s noted in a previous article, the applied chemist is an individual who draws on experience with petroleum chemistry and process
engineering to solve refinery problems. In the following example, an applied chemist combines oxidation chemistry with analytical methodology and field observations to direct process modifications.
A problem arose when a petroleum company encountered erratic results in color and failures in engine tests for several batches of pre-production (i.e., demonstration) runs of a specialty oil. The engine test failures did not appear to correlate with the color of the product; both off-color and water-white oils would fail. Attempts to isolate and characterize the color bodies at a research lab were unsuccessful. However, a high performance liquid chromatography (HPLC) under development at the lab suggested the presence of hydroperoxides in the oil. Hydroperoxides were confirmed by isolation, FTIR and M techniques. Although hydroperoxides are not colored, they are thermally unstable, leading to discoloration or engine-test failure.
With this information in hand, the production protocol was examined with the process engineers. Because the wax hydroisomerization process was being run in a refinery but on small scale, the protocol called for two steps in the process to be run in a blocked operation. After hydroisomerization, the product oil was accumulated in a heated carbon steel storage tank to prevent wax precipitation. Because the tank was not inerted, it was hypothesized that the 60°C temperature and prolonged exposure to air was sufficient to form hydroperoxides. Because the latter were known to be the types of compounds responsible for color formation and engine test failures, additional review of the sample histories were followed.
Attempts were made to rationalize variations in color and severity of engine test failures with process conditions. Two key factors were found. First, the storage tank was maintained at temperature between runs for different periods of time. Second, the configuration of the storage tank allowed the tank heel to be strenuously agitated at
Partnering in Engineering Excellence May 2005
CONTENTS
Applied Chemistry Puts Specialty Process Back on Track How Thick Does a Nozzle Neck Have to Be On an Existing API-650 Storage Tank? Hot Tap Location and Design Considerations Resonance and Magnification in Piping System Vibration
he simple answer to the question posed in the title is “As thick as it needs to be.”
A relative of this question is “Do I need to add a reinforcing pad to a storage tank nozzle that doesn’t have one now? Here again, the answer is simple - “Only if it needs one.”
While those answers sound rather “flippant,” they are both absolutely correct.
Since API-653 was first issued, companies had to take inspection and maintenance of their existing aboveground atmospheric storage tanks more seriously than perhaps they had been doing before. With increased inspection activity comes the inevitable need to evaluate what the inspectors find. It is not uncommon to find cases where existing nozzle neck thicknesses do not meet current API-650 requirements - not because they corroded, they were thinner from the beginning. It is also not uncommon to see a nozzle over NPS 2 (50 mm) that does not have the reinforcing pad that API-650 would currently require. Such situations are more likely to come up with relatively “old” tanks for a variety of reasons. What do you do in these cases?
In their desire to meet current industry practices, be conservative, and “safe,” some folks might decide to add reinforcing pads where there are none now, and to replace the “thin” nozzles with new ones that meet the current API-650 thickness requirements. But, do you have to? Not necessarily.
API-653 does not require us to upgrade existing storage tanks to meet current API-650 requirements. API-653 “only” requires that an evaluation be made to determine if the existing installation is acceptable. In fact for “old” tanks (i.e., those erected before 1980), it is generally preferable to avoid welding to them if at all possible in order to minimize the brittle fracture risk. Don’t misunderstand me - welded repairs and alterations can certainly be safely made to old tanks if appropriate procedures are followed to minimize the brittle fracture risk. It’s just preferable to avoid doing it if possible.
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How Thick Does a Nozzle Neck Have to Be On an Existing API-650 Storage Tank?
By Vincent A. Carucci
So, how do you deal with the cases of “thin” nozzles or no reinforcing pads? I’ve generally used the following approach:
• API-653 does not have any explicit minimum thickness requirements for nozzles. Simplistically, it basically just says “evaluate them for suitability.” So, the engineer must decide if what is there is acceptable.
• I have used 0.1 in. nozzle neck thickness as an absolute minimum value, unless calculations indicate that a thicker nozzle neck is needed. My rationale is that API-653 says that 0.1 in. minimum thickness is acceptable for the shell unless calculations say it needs to be more. Therefore, it is certainly acceptable to use the same approach for the nozzles.
• Common cases where you might have to address the nozzle neck thickness question are:
– If the nozzle was originally installed thinner than current API-650 requirements,
– There is no reinforcing pad at the nozzle (and the nozzle is over NPS 2 where current API-650 says you need a reinforcing pad), and/or
– If there has been severe local corrosion in the nozzle neck or the shell near the nozzle.
In each of these cases, you must “evaluate” whether things are acceptable as they are or not.
• For the evaluation, I generally first do an “area replacement” calculation that API-650 permits (Para. 3.7.2.2). If that works out, you then just have to consider whether the piping system design has enough flexibility in it so that the loads on the nozzle are not excessive. Each case must be looked at individually to decide how far you need to go in evaluating piping system loads and resulting stresses in the nozzle and shell. The worst-case scenario would require flexibility analyses and then local nozzle/shell
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Applied Chemistry Puts Specialty Process Back on Track Continued from Page 1
higher temperatures than realized. (The control thermocouple was positioned 3 feet above the tank bottom, the heel liquid level was only 18 inches deep, and the tank agitated with a 36 inch diameter stirrer mounted on the side of the tank. Thus, during the periods between runs, full heat was applied to the tank with a half-submerged propeller while beating air into the heel of the previous run.)
With this knowledge, the tank was cleaned, a nitrogen inerting system was installed, and a new demonstration run was commissioned. In addition, a local lab was trained with a method for monitoring for hydroperoxides. The first several samples of intermediate product were caught as it flowed into the tank; these samples were free of hydroperoxides. The following day, hydroperoxides were found but at levels that decreased over time. Rapid consultation with the engineering group revealed that these samples were being taken with a sampling loop that had not been cleaned. The run was aborted, the tank and lines cleaned, and a run completed with a product that met color and engine test specifications.
stress calculations to demonstrate that it
either is or is not acceptable. • Of course the cost and time to take a detailed
analytical approach must be weighed against the cost and time to just replace the nozzle and reinforcing pad with ones that meet current API-650 requirements. I have found that in most cases, local corrosion has not been so severe as to warrant going beyond the “area replacement” calculations to decide on an appropriate course of action.
Again, keep in mind that API-653 does not require that we upgrade tank nozzles to current API-650 requirements with respect to thickness and reinforcing pads. We just have to decide if they are acceptable the way they are or not. Of course, if you decide that changes are needed (e.g., adding a new nozzle, adding a reinforcing pad, etc.), then they must meet current API-650 requirements.
3 THE REPORT
How Thick Does a Nozzle Neck Have to be on an Existing API-650 Storage Tank? Continued from Page 2
n earlier article introduced what a hot tap is, when it should not be done, and when it may
be done with special precautions. This article discusses hot tap location and design considerations.
Selecting the Hot Tap Site
The hot tap site should be chosen considering both mechanical reliability and personnel safety. It is normally possible to adjust the exact position of the hot tap as needed to avoid potential problem areas in the pipe being tapped. Consider the following items:
• Safe personnel access, egress, and working conditions.
• Clearance required for the hot tap nozzle, valve, and machine. Also remember that the required clearance increases with pipe diameter.
• Thermal displacement effects. Remember that the hot tap is being done with the pipe (or equipment) in service. Therefore, consider the direction and amount of thermal movement when the system shuts down.
• Drainage of liquid from the lines. • Hot tap angle. The hot tap should ideally be
perpendicular to the pipe and on the top. • Distance between the hot tap and any flange,
threaded connection, or welded seam (including the longitudinal seam of welded piping). Hot tapping too close to such joints could increase the possibility of leakage.
• Rotating equipment or control valves located downstream of the hot tap location. Cuttings from the hot tap operation will go into the pipe and could damage downstream equipment. The hot tap coupon could even be lost and proceed into the flow stream.
• Pipe surface cleanliness, soundness, and curvature. Surface roughness or excessive pipe out-of-roundness could affect nozzle and hot tap machine installation.
Hot Tap Location and Design Considerations
By Vincent A. Carucci
Hot Tap Design Considerations
The hot tap design must meet the applicable Code, local engineering practices, and local governmental requirements. The following highlights several design considerations.
• Inspect the area to be hot tapped before starting the design to confirm the material of construction, wall thickness, and freedom from laminations.
• Ensure that there is adequate flow through the pipe during the hot tap welding and cutting operations. Both minimum and maximum permitted flow rates must be established, and these depend on whether the fluid is a gas or liquid. A minimum flow is needed to help dissipate the welding heat. Maximum flow limits must also be observed in order not to quench the weld and to not “spin” the coupon (which could cause it to disengage from the cutter).
• Most non-air hardenable materials that are normally fabricated by welding can be hot tapped provided the correct conditions of temperature and pressure exist.
• Nozzle and reinforcement materials should be the same nominal chemistry and strength as the pipe or equipment being hot tapped.
• PWHT is normally not possible during hot tapping. However, specific cases may be evaluated to determine if the pressure can be reduced enough to permit online PWHT, or if special welding procedures may be used instead of PWHT.
• All new valve and piping components should be in accordance with the local Piping Material Specifications applicable for the piping system.
• Lined piping or equipment. If a hot tap is made into lined pipe or equipment, the immediate vicinity of the hot tap will become unprotected. This might be tolerable for short periods of operation in particular circumstances.
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Continued on Page 5
A
THE REPORT
• Hot taps into stainless steel lines or equipment typically require using special cutters and procedures.
• A maximum metal temperature [typically about 700°F (370°C)] must be set considering the design temperature of the hot tap machine and personnel protection requirements.
• The minimum acceptable temperature while performing a hot tap is governed by the material to be welded, the hot tap equipment, and welding conditions. Temperatures below the dew point can cause welding problems due to the formation of moisture or frost on the metal surfaces.
• The wall thickness of the header pipe or equipment must be confirmed to be acceptable. This must consider the design conditions, potential burning through the wall when welding, and pressure test of the nozzle assembly before cutting (which imposes an external pressure on the pipe).
• Weld details and procedures must be specified and be qualified for the specific installation.
• Test pressure. Per API RP-2201, a hydrostatic test should be done at a test pressure that is at least equal to the operating pressure of the line or vessel to be tapped. Local code requirements and the possibility of local buckling of the pipe wall must also be considered. Calculations may be required to ensure that buckling does not occur.
• Hot tap fitting. This may be a welded-on pipe stub, an integrally reinforced set-on type connection, or a prefabricated hot tap fitting. A bolted fitting may also be considered in special cases (e.g., when welding cannot be done with the system in operation).
• Hot tap valve. This must have a full-round opening that is at least 1/8 in. (3 mm) larger than the specified drill or cutter OD. A regular, API-600 gate valve may be used. Special hot tap valves (commonly called “sandwich valves”) are available. Their face-to-face dimension is smaller than conventional gate valves, and may be required if the hot tap is done in a confined location.
• Orientation. Hot tap connections should be oriented at a 90° angle to the pipe, in the vertically up direction, and be from the top of the pipe. This reduces the probability of valve
seat damage due to chips from the cutting operation entering the valve. Any variations from this position must be carefully evaluated.
• Size-on-size connections. Size-on-size connections should be avoided. Additional design and procedural items (e.g., full encirclement reinforcement) must be considered when a size-on-size connection must be used.
• Piping system stresses. Design the connections to prevent overstressing the pipe being tapped due to the weight of the hot tap machine, application of test pressure to the hot tap nozzle, or thermal displacement of the added piping. Also consider the pipe flexibility stresses for the case when the system is shut down. Remember, the new line is initially at ambient temperature when it is added to a system that is in operation.
• Supports. Use adequate bracing and support to minimize vibration or impact on the line during cutting.
Hot Tap Location and Design Considerations Continued from Page 4
5 THE REPORT
rom a practical standpoint, the most important problem with forced vibration in a piping system
is resonance. Resonance occurs when the vibration forcing frequency is at or very close to an acoustical or mechanical natural frequency of the system. Since most structures and piping systems have very little damping, the vibration amplitude becomes very high if resonance occurs.
If resonance occurs, it will usually be at the fundamental (i.e., first) or one of the other lower order natural frequencies. Two types of resonance must be considered: mechanical and acoustical.
Mechanical Resonance
Real systems have some damping which eventually reduces the vibration amplitude. Damping also helps determine the peak system response to an exciting force at a given frequency. This peak amplitude can be approximated by using the magnification factor (MF). The MF is the ratio of the dynamic deflection to the static deflection that would occur in the system if the forces were statically applied. The MF is a function of the forcing frequency, mechanical natural frequency, and the viscous damping coefficient (see Figure 1).
When the damping is low, the MF will be high at the natural frequency. The MF will typically be in the range of 10 to 25 at resonance.
Acoustical Resonance
Acoustical resonance in a piping system occurs when reflected pressure pulses from a piping discontinuity (e.g., closed valve, tee, elbow) travel back to and arrive at their source in time to join in phase with the next pulse. The resultant larger pressure pulse travels down the pipe, is reflected back again, increases in size again, and so on. The final amplitude of this reinforcement process is limited by the dynamic friction forces in the piping system.
In acoustic resonance, the system responds with large amplitude pressure surges when it is excited by relatively small amplitude pressure fluctuations that occur near an acoustical natural frequency.
Resonance and Magnification in Piping System Vibration
By Vincent A. Carucci
This is analogous to the large amplitude deflections that are caused by a mechanical resonance. As with mechanical resonance, the fundamental acoustic natural frequency is typically the easiest to excite.
The MF in the case of acoustic resonance represents the amplitude of pressure response at some point in the acoustic system to the amplitude of pressure excitation. The qualification “at some point” is important since there are locations in an acoustic system (i.e., nodes) where the pulsations are relatively small even at resonance. However, there is high pressure magnification at other points. Since acoustic damping from viscous drag forces and heat conduction is small, the MF for an acoustic resonance can be very high, ranging from 10 to 40.
Pipe Failure Considerations
Eliminating or isolating vibration sources is the ideal solution to a vibration problem. However, it is often impossible to do this in a cost-effective manner. Therefore, most process plant piping systems vibrate to some extent. Acceptable vibration limits must be established to determine if a particular vibrating pipe is a potential problem that must be resolved, or whether it can be left alone.
Fatigue Stress Considerations
Steady-state piping vibrations are usually evaluated with respect to their effect on the fatigue life of the piping. The allowable stress values must be determined from fatigue curves due to the large number of cycles encountered in steady-state vibration. The number of cycles to failure is a function of the mean stress, alternating stress, material, environment, and the geometry of the piping component.
Transient Vibration Considerations
Transient vibrations are generally evaluated considering excessive surge pressures, pipe deflections, or reaction loads. Fatigue is a less important concern in this case because of the low number of dynamic transient events expected.
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6 THE REPORT
However, fatigue must be considered if the number of cycles becomes significant.
The primary concern with transient vibrations is the possibility of unacceptable overpressures within the piping and connected equipment due to the dynamic surge pressures that are typical of water-hammer events. Peak dynamic surge pressures are additive to the static operating pressure. The total pressure can then exceed the specified design pressure for the system. Significant overpressure due to hydraulic surge may cause catastrophic failure of the piping system, as well as the possibility of flange leakage.
Resonance and Magnification in Piping System Vibration Continued from Page 6
ζ = 0
ζ = 1 /8
ζ = 3 /4
ζ = 1 /2
0 .0
1 .0
2 .0
3 .0
4 .0
5 .0
6 .0
8 .0
1 0 .0
1 .00 .0 2 .0
ff n
Mag
nifi
cati
on F
acto
r (M
F)
= E x c ita
= N a tu r
= M a g n i= V isc o u (o r D a
f
f n
M Fζ
W H E R E :
ζ = 1 /3
Other types of damage that can occur include the failure of pipe supports, restraints, or small diameter branch connections, as well as the overloading of attached equipment. Therefore, designing a piping system for these latter effects is based primarily on controlling pipe movements, and assuring that the support system and equipment can absorb the transient reactions.
7
Figure 1 Magnification Factor For Mechanical Resonance
Where: f = Excitation
Frequency, Hz fn = Natural
Frequency, Hz MF = Magnification
Factor ζ = Viscous Damping
Coefficient (or Damping Ratio)
THE REPORT
HIGHLIGHTS
8
Conducted Noise Survey at a Chemical Plant to quantify major noise sources and propagations paths.
Provided specialized soil remediation services at a Northeastern refinery.
Supported proprietary assessment of commercial FCC Flue Gas Scrubbing technology.
On behalf of third party, performed independent assessment of packaged H2 plants/PSA facilities.
Carried out independent review of a Hydrocracking unit operation resulting in reliability improvement recommendations.
Participated in P&ID and HAZOP reviews for several processes being implemented at a European refinery.
Providing extensive process design services to a major technology developer/licensor.
Led a Reliability and Maintenance Audit at a European refinery.
Providing continuous support of a major Middle Eastern LNG project via engineering services at the contractor and the sub-contractor’s offices in Europe and the Far East.
Continue to supply specialized, high-value added services to several novel process developments pursued by major technology companies.
Presented training courses covering piping system design and maintenance, aboveground storage tank design and maintenance, and pressure vessel design and maintenance.
Provided continuing mechanical engineering support for a major international oil company.
Conducted onsite audit of critical piping systems installed at a power plant.
Provided aboveground storage tank bottom repair and replacement recommendations at multiple locations.
Provided mechanical engineering support as part of a HAZOP resolution team.
Prepared repair recommendations for cracked tubesheet weld in a fertilizer plant waste heat boiler.
Corrosion audit performed at a major European refinery. Followup program and more extensive survey recommended which may lead to adjustments to inspection plans and operating practices.
