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Stress Analysis of Pump Piping (Centrifugal) System using Caesar II Every process piping industry uses several pumps in each process unit. Sometimes the analysis is very critical. In this article I will try to elaborate the method followed for stress analysis of a centrifugal pump piping system.  The stress system consists of typical discharge lines of two centrifugal pump (Pump A and Pump B). Fluid from this two pumps are pumped into a heat exchanger. As per P&ID only one pump will operate at a time, other pump will be a stand by pump. I will explain the stress analysis methodology in three parts:- a) Modeling of Pump b) Preparation of analysis Load cases  and c) Analysing the output results.

                                           Fig. 1: Sample pump piping model as it looks in Caesar II

A. Modeling of Pump: For modeling the pump we require vendor general arrangement drawing or outline drawing. All rotary equipments are modeled as a weightless rigid body in Caesar II. From the outline drawing we need to take the dimensions till some fixed point. Let us take the example of the outline drawing shown in figure 2.

                                    Fig. 2: Sample outline drawing for a centrifugal pump From the above drawing we can get the dimensions for elements 10-5000 as 8.5 inch and element 5000-5020 as 6.19 inch. At node 5020 we will provide fixed anchor. During modeling of the above elements we need to use line size and thickness as diameter and thickness of the equipment. Line temperature and pressures as equipment properties. We have to provide anchor (with cnode) at node 10 for checking nozzle loads which we will compare with the allowable value as provided in Fig. 3 below:

                      Fig. 3: Allowable

nozzle load values as mentioned in Equipment GA drawing

In absence of allowable load value the Pump design code (API 610 for API pumps, ANSI HI 9.6.2 for non API pumps) can be followed for the same. After the pump is modeled as rigid body the piping modeling need to be done from pump-piping interconnection flanges. B. Preparation of Analysis Load Cases: Along with normal load cases two additional load cases need to be prepared. Normally in refinery and petrochemical industry one pump operates and other acts as a stand by pump. So we have prepare load cases as follows: 1. Hydrostatic case (WW+HP HYD) 2. Operating case with both pump operating (W+T1+P1 OPE)

3. Operating case with total system in maximum design temperature (W+T2+P1 OPE) 4. Operating case with pump A operating and pump B Stand by (W+T3+P1   OPE)  5. Operating case with pump B operating and pump A Stand by (W+T4+P1 OPE) 6. Operating case with total system in minimum design temperature (W+T5+P1    OPE) Next all normal load cases like static seismic, static wind, etc are to be built as per stress analysis or flexibility specification. When pump A is in operating condition and pump B stand by then normal pipe operating temperature has to be inserted till Tee connection for pump A and ambient temperature will be the input input for pump B as shown in Fig. 4.  Similarly reverse the input when pump B is operating.

                      Fig. 4: Operating-Stand By Temperature profile for two pump system After equipment is modeled completely start  modeling the piping following dimensions from piping isometric drawings. Try to make a closed system. Normally pump lines are connected to some vessel, tank or heat exchangers. So it will create a close system. Then run the analysis to check stresses, displacements and loads. C. Analysing the output Result: Once Caesar completes its iteration process we can see the output results in output window. At nozzles (the nodes which we anchored with a cnode) we can check the force values. These values we have to compare with the allowable values. If the actual values are less than the allowable values then the nozzle is safe. Otherwise we have the make changes in supporting or routing to bring the nozzle load values within allowables. A sample output restraint is provided in Fig. 5 for your reference.

                                              Fig 5. Typical output results for two pump system As can be seen from the above figure that we are checking nozzle loads in load case 2, 4, 5 and 6. For rotary equipments normally nozzle qualification in design or upset temperature is not required. Special Consideration for Rotary Equipments: Now we have to make one separate caesar file and we have to check sustained displacement at nozzle at WNC (weight no content) case. This checking will ensure proper alignment of piping flange and equipment nozzle flange. For detailed analysis steps follow this link: http://www.whatispiping.com/alignment-check-methodology Always remember to provide first piping support from pump nozzle as an adjustable support (or a spring support) to aid in alignment. In case of 3 pump system, normally two pumps will be operating and one pump will be stand by. So input and prepare load cases accordingly.

Alignment Check Methodology in Piping Stress Analysis using Caesar II “Alignment Checking” this term is quite familiar with piping engineers and all construction engineers. During piping installation at construction site it is expected that equipment flange should match perfectly (aligned) with the piping flange so that during bolting no problem occurs. But achieving that perfect alignment is very difficult to achieve. If this alignment for rotary equipments are not proper then there may be several problems in future during operation which may lead to vibration of equipment/piping system or in some situation equipment failure. American Petroleum Institute code API RP 686 provides the data for acceptable deviation from the ideal perfect alignment. As per the code if the vertical and horizontal deviation of piping flange and rotary equipment flange center line is within 1.5 mm and parallelism (rotation) is within 0.0573 degree then the alignment is accepted otherwise means to be devised to bring the deviation within those values. While performing stress analysis of rotary equipment connected piping systems in Caesar II we can very easily ensure this limitation. The following write up will describe the step by step method of doing the same.

Alignment check of nozzle flange shall be performed for all Rotating Equipments like Centrifugal Compressor, Steam Turbine, Centrifugal Pumps, Gear Pumps etc as per following procedure. Steps for performing Alignment checking:  Ensure correct weight of the pipe (with proper thickness), Support weight (dummy pipe), Weight of valves, flanges and any in-line items.   

Consider Insulation density carefully (equivalent insulation density to be correctly fed with insulation & cladding weight, Check insulation on dummies for cold insulated lines). Model all branch piping (like drip legs etc.) greater than 2 inches. Discuss with piping lead engineer for requirement of any maintenance flanges (Normally for steam turbine or centrifugal connected lines the maintenance flange is recommended) and include it if required.

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Minimize the sustained load on equipment nozzle as much as possible during static analysis run of the Caesar model.

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Normal industry practice is to analyse the Alignment checking in separate file. So rename the static file as Filename_Alignment.C2

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Make the equipment nozzle anchor flexible or remove the displacement if anchor was not modeled.

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Wherever spring support is used, define spring rate and cold load in case of variable effort spring & Constant effort support load in case of constant effort spring. After performing the above create one additional load case in Caesar II as mentioned below:

                          WNC+H                                    SUS             System with spring hanger                           WNC                                           SUS             System without spring hanger 

Set the spring hanger as “As designed”.(Two load cases can be generated for spring As designed and rigid condition)



Now run the analysis and check the displacements of the nozzle at the above mentioned load case and limit them within below mentioned values:

        Vertical deflection (Normally DY):                                               +/- 1.5 mm         Horizontal displacement (sqrt sum of DX and DZ):                     +/- 1.5 mm          Parallelism (sqrt sum of RX and RZ) :                                          0.0573 degree. 

In case the above limitations are not met then re-analyse by readjusting the spring and other supports and do the simulation.

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Alignment check is to be performed for both inlet and outlet lines.

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Alignment check must be performed with spring under both in “As designed” and in “locked” condition.

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To avoid small misalignment in vertical direction first support from rotary equipment nozzle is used either a spring support or an adjustable type support.

Flange Leakage Evaluation based on NC 3658.3 Method method using Caesar I

This is the last post on the topic Flange Leakage Evaluation using Caesar II. I had already published 3 more posts on flange leakage checking. Click here to visit those. In this section I will describe the methods of flange leakage evaluation by NC 3658.3 method using Caesar II. Applicability:  NC 3658.3 Method for flange leakage evaluation can only be applied if the following two conditions are met: 1.

Flanges, bolts and Gaskets used are designed based on as specified in ASME B 16.5a and

2.

Boting material must have a allowable stress value at 100°F(38°C) >=20000 psi (138 MPa) (High Strength Bolting)

Governing Equation:  By NC 3658.3 method the generated external moment (Mfs) is limited to a value as provided by the below mentioned equation: Mfs104) with relatively low stress levels and the deformation is in elastic range. 

This type of fatigue failure used in the design of rotating machinery.

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This type of fatigue results from strain cycles in the elastic range.

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A stress level, endurance limit, may be applied an infinite times without failure, is calculated.

Failure Criteria: While preparing fatigue curves, the strains obtained in the tests are multiplied by one-half of the elastic modulus to obtain pseudo stress amplitude. This pseudo stress is directly compared with the stresses calculated on the assumption of elastic behavior of

piping. During piping stress analysis, a stress called the alternating stress (Salt) is used which is defined as one-half of the calculated peak stress. Fatigue failure can be prevented by ensuring that the number of load cycles (N) associated with a specific alternating stress is less than the number allowed in the S–N curve or endurance curve. But in practical service conditions a piping system is subjected to alternating stresses of different magnitudes. These changes in magnitudes make the direct use of the fatigue curves inapplicable since the curves are based on constant-stress amplitude. Fatigue tests of metallic materials and structures have provided the following main clues to the basic nature of fatigue:  Fatigue failure, or cracking under repeated stress much lower than the ultimate tensile strength, is shown in most metals and alloys that exhibit some ductility in static tests. The magnitude of the applied alternating stress range is the controlling fatigue life parameter. 

Failure depends upon the number of repetitions of a given range of stress rather than the total time under load. The speed of loading is a factor of secondary importance, except at elevated temperatures.

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Some metals, including ferrous alloys, have a safe range of stress. Below this stress, called the “endurance limit or fatigue limit”, failure does not occur irrespective of the number of stress cycles.

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Notches, grooves, or other discontinuities of section greatly decrease the stress amplitude that can be sustained for a given number of cycles.

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The range of stress necessary to produce failure in a fixed number of cycles usually decrease as the mean tension stress of the loading cycle is increased.

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Examination of fatigue fracture shows evidence of microscopic deformation, ever in the apparently brittle region of origin and propagates of the crack. The plastic deformation that accompanies a spreading fatigue crack is usually limited in extent to regions very near the crack.

Therefore, to make fatigue curves applicable for piping, some alternate approach is necessary. One hypothesis asserts that the damage fraction of any stress level S, is linearly proportional to the Ratio of the number of cycles of operation at the stress level to the total number of cycles that would produce failure at that stress level. This means that failure is predicted to occur if U≥1.0 where U= Usage factor = ∑(ni/Ni) for all stress levels Where, ni= number of cycles operating at stress level i Ni= number of cycles to failure at stress level i as per material fatigue curve. Analysis Requirement: If there are two or more types of stress cycles which produce significant stresses, their cumulative effect shall be evaluated as stipulated in Steps 1 through 6 below: 1. Designate the specified number of times each type of stress cycle of types 1,2,3,…,n, will be Repeated during the life of the component as n1, n2, n3,……., nn, respectively. In determining n1, n2, n3,……., nn, consideration shall be given to the superposition of cycles of various origins which produce the greatest total alternating stress range.  For example , if one type of stress cycle produce 1000 cycles of a stress variation from zero to +60,000 psi and another type of stress cycle produces 10,000 cycles of a stress variation from zero to -50,000 psi, the two cycles to be considered are shown below: 

cycle type 1: n1=1000 and Salt1= (60000+50000)/2

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cycle type 2: n2=9000 and Salt2= (0+50000)/2

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For each type of stress cycle, determine the alternating stress intensity Salt, which for our application is one half of the range between the expansion stress cycles (as shown above). These alternating stress intensities are designated as Salt1, Salt2, Saltn.

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On the applicable design fatigue curve find the permissible number of cycles for each Salt computed. These are designated as N1, N2, …….Nn.

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For each stress cycle calculate the usage factor U1, U2, …….Un where U1= n1/N1, U2= n2/N2,……..Un=nn/Nn.

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Calculate the cumulative usage factor U as U=U1+U2+…….+Un.

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The cumulative usage factor shall not exceed 1.0

Case Study for Fatigue Analysis in Caesar II for a typical piping system I  have taken up this topic to explain the fatigue analysis (Click here to read the basic article on Fatigue Analysis) methodology using caesar II with an example problem of a typical piping system. To perform fatigue analysis we need to calculate the thermal and pressure fluctuations the piping system will undergo in its design life. We have to calculate the worst possible cycles from preliminary data provided by process/operation department. Lets assume we received the following data from process for a typical piping system.  Operating cycle from ambient (40°C) to 425°C (400,000 cycles anticipated) 

Shutdown external temperature variation from ambient (40°C) to -20°C (300,000 cycles anticipated)

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Pressurization to 5.5 Bars (400,000 cycles anticipated)

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Pressure fluctuations of plus/minus 1.5 Bars from the 5.5 Bars (1,000,000 cycles anticipated)

Now, in order to do a proper fatigue analysis, these should be grouped in sets of load pairs which represent the worst-case combination of stress ranges between extreme states which we can do in the following way (Refer Attached Figure, Fig.1 for proper understanding):

Fig. 1: Explanation of worst case cycle combination for fatigue analysis 

From -20°C, 0 Bars to 425°C, 7 Bars.  300,000 Cycles



From 40°C, 0 Bars to 425°C, 7 Bars.:  100,000 Cycles

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From 425°C, 4 Bars to 425°C, 7 Bars: 600,000 Cycles

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From 425°C, 4 Bars to 425°C, 5.5 Bars: 400,000 Cycles

So in Caesar II we can define the above data as follows (Refer Fig. 2): T1= 425°C; T2= -20°C P1= 5.5 Bar; P2= 4 Bar  and P3= 7 Bar

Fig.2: Caesar II spreadsheet explaining the input requirement Now go to the load case editor and define load cases as shown in Fig.3 for fatigue analysis. Click on load cycles button to input the number of cycles calculated above.

Fig.3: Load cases for Fatigue Analysis Don’t forget that all load cases with stress type FAT (for fatigue) must have their expected number of Load Cycles specified. After load cases are prepared run the analysis and find out the results from output processor. Part of the output results are provided in the below attached figures for your reference (Fig. 4 and Fig. 5) The fatigue stress range (Maximum Stress Intensity as calculated in Expansion stress case) may be checked against the fatigue curve allowable for each fatigue load case as shown in Fig 4.

Fig 4: Output Screen showing stress range However, this is not a true evaluation of the situation, because it is not a case of “either-or.” The piping system is subjected to all of these load cases throughout its expected design life, not just one of them. Therefore, we must review the Cumulative Usage report, which shows the total effect of all fatigue load cases (or any combination selected by the user) on the design life of the system. Refer Fig 5 for example.

Fig. 5: Output Screen showing Cumulative usage factor This report lists for each load case the expected number of cycles, the allowable number of cycles (based upon the calculated stress), and the Usage Ratio (actual cycles divided by allowable cycles). The Usage Ratios are then summed for all selected load cases; if this sum exceeds 1.0, the system has exceeded its fatigue capabilities.

Introduction: Flare system is a means of safe disposal of waste gases by burning them under controlled conditions. Flare piping generally comprises of PSVs outlet piping, sub header piping & main header piping. Design conditions considered for stress analysis are as per P&IDs, line list and specific information related to flare if any by process. A typical flare system consists of:  PSV outlet pipes, sub header connected to main flare header , main flare header connected to knock out drum , outlet of flare knock out drum to flare stack. 

A knockout drum to remove and store condensable and entrained liquids.



A single or multiple burner units and a flare stack.

The major thrust points which a stress engineer should consider carefully are listed below:  Fluid Density: Fluid density has to be taken from list (Process Department). In absence of data, 1/3rd water filled weight can be assumed for Caesar input.  Test Method: Flare lines are normally pneumatic tested. So, hydrotest weight is not required to be considered. However in specific cases water filled weight has to be considered (Check with Process department).  Supporting: Flare lines are normally provided with slopes as per Project specification. So general practice is to support with Shoe/saddle supports.  Supporting span to be maintained such than sustained sagging should not exceed 3-5 mm. Structure below pipe support / shoe height is to be planned to meet piping sloping/free draining requirement.

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SIF: Normal industry practice is to take 45 degree/90 degree branch connections from Flare Header: Proper SIF (both inplane and outplane) should be incorporated at branch connections while entering data into Caesar II. SIF s can be calculated using Fe-SIF, Nozzle Pro, or some other type of FEA software. Sometimes reinforcement may be required to reduce SIF value. Temperature Gradient: In a flare system sometimes temperature gradient or profile may exist when the hot contents flow into the subheader / main header which is at a lower temperature (confirmation with process if required). Flexibility: Piping shall be evaluated for flexibility. If necessary expansion loops shall be provided. Expansion joints to be avoided. Flare piping loops are planned in horizontal plane (4D bends) in order to ensure pipe slope/free draining requirement. However no of loops should be minimized as much as possible.  Flare line routing and supporting to be planned in such a way that forces and moments on flare knock out drum nozzle connections are minimized. Sometimes Flare line may consist of two phase flow. So Vibration/Acoustic analysis is required to be performed and supporting to be strengthened.

HAZOP (Hazard and Operability) Study: A brief introduction Full form of HAZOP is Hazard and Operability Study. This is a comprehensive multi-disciplinary team exercise to critically review (Study) the piping design (Layout/ Routing/Placement of branches/inline instrumentation items/ equipments etc.) with respect to Hazardous and Operational considerations and requirements. A Hazard and Operability (HAZOP) study is a structured and systematic examination of a planned or existing process or operation in order to identify and evaluate problems that may represent risks to personnel or equipment, or prevent efficient operation. The HAZOP technique was initially developed to analyse chemical process systems, but has later been extended to other types of systems and also to complex operations and to software systems. A HAZOP is a qualitative technique based on guide-words and is carried out by a multi-disciplinary team (HAZOP team) during a set of meetings. HAZOP is now a mandatory activity. It is a qualitative, experience intensive exercise as of now. It is in the form of deviation analysis. After the process design, the steady state specifications of each stream in the flow sheet are known. The HAZOP team exhaustively asks itself questions as to what will happen if this specification deviated on the positive or negative side of the expected steady state value. It debates the possible causes and consequences of each such eventuality. Anything which appears to them as likely to lead to hazardous situations is debated further and possible means of avoiding the same or raising alarm if it happens so that remedial action can be taken etc. are recommended. This may lead to recommendation of additional instrumentation on lines and equipment, Hi-Lo alarms and trips etc. may be required to be provided. The idea of HAZOP is to foresee hazardous situation and take measures and abundant precaution to avoid them and increase process safety. This is a structured analysis, conducted after the design review, to ensure the design is suitable for all the intended operating conditions and complies with the HSE requirements. This process is also to ensure that the fundamentals of the design are thoroughly explained, understood, and examined. Advantage: The benefit of the HAZOP is that early identification and assessment of the critical hazards provides essential input to project development decisions.  This leads to a safer and more cost effective design with a minimum cost of change penalty. Key Documents required:  PFD / PFS’s (Process Flow Diagram/ Process Flow Schemes) 

P&ID / PEFS’s (Piping & Instrument Diagrams/ Process Engineering Flow Schemes)

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Basis of Design

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Operating, Control and safeguarding philosophy

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Plot plans & Hazardous area classification drawings

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Cause & Effect diagrams

Team Composition:  Chairman (independent) 

Lead engineers from Process, Instrumentation & Control (both from Design team and Client/ End user)

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Operations engineer (from Client/ End user)

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Lead engineers from Mechanical/Piping, Pipeline, HSE and Electrical as required. (Both from Design team and Client/ End user)

Timing:

The HAZOP study should preferably be carried out as early in the design phase as possible – to have influence on the design. On the other hand; to carry out a HAZOP we need a rather complete design. As a compromise, the HAZOP is usually carried out as a final check when the detailed design has been completed. A HAZOP study may also be conducted on an existing facility to identify modifications that should be implemented to reduce risk and operability problems. Typically HAZOP in EPC design companies are performed 3 to 4 weeks after the Design review meeting, once the design review points are incorporated in the key documents.

Cleaning Requirements of Piping Systems: An article New construction of piping systems requires some type of cleaning of debris or contaminants. Debris can be defined as substances such as dirt, grease, construction materials such as wood, wire, hard hats, tools, weld slag, rust and scale, and any other small objects that could be misplaced inside the diameter of piping systems. Proper cleaning is required dependent upon service requirements. 

All piping systems shall be flushed with water. Water flush is accomplished through hydro-testing of piping systems. If water being drained still has evidence of debris, continue to flush with water until no evidence of debris exists.

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Lines that require cleaning should be identified on the Mechanical Flow Diagrams. The Process Engineering Group (Process Department) shall set the limits based on the service requirements and equipment being protected from debris and contaminants generated during construction.

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Certain process services require chemical cleaning. The process engineer shall be responsible for identifying services that require chemical cleaning. Typical examples of services requiring chemical cleaning are listed below:

1.

Reciprocating Compressor suction piping

2.

Super High Pressure Boiler Feed Water and High Pressure Steam

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Product Shipping Lines

1.

Specialty Chemical /Catalyst lines

2.

Oxygen

3.

Hydrogen Peroxide

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The designer should be responsible for verifying all steps to remove debris that would be detrimental to the process fluid, including the provision of any temporary facilities for carrying out the chemical cleaning procedures.

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The cleaning method used should be selected based upon the facilities available. Steam and detergent cleaning is much less costly than acid or mechanical cleaning. Each project specification must indicate the type of contamination/debris to be removed.

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All systems shall be sealed after cleaning to keep out dirt and moisture. Cleaning in place with chemical cleaning solutions shall be compatible with all components of the piping system; otherwise, components that would be adversely affected by the cleaning solution shall be temporarily removed.

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Use and disposal of cleaning solutions must be in accordance with plant policy or local regulations (or both).

Types of Pipe Contamination for Stainless Steel:  Dirt 

Iron contamination

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Grease and loose weld spatter

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Scale and tight weld spatter

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Oil, paint, or grease

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Rust

Types of Pipe Contamination for Carbon Steel:  Dirt 

Varnish or protective oil

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Mill scale

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Shop weld spatter and scale

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Rust

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Moisture (low-temp service)

Various cleaning types:  Mechanical Cleaning: Rotating shafts, brushes, compressed air, and flying grit are hazards. Use protective equipment dictated by site.  Chemical Cleaning: Acids and other chemicals, heated solutions, steam pressure hoses, spills, and sprays are hazards. Provide protective clothing, eye protection, safety showers, and facilities to neutralize spills of spent chemicals. Personnel should not breathe ferroxyl solution

(or other chemical) vapours that may be harmful. Adequate respiration must be provided when testing or cleaning in enclosed areas with inadequate ventilation.  Vapour Cleaning: Steam, condensate, and other hazards are associated with chemical cleaning. Controlled discharge of vapours to the atmosphere or condensate cooled by water sprays is essential to minimize personal contact. Cleaning procedures: Procedure for Water Flush:  Flush pipe with chloride-free clean water. 

Thoroughly drain the pipe and dry if required. Drying can be done by wiping or by blowing with clean, dry compressed air or inert gas.

Procedure for Air Blow:  Blow with clean, dry compressed air. Use sufficient volume of air to create high velocity in pipe. Procedure for Steam and Detergent Cleaning:  Steam-clean with a water solution of Pennwalt Corp. Cleaner MC-79, Oakite Products, Inc. Oakite 33, or approved equal. (Mix 1 gal MC-79 with 9 gal clean water; mix 1 gal Oakite 33 with 6 gal clean water.) 

Drain pipe thoroughly and flush with clean water.

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Dry pipe by wiping or by blowing with clean, dry compressed air or inert gas.

Procedure for acid Cleaning for Stainless Steel: The choice of acid cleaning solution depends upon the composition, heat treatment, and form of the stainless steel to be cleaned. Choose the acid cleaning solution as follows: 

For mill products or castings in the solution-annealed condition of Type 300 or 400 series and Carpenter 20 Cb (UNS N08020), Alloy B (UNS N10001), or Alloy C-276 (UNS N10276) material, or to weld-ments, mill products, or castings of CF-8, CF-8M, CF-3, CF-3M, and SW20M (CN-7M): use a nitric-hydrofluoric acid.

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For weldments of Type 304, 316, or any of the other non-extra low carbon (ELC), non-stabilized grades, or for severely sensitized items (such as those that have been stress-relieved) of any of the grades (including ELC and stabilized): use a weak acid.

Procedure for Pickle (Sulfuric Acid method) for Carbon Steel:  Pickle with a solution of one part Metclean No. 1 or equivalent (inhibited sulfuric acid) 3 to 10 parts of clean water. Heat and maintain pick-ling bath between 71 and 82 °C (160 and 180 °F). 

Pump solution through pipe or immerse pipe in a pickling tank until clean.

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Flush with clean water.

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Inspect and repeat steps 2 and 3 if necessary.

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Rinse with a neutralizer solution.

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Dry as required by the process in which the pipe is being used.

Procedure for Pickle (Citric Acid Method) for Carbon Steel:  Pickle in a solution of 3-1/2 gal of water per lb of citric acid (required anhydrous granular citric acid). Heat and maintain pickling solution between 82 and 88 °C (180 and 190 °F). 

Pump the solution through pipe or immerse pipe in a pickling tank until clean.



Flush with clean water.

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Inspect and repeat steps 2 and 3 if necessary.

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Rinse with a neutralizer solution of 5.0 percent soda ash (Na2CO3).

 

Flush with rust inhibitor consisting of 0.5 percent sodium nitrite (NaNO2), 0.25 percent disodium phosphate (Na2HPO4), and 0.25 percent monosodium phosphate (NaH2PO4). Dry as required by the process in which the pipe is being used.

Procedure for Mechanical Cleaning for Stainless Steel:  Blast-clean inside of pipe and fittings with clean, iron-free sand or alundum grit. Repeat if free iron is found. Use ferroxyl test if required. Blast-cleaning of clad material should not be carried to the point of seriously reducing the cladding thickness. 

Walnut-shell blast provides very smooth interior surfaces. Blast inside of pipe and fittings until desired results are obtained.

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For brush cleaning, use stainless steel wire

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Note: Any one, or all, of the mechanical cleaning procedures may be required to effectively clean stainless steel pipe and fittings when weld spatter or scale (or both) have formed from welding.

Procedure for Mechanical Cleaning for Carbon Steel:  Blast clean inside of pipe and fittings. Wire brushing with power rotary wire brushes is an alternate method. A rotary cutter followed by wire brushing should be used on heavily rusted, pitted, and weld-spattered pipe, and on pipe with tightly adhered scale. 

Blow out residues with clean, dry compressed air.

Spring hanger selection and design guidelines for a Piping engineer using Caesar II Introduction: Spring hangers are an integrated part of Piping Industry. The use of spring hangers for supporting pipe weights are welknown to every piping engineer. Whenever some rigid supports are not taking load due to its thermal movement or rigid supports are creating bad effect to equipment connection Piping engineers suggest the use of a spring hanger to share some of the loads and to keep the piping system safe. Selection of the appropriate type of hanger support for any given application is governed by the individual piping configuration and job requirements. There are two types of Spring hangers. a) Variable Spring Hanger- Loads vary throughout its operating range and b) Constant Spring hanger: Load remains constant throughout its operating range. The following write up will provide a simple guideline for selection of both Variable and constant Spring hanger while analysing a piping system using Caesar II. Selection Procedure of Variable Effort Springs:  

 

1.Determine the hot load required and the pipe movement (up or down). 2.Estimate the travel range from the catalogue. 3.Select the smallest spring size which has the hot load within the working travel (mid range). 4.Ensure that the cold load lies within the working range of the spring i.e. between the two dark black lines shown in the selection chart. Calculate the cold load as follows:  Cold Load = Operating Load + Movement x Spring Rate (For pipe movement up)  Cold Load = Operating Load – Movement x Spring Rate (For pipe movement down) 5.If the Cold load lies beyond the working range in the selection chart, then select higher spring size    or the next travel range. 6.    Check the variability in selected spring

Generally for non critical systems, the variability is limited to 25% through out the total travel. For critical systems such as steam connections terminating at turbines and pipes connected to rotating equipment Like compressor etc. variability is limited to 10%.If the variation exceeds the allowed value, choose higher size spring or smaller spring rate at same load range. 7.Select the type and check the feasibility of the spring depending on space available and  type of structure available.

Selection procedure of Constant effort springs:  Constant Effort spring shall be selected where the vertical movement exceeds 50 mm, or where it is necessary to restrict transfer of load to adjacent terminal of equipment or where the Spring variability exceeds 25%.

1.      Determine the load and the total movement.          Total movement = design movement + over travel        Over travel = 20% of the design movement or 25mm whichever is higher.

2.    Select the spring from the load chart keeping in mind that the spring selected must lie within the working range (Between red and black line) 3.    Select the type and check the feasibility of the spring depending on space available and type of structure available. 4.   The Spring box must be able to move freely without any restriction. 5.  Stress Engineer must check the eccentricity (See Fig 1 below) of the spring load flange and the spring base plate while providing foundation information to civil.

Spring Selection procedure in Caesar II: 1.    CAESAR-II Default Setting for Hanger Selection: Before making input for spring selection it is always better to make a default Caesar setting for hanger design.

                                       Fig 2. Caesar II Default hanger setting 2.    CAESAR-II Auxiliary Spreadsheet setting for Hanger Selection During spring selection at a particular node the following auxiliary spreadsheet appears. The setting of this spreadsheet is to be done as illustrated in below diagram.

                                     Fig. 3  Caesar II Auxiliary spreadsheet for hanger selection

NOTE-1: Maximum Allowed Travel Limit: This field is used to specify a limit on the amount of travel a variable support hanger may undergo.  CAESAR will be forced to select a Constant Effort Spring if the movement exceeds the limit in this field, even though a variable effort spring would have fulfilled our purpose. Constant effort hangers can be designed forcefully by inputting a very small number i.e. 0.001 in this field.  NOTE-2: Free Code: Anchor or Restraints from equipment connections which are very near to the hangers are usually freed during the hanger design restrained weight run, so that loads normally going to the equipment nozzle are carried by the hanger. The hanger can be designed to take almost the full weight of the pipe between the anchor and the hanger Using this field enter the node number & the direction in which free code is to be used. Free Codes are:1.Free the anchor or restraint in the Y direction only. 2.Free the anchor or restraint in the Y and X directions only. 3.Free the anchor or restraint in the Y and Z directions only. 4.Free all translational degrees of freedom for the anchor or restraint. (X,Y and Z) 5.Free all translational and rotational degrees of freedom for the anchor or restraint. (X, Y, Z, RX, RY, and RZ).Refer Figure below. The option 5 above usually results in the highest adjacent hanger loads, but should only be used when the horizontal distance between the hanger and the anchor is within about 4 pipe diameters as shown in Fig 4.

                                      Fig. 4  Maximum Spring distance for using Free Code

NOTE-3:  Number of hangers at location: For better stability, the base type spring support of 24″ and larger is used with 2 spring cans. Few important points to keep in mind while Spring selection: For can type springs the spring height should be kept minimum from stability point of view. If spring height is less the moment on spring will reduce and tilting of spring (Fig. 5) can be avoided or significantly minimized. The spring which has lower spring rate will have lower load variation.

While designing the spring hanger the sustained sagging should be minimized within +/-1 mm so that original piping system is not strained much.

                                          Fig. 5 Effect of Spring Height

Heat Tracing of Piping Systems Heat Tracing is a generalized term relating to the application of radiant heat input to piping systems from tubing attached to the outside of the pipe. When Heat tracing is used to ensure that the system functions from a process standpoint regardless of climate conditions it is known as Process Control Tracing Again when Heat tracing is used to prevent freeze up due to climatic conditions only it is known as Winterization Tracing. General Requirements  General  Steam tracing supply lines shall be taken from the top of the supply header to assure dry quality steam.  

Identify the locations for steam tracing supply manifolds and condensate manifolds early in design to reserve space in plant layout. This applies to non-steam supply and return manifolds (hot oil, glycol, etc.). Allow for increase in insulation sizing to allow for tracers.

Instrument Application  This specification is to be used by Piping for heat tracing of all in-line instruments. Piping will also provide steam supply and condensate collection manifolds for all other instruments. The break between Piping Traced Instruments and Control Systems traced instruments will match the drawing break between the two departments. System Description  Using various media such as steam, hot water, glycol, or hot oil heat tracing is installed to protect the piping, equipment, and instruments against temperatures that would cause congealing or freezing of the process fluids, interfere with operation, or cause damage to the equipment. Design Requirements   The daily average low temperature of the coldest month shall be used to select the low ambient design temperature that then determines the degree of winterizing protection required.  

No winterizing is required for water service except where a sustained temperature below minus 1 degree C is often recorded for 24 hours or longer. Compressors, blowers, and other mechanical equipment shall be specified for operation at low ambient design temperature.

Methods of Heat Conservation   Where feasible, insulation shall be used for heat conservation. 

Heat tracing, plus insulation, is the alternative method for heat conservation.



Heat transfer cement may be utilized when a process line requires a high heat input and common methods of heat tracing are inadequate.



Steam jacketing is utilized in specific cases where steam tracing with heat transfer cement is inadequate.



Electric tracing is utilized when precise temperature control is required or where steam tracing is not practical. Thermostat setting for electric tracing should not be higher than fluid operating temperature.

Methods for Winterization   Winterizing by circulation shall be provided where a sufficient power source is available to keep the fluid circulating. 

Utility water and utility air lines in intermittent service shall be winterized by draining.



Winterizing by steam tracing is the preferred method when winterizing by circulation and draining is impracticable.



Winterizing by electric tracing is utilized when a precise temperature control is required or where steam tracing is not practical. Thermostat setting for electric tracing should not be higher than fluid operating temperature.



Minimum tracing steam pressure shall be 1 Bar; maximum required is 10.3 Bar. At minimum pressure, condensate shall be routed to the plant sewer system. If condensate is collected, the minimum usable pressure shall be 1.7 Bar.

Tracer Description  Tracer Size and Length   Required tracer size shall be determined by piping heat loss and tracer steam pressure found in the Heat Loss Chart (Fig. 1) 

Minimum tracer size shall be 3/8 of an inch OD tubing; maximum size shall be 1 inch OD tubing. For economy, where Heat Loss Chart indicates the requirements for multiple tracers, a single tracer with heat transfer cement shall be considered.



When using heat transfer cement, tracers of 3/8 of an inch and 1/2 of an inch OD tubing are recommended. If more tracer area is required, multiple tracers of 3/8 of an inch and 1/2 of an inch shall be used.



Maximum tracer length shall be based on tracer size and steam pressure as follows:

o    Steam pressure 1 Bar through 1.7 Bar 

60m for 3/8 of an inch and 1/2 of an inch tracers



100m for 3/4 of an inch and 1 inch tracers

o    Steam pressure 3.5 Bar through 13.8 Bar 

60m for 3/8 of an inch and 1/2 of an inch tracers



120m for 3/4 of an inch and 1 inch tracers

o    Tracer lengths for tracing with heat transfer cement shall be based on recommendation of manufacturer.  

For stainless steel lines, the tracer material shall be low carbon steel. Stainless steel instrument leads shall be traced with copper tubing. Each tracer shall have its own trap. Tracer traps shall discharge to sewer. If condensate must be collected, minimum usable pressure is 1.7 Bar.



Compression type fittings shall be installed outside of the insulation OD.



Socket type fittings may be installed inside of the insulation.



The steam tracers shall be pressure tested before the insulation is applied. Under emergency conditions, the insulation may be applied but the fittings shall be left exposed until the testing is complete.

Tracer Pocket Depth   Pocket depth is the distance the tracer rises in the direction of flow from a low point to a high point. The total pocket depth is the sum of all risers of the tracer. 

Maximum tracer total pocket depth shall be equal to 40 percent of tracing steam gage pressure expressed in meters.

Example: Tracing steam 10.3 bar 30 m x 0.40 = 12 m feet total pocket depth Products   Steam tracing tubing materials shall be in accordance with material specifications. 

Tracers shall be OD tubing. Soft annealed copper tubing shall be used where the temperature of the product line or tracing steam does not exceed 204 °C. Above this temperature, dead soft annealed hydraulic quality, low carbon, seamless steel tubing shall be used where the temperature of the product line or tracing steam does not exceed 399 °C.



For aluminum pipe lines, carbon steel tracer material shall not be used.



For aluminum pipe lines and all lines above 399 °C the tracer material shall be stainless steel.



For conditions where the tracer could overheat lines containing acid, caustic, amine, phenolic water, or other chemicals, insulation spacer blocks shall be installed between tracer and pipe.

Fig.1: Typical Heat Loss Chart

A Brief Presentation on “HOSE COUPLINGS” The purpose of this presentation is to provide brief information about different types of hose couplings which are used in oil & gas applications. Purpose of Couplings (Fig. 1):  For loading & unloading tanker connection. 

For purging as well as flushing connection.

Different Hose Couplings Types/Brands                Elaflex 

TODO



Cam and Groove (Camlock) Couplings



Avery Hardoll dry break couplings &



Carter couplings

Elaflex Couplings (Fig. 2):  Elaflex coupling sizes – ½” to 4” 

Type of pipe connection – threaded & flanged



Available Pressure classes – 150# & 300# (Working pressure up to 25 bar)



Material of construction – Brass (for non-sour service), SS (for sour service)



Manufacturing Std. – API RP 1004 / EN 14420

Fig. 1: Purpose of Hose Couplings

TODO coupling (Fig. 3):  Available sizes – 3/4” to 6” 

Type of pipe connection – threaded & flanged



Pressure class – 150# & 300# (Working pressure up to 25 bar)



Material of construction – Brass, SS, Aluminium, Hastelloy C & other on request



Manufacturing Std. – EN 13480 and EN 13445

Fig. 2: Typical figure of Ela Flex Coupling

Fig. 3: Typical figure of TODO Coupling



TODO couplings are used for tanker unloading connection into a tank/vessel, because of the integral check valve.



Elaflex couplings are used for tanker loading connection from a tank/pit.

Cam & Groove (Camlock) Couplings (Fig. 4):  Available sizes – 1/2” to 6” 

Type of pipe connection – threaded



Pressure class – 150# (Working pressure up to 17 bar)



Material of construction – Brass, SS & Aluminium

Fig. 4: Typical figure of Camlock Couplings. Carter Couplings (Fig. 5): Carter Couplings are used in following applications: 

LNG tanker refuelling



Aircraft refuelling

Fig. 5: Figure of Carter Couplings

A very short literature on Strainers used in piping Industry Strainers (Fig. 1) arrest debris such as scale, rust, jointing compound and weld metal in pipelines, protecting equipment and processes. A strainer is a device which provides a means of mechanically removing solids from a flowing fluid or gas in a pipeline by utilizing a perforated or mesh straining element.

Fig.1: Example of a typical Strainer

To ensure against untimely shutdown of equipment, strainers should be installed ahead of pumps, loading valves, control valves, meters, steam traps, turbines, compressors, solenoid valves, nozzles, pressure regulators, burners, unit heaters and other sensitive equipment. The most common range of strainer particle retention is 1 inch to 40 micron (.00156 inch ). Sensitive Equipments: Static  Heat exchanger 

Meters



Steam trap



Spray nozzles

Sensitive Equipments: Dynamic  Pumps



Compressors



Turbines

What are Basic Types? Permanent: 

Y type (Fig. 2)



Basket Type( Simplex & Duplex construction) (Fig. 3)



T type

Fig. 2: Figure showing an example of a typical Y-type Strainer

Temporary: 

Cone type



Truncated Cone type

Design Code: Design to following International Standards: 

ANSI B 16.34



PED 97/23/EC: Pressure equipment design



BPV: ASME Boiler & Pressure vessel code, Section-VIII Div.1

Material of Construction: Body: 

Forged



Casting( but flanges shall be integral part of body)



Fabricated

Internals: 

Stainless steel



Special care shall be taken for Produced water service

Fig. 3: Example showing a figure of typical Basket type filters

End connections: 

Flanged



SW or Threaded

Construction terminology: Two types of screens used in strainers: 

Perforated screens



Mesh screens

Perforated screens: – These are formed by punching a large number of holes in a flat sheet of the required material using a multiple punch. These are relatively coarse screens and hole sizes typically range from 0.8 mm to 3.2 mm Mesh screens: – Fine wire is formed into a grid or mesh arrangement. This is then commonly layered over a perforated screen, which acts as a support cage for the mesh. 

Mesh Screen terminology : e.g. 3 mesh screen



We shall always ask process to give Max.allowable pressure drop at % clogged condition.



Mesh screens are usually specified in terms of ‘mesh'; which represents the number of openings per linear inch of screen, measured from the center line of the wire.

Fig. 4: Example of Mesh Size



Mesh is not the only thing to be asked for but hole size is also important.



Corresponding hole size in the mesh screen is determined from knowledge of the wire diameter and the mesh size

Strainer options:  Magnetic inserts 

Self-cleaning strainers



Mechanical type self-cleaning strainers



Backwashing type strainers



Temporary strainers

Temporary strainers (Fig. 5): -

Fig. 5: Typical Temporary Strainers

Y type strainer on various fluid (Fig. 6):-

Fig.6: Y type strainer on various fluid

137.4 Hydrostatic Testing It is important to provide high point vents and low point drains in all piping systems to be hydro tested. The high point vents are to permit the venting of air, which if trapped during the hydro test may result in fluctuating pressure levels during the test period. The drains are to allow the piping to be emptied of the test medium prior to filing with the operating fluid. (Low point drains are always a good idea though since they facilitate cleaning and maintenance.) A hydro test is to be held at a test pressure not less than 1.5 times the design pressure. The system should be able to hold the test pressure for at least 10 minutes, after which the pressure may be reduced to the design pressure while the system is examined for leaks. A test gauge should be sensitive enough to measure any loss of pressure due to leaks, especially if portions of the system are not visible for inspection. The test medium for a hydro test is usually clean water, unless another fluid is specified by the Owner. Care must be taken to select a medium that minimizes corrosion.

Routing Of Flare And Relief Valve Piping: An article-Part 1 The purpose of this article is to provide a brief idea of Flare and Relief Valve piping highlighting the important points. Due to long length of this article it will be published in several parts. What are Relief Events?  External fire 

Flow from high pressure source



Heat input from associated equipment



Pumps and compressors



Ambient heat transfer



Liquid expansion in pipes and surge

Potential Lines of Defense:  Inherently Safe Design 

Low pressure processes



Passive Control



Overdesign of process equipment



Active Control



Install Relief Systems

What is a Relief System?



A relief device, and



Associated lines and process equipment to safely handle the material ejected

Why Use a Relief System?  Inherently Safe Design simply can’t eliminate every pressure hazard 

Passive designs can be exceedingly expensive and cumbersome



Relief systems work!

Code Requirements: General Code requirements include: 

ASME Boiler & Pressure Vessel Codes



ASME B31.3 / Petroleum Refinery Piping



ASME B16.5 / Flanges & Flanged Fittings

Relieving pressure shall not exceed MAWP (accumulation) by more than: 

3% for fired and unfired steam boilers



10% for vessels equipped with a single pressure relief device



16% for vessels equipped with multiple pressure relief devices



21% for fire contingency

Locating Reliefs – Where?  All vessels 

Blocked in sections of cool liquid lines that are exposed to heat



Discharge sides of positive displacement pumps, compressors, and turbines



Vessel steam jackets

Choosing Relief Types  Relief Valves 

Rupture Devices

Spring-Operated Valves:  Conventional Type

Fig.1: Conventional type PRV



Balanced Bellows Type:

Fig.2: Bonnet Bellow type PRV

Fig.3: A Typical Pressure Safety Valve

Pros & Cons: Conventional Valve  Advantages +        Most reliable type if properly sized and operated +        Versatile — can be used in many services 

Disadvantages

+        Relieving pressure affected by back pressure +        Susceptible to chatter if built-up back pressure is too high Pros & Cons: Balanced Bellows Valve



Advantages

+        Relieving pressure not affected by back pressure +        Can handle higher built-up back pressure +        Protects spring from corrosion 

Disadvantages

+        Bellows susceptible to fatigue/rupture +        May release flammables/toxics to atmosphere +        Requires separate venting system When to Use a Spring-Operated Valve  Losing entire contents is unacceptable –        Fluids above normal boiling point –        Toxic fluids 

Need to avoid failing low



Return to normal operations quickly



Withstand process pressure changes, including vacuum

When to Use Both Types:  Need a positive seal (toxic material, material balance requirements) 

Protect safety valve from corrosion



System contains solids

A Special Issue: Chatter  Spring relief devices require 25-30% of maximum flow capacity to maintain the valve seat in the open position  

Lower flows result in chattering, caused by rapid opening and closing of the valve disc This can lead to destruction of the device and a dangerous situation

Chatter – Principal Causes  Valve Issues –        Oversized valve –        Valve handling widely differing rates 

Relief System Issues

–        Excessive inlet pressure drop –        Excessive built-up back pressure Rupture Devices  Rupture Disc 

Rupture Pin

Conventional Metal Rupture Disc  

Fig.4: Conventional Rupture Disc

What is total head? Total head and flow are the main criteria that are used to compare one pump with another or to select a centrifugal pump for an application. Total head is related to the discharge pressure of the pump. Why can't we just use discharge pressure? Pressure is a familiar concept, we are familiar with it in our daily lives. For example, fire extinguishers are pressurized at 60 psig (413 kPa), we put 35 psig (241 kPa) air pressure in our bicycle and car tires.For good reasons, pump manufacturers do not use discharge pressure as a criteria for pump selection. One of the reasons is that they do not know how you will use the pump. They do not know what flow rate you require and the flow rate of a centrifugal pump is not fixed. The discharge pressure depends on the pressure available on the suction side of the pump. If the source of water for the pump is below or above the pump suction, for the same flow rate you will get a different discharge pressure. Therefore to eliminate this problem, it is preferable to use the difference in pressure between the inlet and outlet of the pump. The manufacturers have taken this a step further, the amount of pressure that a pump can produce will depend on the density of the fluid, for a salt water solution which is denser than pure water, the pressure will be higher for the same flow rate. Once again, the manufacturer doesn't know what type of fluid is in your system, so that a criteria that does not depend on density is very useful. There is such a criteria and it is called TOTAL HEAD, and it is defined as the difference in head between the inlet and outlet of the pump.

You can measure the discharge head by attaching a tube to the discharge side of the pump and measuring the height of the liquid in the tube with respect to the suction of the pump. The tube will have to be quite high for a typical domestic pump. If the discharge pressure is 40 psi the tube would have to be 92 feet high. This is not a practical method but it helps explain how head relates to total head and how head relates to pressure. You do the same to measure the suction head. The difference between the two is the total head of the pump.

The fluid in the measuring tube of the discharge or suction side of the pump will rise to the same height for all fluids regardless of the density. This is a rather astonishing statement, here's why. The pump doesn’t know anything about head, head is a concept we use to make our life easier. The pump produces pressure and the difference in pressure across the pump is the amount of pressure energy available to the system. If the fluid is dense, such as a salt solution for example, more pressure will be produced at the pump discharge than if the fluid were pure water. Compare two tanks with the same cylindrical shape, the same volume and liquid level, the tank with the denser fluid will have a higher pressure at the bottom. But the static head of the fluid surface with respect to the bottom is the same. Total head behaves the same way as static head, even if the fluid is denser the total head as compared to a less dense fluid such as pure water will be the same. This is a surprising fact, see this experiment on video that shows this idea in action

.

For these reasons the pump manufacturers have chosen total head as the main parameter that describes the pump’s available

Hot Sustained Stress (Lift-Off) Checking in Caesar II Hot Sustained Stress Checking in Caesar II In Layman’s term Sustained means always present. So sustained stresses are the stresses which are present in the system throughout its operating cycle. Weight of piping system and Pressure inside the pipe are examples of sustained loads which generate sustained stresses in the system. So what is hot sustained case? While analyzing a piping system you many times will come across with few supports which will take load in sustained case but are not taking load in operating and design temperature cases (Refer Attached Fig. 1 and Fig. 2 for one such typical example). The support is lifting at that point in temperature case i.e. supports are not contributing in load and stress distribution while in in operating condition. Still in that situation the weight of pipe and pressure inside the system will induce sustained stresses. So in my opinion, hot sustained stress is the sustained stress in pipe operating situation. And we must ensure that the system stress will not fail because of those supports not sharing any load. That is why many organization make it mandatory to check sustained stresses.  

Fig.1: Caesar II Restraint summary showing lifting supports

Methods of Sustained stress checking: I have come across with two different methods of hot sustained stress check in various organization: 1. Conventional Method followed by many organizations: 

In first method the analyst has to run the static analysis as per conventional method.



Now go to restraint summary and note down the support nodes which are lifting or not taking any vertical load (Sometimes small positive value may be there due to guide and line stop frictions, in that case check the vertical displacement if it shows positive value consider the same as lifting).



Make a separate Caesar file with name FILE NAME_HOT SUSTAINED.



Open the input screen and delete all lifting supports from the nodes you noted down. Delete only +Y support, Guide and line stops will be there.



Run the analysis and check sustained stress.



If sustained stress is within allowable limit accept the file as it is else change the support location or routing to make the system safe.

Fig.2: Caesar II Plot showing lifting s

energy. 2. New method followed by very few organizations: 

In this method analyst will check the hot sustained stress in the same main file (No need to create separate file). Some additional load cases are required. Lets assume we will check hot sustained stress in design temperature, T1 condition (means we will check which supports are lifting in design temp case). So the below mentioned cases is required for hot sustained stress checking L1:                                W+T1+P1                                     OPE L2:                                        T1                                OPE/EXP L3:                                  L1-L2                                          SUS



Check the stresses for load case L3, if the same is within allowable limit then accept the file else make the system safe.

Notes: 1.

Now you may be thinking whether to mark deleted supports in isometric or not. You must mark those supports. As we have not deleted the supports in actual practice. Supports will be there at site, We simply ensured that without those supports also system will be safe. However if you want to delete those supports that can be done if all other stress criteria can met.

2.

Whether we need to check expansion stresses in hot sustained file too? In my opinion if we are using liberal stress for expansion stress range checking then it is better to check expansion stress (along with sustained stress) in hot sustained file. Otherwise it is not required as system won’t fail in expansion case even after removing those supports.

Pipe Rack and Rack Piping: A presentation This is a small presentation on Pipe Rack and Rack Piping. It will be very helpful for the beginners into piping industry. This article will cover the following points in brief:

                 

INTRODUCTION PIPE RACK Pipe Rack design criteria Shapes Future Space Width of Pipe Rack Clearance Pipe Rack Loading RACK PIPING Positions of Lines (Process & Utilities) Hot Lines & Cold Lines Bigger Size Lines Pipe Spacing Anchor Bay Unit Battery Limit Expansion Loops Pipe Route

Trays

INTRODUCTION: A pipe rack is the main artery of a process unit. It connects all equipment with lines that cannot run through adjacent areas. Because it is located in the middle of the most plants, the pipe rack must be erected first, before it becomes obstructed by rows of equipment. Pipe racks carry process, utility piping and also include instrument and electrical cable trays as well as equipment mounted over all of these. Fig. 1 shows a typical pipe rack. The primary data required for detailed development of a pipe rack :Plot Plan P&ID’s Client Specification Construction Materials Fire proofing requirements Statutory requirements

Fig. 1: Typical pipe rack

PIPE RACK DESIGN CRITERIA: Shapes There are various shapes of pipe rack like L/T/U/H/Z. These shapes shall be considered based on the area available. Future Space The total width of the pipe rack shall include 25% extra space for future expansion/modification in unit for rack-width up to 16 m and 10% for rack-width above 16 m. The future space %age is normally based on the client requirements. Width of Pipe rack The width of the rack shall be 6 m, 8 m or 10 m for single bay and 12 m, 16 m or 20 m for double bay having 4 tiers maximum. The spacing between pipe rack portals shall be taken as 6m in general. However it can be increased to 8m depending on the size of the pumps to be housed below pipe rack. Clearance For units, clearance beneath pipe rack shall be 4 m minimum both in longitudinal and transverse directions. For Offsite, clearance beneath pipe rack shall be 2.2 m minimum both in longitudinal and transverse directions. Road clearance shall be 7 m for main road and 5 m for secondary road.

RACK WIDTH SELECTION CRITERIA: Refer Fig. 2 for details

Fig. 2: Rack width selection criteria

PIPE RACK LOADING: Pipe rack loads shall be given by stress group to Civil & structural discipline for pipe rack design.     

Sustain Load (Dead Load): Weight of piping, valve and load insulation Thermal Load: Load by thermal expansion of piping & Reaction force by internal pressure of expansion bellows Dynamic Load Load by vibration of piping & by wind and earthquake Sustained Load (Live Load): Liquid load for hydro static pressure test

RACK PIPING:  Position of Lines: Predominantly process lines are to be kept at lower tier and, utility & hot process lines on upper tier.  Hot Lines & Cold Lines: Generally hot lines & cold lines are to kept at different tiers or at different groups on a tier.  Pipe Spacing: Minimum spacing between adjacent lines shall be decided based on O.D. of bigger size flange (minimum rating 300# to be considered), O.D. of the smaller pipe, individual insulation thickness and additional 25mm clearance. Even if flange is not appearing the min. spacing shall be based on above basis only. Actual line spacing, especially at ‘L’ bend and loop locations, shall take care thermal expansion/thermal contraction/nonexpansion of adjacent line. Non-expansion/thermal contraction may stop the free expansion of the adjacent line at ‘L’ bend location.  Bigger Size Lines: Large size lines (14” and larger) shall be arranged close to the column in order to decrease the bending moment of beam. Water lines more than 30” shall not be routed over pipe rack, these shall be routed underground.  Anchor Bay: Anchors on the racks are to be provided on the anchor bay if the concept of anchor bay is adopted. Otherwise anchor shall be distributed over two to three consecutive bays.  Anchors shall be provided within unit on all hot lines leaving the unit.  Pipe Route: Racks shall be designed to give the piping shortest possible run and to provide clear head rooms over main walkways, secondary walkways and platforms.  Trays: Generally top tier is to be kept for Electrical cable trays (if not provided in underground trench) and Instrument cable ducts/trays. Cable tray laying to take care of necessary clearances for the fire proofing of structure.  Battery Limit (ISBL): Process lines crossing units (within units or from unit to main pipeway) are normally provided with a block valve, spectacle blind and drain valve. Block valves are to be grouped and locations of block valves in vertical run of pipe are preferred. If the block valves have to be located in an overhead pipe-way, staircase access to a platform above the lines shall be provided.

EXPANSION LOOPS (Fig. 3):

Fig. 3: Examples of Expansion Loops  Expansion loop is provided on the high temperature lines. This information shall be given by stress group. All the loops shall be located around one column only.  MAKE LINES INTO A GROUP AND INSTALL A LARGE SIZE PIPING AND HIGH TEMPERATURE PIPING TO THE EDGE OF THE RACK  When necessary to install an expansion loop on the condensate line, do it horizontally to prevent water hammering. But do as above if horizontal loop is impossible.

 1. What is the ASTM code for the following?  A. Pipes :I. Carbon Steel II. Alloy Steel III. Stainless Steel IV. Nickel Steel. B. Tubes: – I. Carbon Steel II. Alloy Steel III. Stainless Steel IV. Nickel Steel. C. Wrought Iron Fittings: – I. Carbon Steel II. Alloy Steel III. Stainless Steel IV. Nickel Steel. D. Forged Fittings: – I. Carbon Steel II. Alloy Steel III. Stainless Steel IV. Nickel Steel. E. Cast Fittings: – I. Carbon Steel II. Alloy Steel III. Stainless Steel IV. Nickel Steel. F. Plates: – I. Carbon Steel II. Alloy Steel III. Stainless Steel IV. Nickel Steel.  Answer: –  A. Pipes: – I. Carbon Steel : – ASTM A53 Gr. A/B, ASTM A106 Gr. A/B/C, ASTM A333 Gr.1/Gr.6 II. Alloy Steel : – ASTM A335 Gr.P1/P2/P5/P7/P9/P11/P12/P22. III. Stainless Steel : – ASTM A312TP304/TP304L/TP304H/TP308/TP310/TP316/TP316L/ TP316H/TP317/TP321/TP321H/TP347/TP347H/TP348/TP348H. IV. Nickel Steel : – ASTM A333Gr.3/ Gr.8. B. Tubes: – I. Carbon Steel : – ASTM A178/179/192, ASTM A334 Gr.1/6. II. Alloy Steel : – ASTM A161T1, ASTM A213T1/T2/T5/T7/T9/T11/T12/T22. III. Stainless Steel : – ASTM A213 TP304/TP304L/TP304H/TP310/TP316/TP316L/TP316H/ TP317/TP321/TP321H/TP347/TP347H/TP348/TP348H, ASTM A608 HK40. IV. Nickel Steel : – ASTM A334Gr.3/Gr.8 C. Wrought Iron fittings :I. Carbon Steel : – ASTM A234Gr.WPA/B, ASTM A420 Gr.WPL6. II. Alloy Steel : – ASTM A234 WP1/WP5/WP7/WP9/WP11/WP12/WP22. III. Stainless Steel : – ASTM A403 WP304/WP304L/WP304H/WP309/WP310/WP316/ WP316L/WP316H/ WP317/WP321/WP321H/WP347/WP347H/ WP348. I V. Nickel Steel : – ASTM A420WPL6/WPL8. D. Forged Fittings : – I. Carbon Steel : – ASTM A181. ASTM A105, ASTM A350 LF1/2. II. Alloy Steel : – ASTM A182F1/F2/F5/F7/F9/F11/F12/F22.

III. Stainless Steel : – ASTM A182F6/F304/F304L/F304H/F310/F316/F316L/F316H/F321/ F321H/F347/F347H/F348. IV. Nickel Steel : – ASTM A350 LF3, ASTM A522. E. Cast Fittings: – I. Carbon Steel : – ASTM A216, ASTM A352 LCB/C. II. Alloy Steel : – ASTM A217 WC1/WC6/WC9/C5/C12. III. Stainless Steel : – ASTM A217 CA15, ASTM A296 CA15, ASTM A351 CF8/CF3/CH20/ CK20/CF 8M/CF 3M/CF 8C/HK40. IV. Nickel Steel : – ASTM A352LC3. E. Plates: – I. Carbon Steel : – ASTM A285, ASTM A515, ASTM A516. II. Alloy Steel : – ASTM A387 Gr.2/Gr.5/Gr.7/Gr.9/Gr.11/Gr.12/Gr.22. III. Stainless Steel : – ASTM A240 TP410/TP405/TP430/TP304/TP304L/TP309/TP310S/ TP316/TP316L/TP317/TP321/TP347/TP348 IV. Nickel Steel : – ASTM A203 Gr.D/Gr.E, ASTM A353.

2. What is the basic difference between Pipe specification A106 Gr.A / Gr.B/ Gr.C.? Answer: – Difference is due to the Carbon content. % of carbon content in : – I. ASTM A106 Gr. A – 0.25 % II. ASTM A106 Gr. B – 0.30 % II ASTM A106 Gr. C – 0.35 %. 3. What is the difference between pipe specification ASTM A312 TP 304 & ASTM A312 TP304L, ASTM A312 TP 316 & ASTM A312 TP 316L? Answer: – Difference is due to the Carbon content. The Letter “L” denotes lower percentage of carbon. % of carbon content in : – I. ASTM A312 TP 304 – 0.08 % II. ASTM A312 TP 304L- 0.035% III. ASTM A312 TP 316 – 0.08 % IV. ASTM A312 TP 316L- 0.035% 1. What is the ASME code followed for design of piping systems in Process piping (Refineries & Chemical Industries)? (i) B 31.1 (ii) B 31.3 (iii) B 31.5 (iv) B 31.9 Answer (II) 2. Which American institute standard does piping engineer refer? Answer: – A. The American Petroleum institute (API). B. The American Iron & Steel institute (AISI). C. The American Society for Testing and materials (ASTM). D. The American National standard institute (AISI). E. Th e American welding society (AWS). F. The American Water Works Association (AWWA). G. The American Society for Mechanical Engineers (ASME). 3. What is the different ASME 31 code for pressure piping? Answer: – A. ASME B31.1 – Power piping. B. ASME B31.2 – Fuel Gas Piping. C. ASME B31.3 – Process piping. D. ASME B31.4 – Pipeline Transportation system for liquid hydrocarbon & other liquid. E. ASME B31.5 – Refrigeration Piping. F. ASME B31.8 – Gas transmission & distribution piping system. G. ASME B31.9 – Building services piping. H. ASME B31.11 – Slurry transportation piping system. 4. What are the different sections of ASME code? Where these sections are reffered? Answer: – A. ASME section I : – Rules for construction of power boiler. B. ASME Section II : – Materials. Part A – Ferrous materials.

Part B – Non- Ferrous materials. Part C – Specification for electrodes & filler wire. Part D – Properties. C. ASME Section IV : – Rules for construction of Heating Boiler. D. ASME Section V : – Non- destructive E xamination. E. ASME Section VI : – Recommended rules for care & operation of heating boiler. F. ASME Section VII : – Recommended guidelines for care of power boiler. H. ASME Section VIII : – Rules for construction of pressure vessels. (Division I & II) I. ASME Section IX : – Welding & Brazing qualification. 5. Which American standard is reffered for selection of following piping element? A. Flanges B. Butt Welded fittings C. Gasket D. Socket & Threaded fittings E. Valves F. Pipes. Answer: – A. Flanges : – I. ASME B16.1 : – Cast iron pipes flanges & flanged fittings. II. ASME B16.5 : – Carbon steel pipes flanges & flanged fittings. (Up to 24”) III. ASME B16.47 : – Large Diameter steel flanges. (Above 24”) B. Butt welded fittings :I. ASME B16.9 : – Steel butt welding fittings. II. ASME B16.28 : – Butt-welded short radius elbows & returns bends. C. Gasket :I. ASME B16.20 / API – 601: – Metallic gaskets for pipe flanges- Spiral wound, Octagonal ring Joint & Jacketed flanges. II. ASME B16.21 : – Non metallic gasket. D. Socket & Threaded fittings : I. ASME B16.11 : – Forged steel socket welding & threaded fittings. E. Valves :I. ASME B16.10 : – Face to face & end to end dimension of valves. II. ASME B16.34 : – Flanged & butt-welded ends steel valves (Pressure &Temperature ratings) except Ball, Plug & Butter fly Valves. F. Pipes :I. ASME B36.10 : – Welded & Seamless wrought iron pipes. II. ASME B36.19 : – Stainless steel pipes.

An article on Tank Bulging effect or bulging effect of tank shells Stress analysis of lines connected to API tanks is very critical. I am sure most of you have done stress analysis of lines connected to equipment nozzles. However when it comes to tank nozzle, there are some differences, due to which the approach followed for equipment nozzle cannot be followed. In the Stress analysis of lines connected to normal Equipment nozzle (Vessel, Column, Heat Exchanger etc.), generally there are only 2 things which we have to account during Caesar modelling.  Nozzle’s thermal movements, and  Nozzle flexibility But in additional to those two things, there are two additional points which we have to account in the Caesar modelling during analysis of tank connected piping system. These are,  Nozzle rotations due to tank bulging, and  Tank settlement

What is this Tank Bulging? In case of tank, tank is filled with liquid. This liquid has varying height. Due to this, there is varying liquid pressure on tank wall. It has more pressure at bottom. Due this, tank wall try to expand more at bottom (as seen in slide).

But the bottom plate prevents this expansion and holds the bottom end of shell in position. Due to this, actual shape of tank is formed similar to as shown in Fig. 1. This is called bulging of tank shell.

Due to tank shell bulging, the nozzle on the shell moves radially outward, and rotates in vertical plane, depending upon their position. The nozzle on lower portion of the tank rotates downwards whereas nozzle on upper portion rotates upwards. This effect is not seen in other equipment, mainly because  Equipment diameter is relatively much small (up to 3 m). Therefore the amount of radial growth is much less. Whereas tank diameters are generally large, of the order of 10 m to 60 m. Due to this the amount of radial growth is significant.  Also, equipment has internal pressure, not only pressure due to fluid weight. Thus pressure variation from top to bottom is not so much where as in tank, pressure on top is zero.  At the same time, the bottom of equipment is not flat like tank, which does not deflect but acts like stiffener, to holds the shell ends. However the main difference is due to tank diameter only. How Tank Bulging is calculated? In the design code API 650, which governs the design of tank, this bulging effects is covered in Appendix – P. This Appendix – P is mandatory for tanks greater than 36 m diameter and for tank with diameter 36 m & below, it is optional or mandatory only if specified by purchaser. The intent of 36m diameter condition is to inform the user that the bulging effect is significant in large diameter tanks, which code has considered as above 36m diameter, hence put as mandatory. For smaller diameter it is considered as insignificant, hence kept as non-mandatory . The formulas for calculation of Radial movement and rotation due to tank bulging is provided in API 650 and produced in Fig 2 and Fig 3 for your reference.

If you calculate the outward radial movement and rotation using the above formulas it can be found that effect of tank bulging on nozzle at higher elevation is insignificant. Pipe routing guidelines to minimize effect of tank bulging:

Due to bulging, nozzle at lower levels rotates downward. This causes pipe to move vertically downwards.  To minimize the amount of this movement:  Piping shall be rotated through 90° as close to the tank wall as practical. 2D (D=outer diameter of pipe) spool may be provided to avoid elbow stiffening due to flanged elbow. This is shown in Fig. 4

Minimum Pipe Spacing Chart In petrochemical & refinery plants there are many pipes which are running from source to destination. In most of the cases there is pipe rack between the plant units which carry these pipes and distribute it across the plant. When the pipes are running next to each other there should be some minimum spacing between the pipes so that there shall be no clash between the pipes during construction. The basic principle for spacing the pipes adjacent to each other is: Centre to centre between the pipes = half O/D (outside diameter) of the bigger size pipe flange + Insulation thickness of bigger size pipe (if applicable) + 25mm + half O/D (outside diameter) of the smaller size pipe + Insulation thickness of smaller size pipe(if applicable).

NOMINAL PIPE SIZE ( Millimeters ) AND FLANGE RATING



PIPE SIZE

150

200

250

300

350

150#

300#

600#

150#

300#

600#

150#

300#

600#

150#

300#

600#

150#

300#

600#

25

190

205

230

215

240

255

255

265

305

295

305

330

320

345

355

40

190

215

230

230

240

265

255

280

305

295

320

330

320

345

355

50

205

215

240

230

255

265

265

280

320

305

320

345

330

355

370

80

215

230

255

240

265

280

280

295

330

320

330

355

345

370

380

100

230

240

265

255

280

295

295

305

345

330

345

370

355

380

395

150

255

280

295

295

305

330

320

345

370

355

380

395

380

405

420

200

280

305

320

320

330

355

345

370

395

380

405

420

405

430

445

250

305

330

345

345

355

380

370

395

420

405

430

445

430

460

470

300

330

355

370

370

380

405

395

420

445

430

460

470

460

485

495

350

345

370

380

380

395

420

405

430

460

445

470

485

470

495

510

400

370

395

405

405

420

445

430

460

485

470

495

510

495

520

535

450

395

420

430

430

445

470

460

485

510

495

520

535

520

545

560

500

420

445

460

460

470

495

485

510

535

520

545

560

545

570

585

550

445

470

485

485

495

520

510

535

560

545

570

585

570

595

610

600

470

495

510

510

520

545

535

560

585

570

595

610

595

625

635

650

495

520

535

535

545

570

560

585

610

595

625

635

625

650

660

700

520

545

560

560

570

595

585

610

635

625

650

660

650

675

685

750

545

570

585

585

595

625

610

635

660

650

675

685

675

700

710

800

570

595

610

610

625

650

635

660

685

675

700

710

700

725

735

850

595

625

635

635

650

675

660

685

710

700

725

735

725

750

760

900

625

650

660

660

675

700

685

710

735

725

750

760

750

775

790

1050

700

725

735

735

750

775

760

790

815

800

825

840

825

850

865

PIPE NOMINAL PIPE SIZE ( Millimeters ) AND FLANGE RATING 400 450 500 550 600 SIZE 150# 300# 600# 150# 300# 600# 150# 300# 600# 150# 300# 600# 150# 300# 600# 25 345 370 395 370 405 420 395 430 460 420 470 485 460 510 520 40 355 380 395 370 405 430 405 445 460 430 470 495 460 510 520 50 355 380 405 380 420 430 405 445 470 430 485 495 470 520 535 80 370 395 420 395 430 445 420 460 485 445 495 510 485 535 545 100 380 405 430 405 445 460 430 470 495 460 510 520 495 545 560 150 420 445 460 430 470 485 470 510 520 495 535 545 520 570 585 200 445 470 485 460 495 510 495 535 545 520 560 570 545 595 610 250 470 495 510 485 520 535 520 560 570 545 585 595 570 625 635 300 495 520 535 510 545 560 545 585 595 570 610 625 595 650 660 350 510 535 545 520 560 585 560 595 610 585 625 650 610 660 675 400 535 560 570 545 585 610 585 625 635 610 650 675 635 685 700 450 560 585 595 570 610 635 610 650 660 635 675 700 660 710 725 500 585 610 625 595 635 660 635 675 685 660 700 725 685 735 750 550 610 635 650 625 660 685 660 700 710 685 725 750 710 760 775 600 635 660 675 650 685 710 685 725 735 710 750 775 735 790 800 650 660 685 700 675 710 735 710 750 760 735 775 800 760 815 825 700 685 710 725 700 735 760 735 775 790 760 800 825 790 840 850 750 710 735 750 725 760 790 760 800 815 790 825 850 815 865 875 800 735 760 775 750 790 815 790 825 840 815 850 875 840 890 900 850 760 790 800 775 815 840 815 850 865 840 875 900 865 915 930 900 790 815 825 800 840 865 840 875 890 865 900 930 890 940 955 1050 865 890 900 875 915 940 915 955 965 940 980 1005 965 1015 1030

PIPE NOMINAL PIPE SIZE ( Millimeters ) AND FLANGE RATING 650 700 750 800 850 SIZE 150 # 300 # 600 # 150 # 300 # 600 # 150 # 300 # 600 # 150 # 300 # 600 # 150 # 300 # 600 # 25 485 535 560 510 570 585 545 595 610 585 625 650 610 650 675 40 495 545 560 520 570 595 545 595 625 585 635 650 610 660 675

50 80 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 1050

495 510 520 545 570 595 625 650 675 700 725 750 775 800 825 850 875 900 930 1005

545 560 570 595 625 650 675 700 725 750 775 800 825 850 875 900 930 955 980 1055

570 585 595 625 650 675 700 710 735 760 790 815 840 865 890 915 940 965 990 1065

520 535 545 585 610 635 660 675 700 725 750 775 800 825 850 875 900 930 955 1030

585 595 610 635 660 685 710 725 750 775 800 825 850 875 900 930 955 980 1005 1080

595 610 625 650 675 700 725 750 775 800 825 850 875 900 930 955 980 1005 1030 1105

560 570 585 610 635 660 685 700 725 750 775 800 825 850 875 900 930 955 980 1055

610 625 635 660 685 710 735 750 775 800 825 850 875 900 930 955 980 1005 1030 1105

625 635 650 685 710 735 760 775 800 825 850 875 900 930 955 980 1005 1030 1055 1130

595 610 625 650 675 700 725 735 760 790 825 840 865 890 915 940 965 990 1015 1095

635 650 660 685 710 735 760 790 815 840 865 890 915 940 965 990 1015 1040 1065 1145

660 675 685 710 735 760 790 800 825 850 875 900 930 955 980 1005 1030 1055 1080 1155

625 635 650 675 700 725 750 760 790 815 840 865 890 915 940 965 990 1015 1040 1120

660 675 685 725 750 775 800 815 840 865 890 915 940 965 990 1015 1040 1065 1095 1170

685 700 710 735 760 790 815 825 850 875 900 930 955 980 1005 1030 1055 1080 1105 1180

PIPE NOMINAL PIPE SIZE ( Millimeters ) 1. Spacing based on min. clearance of 25 mm between flange SIZE AND FLANGE RATING of one pipe and outside dia of adjacent pipe. 900 1050 2. All dimensions shown in millimeters. 3. If pipes are insulated add insulation thickness to above dimensions. 4. To arrive at spacing between two pipes of different flange ratings refer to tables of both pipes and use the larger of the two distances. Example: To Determine spacing between 150 NB Pipe 150# flange rating and a 100 NB pipe With 600# flange rating.  For 150 NB pipe and 100NB 600# flange Rating spacing = 255mm.

 For 100 NB pipe and 150 NB150# flange Rating spacing =230mm. Consider the maximum distances from 2 cases. The spacing between the 2 lines = 255mm

150 # 25 635 40 635 50 650 80 660 100 675 150 700 200 725 250 750 300 775 350 790 400 815 450 840 500 865 550 890 600 915 650 940 700 965 750 990 800 1015 850 1040 900 1065 1050 1145

300 # 685 685 700 710 725 750 775 800 825 840 865 890 915 940 965 990 1015 1040 1065 1095 1120 1195

600 # 710 710 725 735 750 775 800 825 850 865 890 915 940 965 990 1015 1040 1065 1095 1120 1145 1220

150 # 725 725 735 750 760 790 815 840 865 875 900 930 955 980 1005 1030 1055 1080 1105 1130 1155 1230

300 # 775 775 790 800 815 840 865 890 915 930 955 980 1005 1030 1055 1080 1105 1130 1155 1180 1205 1285

600# 800 800 815 825 840 865 890 915 940 955 980 1005 1030 1055 1080 1105 1130 1155 1180 1205 1230 1310

5. Flanges and or valves in adjacent lines must be staggered.

Vendor Drawing Review: A Review of Valve Drawings

Vendor drawing review (VDR) is a review of valve drawings indicating cross sectional view, material of construction with respect to purchase requisition (PR)requirements / data sheets. Piping material engineer shall well understand  the Project/Client/contract specifications to take care of any requirements specified therein which need to be reflected in the drawing before taking up this work on the project. Piping material engineer has to be familiar with codes applicable for the respective valve type. General Requirements for Vendor Drawing Review Below mentioned are general requirements which are applicable to most of the manual valves. Following details with respect to relevant valve data sheets, PO/PR shall be checked:     

    

         

Tag no/Part Number/Client part number, Size, MR SOS item No, Type of valve. Project specific Datasheet document number. Pressure class designation as applicable. Valve Design Standard specified (such as API, BS etc.). End connections (threaded, socket welded, butt welded, flanged, wafer type or hub ended). In the case of jacketed valves, the jacket flange size may be valve or jacket size depending upon whether the valve is partly or fully jacketed. Check for jacket fluid inlet / outlet connections. In case of valves with special end design, flanges / hub dimensions shall match with flanges / hub procured. Pipe class as applicable. Bonnet design whether welded or bolted or pressure seal type. Valve pattern i.e., long or short pattern requirement. Type of flange facing Raised face/ Flat face/RTJ with surface finish. In case of RTJ flange, hardness value. Materials of construction for: o Pressure parts (Body, Bonnet/Cover, Ball/Gate/Disc). o Pressure bolting with coating if any. o Trim (Seating surface/Seat Ring, Stem), Trim no. o Design temperature. o Gland packing or seal material. o Spring Material. o Bonnet/body gasket material. o Jacket of jacketed valves. o Other accessories shall be checked for suitability to service conditions like Low Temperature (LT) material for applications where in the ambient temperature is – 45 deg. C Type of operation where applicable, such as lever/wrench with position indicator, hand wheel, Gear, Chain etc., Or if extension of stems are required-in case of valves with insulation / extended operation. Check the extended stem dimension according to layout requirements. Stem design shall be generally single piece construction, however for extended stem design two piece construction shall be reviewed and may be accepted based on integrity and functionality of design provided by suppliers. Body wall thickness provided by vendor (actual) and body wall thickness as per respective design standard. Additional thickness considered in the shell for pipe classes wherever it is specified with Corrosion allowance ≥ 6 mm. Locked-open /Close requirements. For valves with butt-welding ends, edge preparation details and connecting pipe wall thickness details. Jacket fluid details. Tag/Name plate as per project specific requirements. Painting requirements as per project specifications. Compliance to NACE MR-0175/NACE MR-0103/ISO-15156 as applicable for sour service.

      

          

Reference to compliance to Job specification, NDE specification requirements. Flow direction for uni-directional valves. Spark test requirements for liners, as specified. Weight of valves especially for large sizes including gear box. Test pressures for Hydrostatic Shell, Seat /back seat, Pneumatic Seat. Fugitive Emission type test & production test, LT tests, Fugitive Emission tightness class requirements if any. Overall dimensional details i.e., face to face dimension etc., flange details or flanged end valves, in case of ball valves outer body contour dimensions from centerline to avoid interference with adjacent piping for sizes where it is more than outer diameter of connecting flange etc. distance from centerline to gear box location, hand wheel orientation for PDMS / PDS modeling. Supporting details for large size valves and lifting lug details. Minimum 2 Nos lifting lugs are required for valves weighing 250 Kg and more. Maximum wheel diameter (normally minimum of 750mm or face to face) or lever length (normally minimum of 450mm or twice the face to face) as per project requirement. End flange standard especially for sizes above 24” whether it is as per B16.47 Series A or B/ API standard. Wafer type valves, where the disc is expected to come out of body in open condition, clearance of disc with connecting pipe ID to be verified. Deviations in material of construction if to be accepted because of superior metallurgy offered by vendor to be scrutinized cautiously e.g., SS body proposed in place of CS shall lead to de-rating of CS rating. All nonmetallic seals shall be ascertained as suitable for service intended for. In particular, this shall include where applicable for the pressure rating, temperature,Sour service, fire-resistant and explosive decompression. Check if the extended bonnet requirement is applicable. Check if ‘O’ rings are provided in the vent/drain connection. Check for Full vacuum requirement compliance specified in the drawing. Check for PSL level and PR requirements for valves designed according to API-6A standard. Check for ring number requirement for flanged end valves designed according to API-6A.

WHAT IS A PIPE UNION : A pipe union is a secure and semi-permanent connection between two pipes. Most pipe unions consist of two pipes connected together via a third piece. All three are threaded to make a firm connection. While unions are similar to couplings, they are generally easier to take apart and allow pipes of different metals to come together safely. This joining method is common in household and commercial pipe systems. At first glance, a pipe coupling and a pipe union seem very similar. They both connect two pipes together using a male and female threading system. The main difference between the systems comes from the actual method of joining. Two coupled pipes screw together directly, one inside the other. To take the pipes apart, every pipe that connects to the coupled pipe needs to turn. In a full pipe system, this would mean the entire system needs to come apart to remove one pipe. With a pipe union, the two pipe ends don’t screw into one another—they each screw into a third piece. When one pipe needs to come apart from the other, the union piece simply screws onto one of the two pipes completely. If both ends of a pipe are attached using a union, the pipe may be removed on its own without unscrewing the other pipes in the system.

Hierarchy in PDMS: World, Site, Zone

Hierarchy in PDMS (Plant Design Management System): World, Site, Zone In the previous post, we saw the PDMS overview. I will cover WORLD, SITE, ZONE aspects in PDMS software developed by Aveva Plant to create 3D models. Before anyone starts modeling in the design module of PDMS, he should be well acquainted with the concept of hierarchy in PDMS i.e. WORLD, SITE & ZONE. All PDMS data is stored in the form of a hierarchy. A PDMS Design database has:  a top level, World (usually represented by the symbolic name /*)  two principal administrative sublevels, Site and Zone.

Hierarchy in PDMS If you login to PDMS SAMPLE project with design module, the tree shown in fig.1 appears under the Design Explorer. At the top of the tree is WORLD which contains number of SITES. In each SITE there are number of ZONES. While modeling the designer shall model in the correct SITE & the correct ZONE as per the philosophy decided at the start of the project by the Lead Engineer & PDMS Administrator. These instructions are generally covered in the document called as 3D Modeling Execution Procedure or 3D Modeling Job Notes.

Fig.1: Hierarchy in PDMS SAMPLE project The concept of hierarchy can be explained with an example shown in fig.2 WORLD in PDMS: The complete plant area appearing in the Plot Plan or the overall layout can be considered as “WORLD” for the Project. In the example the complete deck area highlighted in thick black border can be considered as the area available as WORLD in the PDMS. All the PDMS modeling shall be limited within this area. SITE in PDMS: In a project, the Plot Plan or the overall layout is divided into several sub-areas based on the sheet (A0 or A1) and the scale (eg. 1: 100 or 1:50) used for developing the equipment layout. In the equipment layout for each sub-area there are different equipment & components of each discipline i.e. Mechanical Equipment, Piping, Electrical, Instrumentation, etc. These sub-areas are used to create SITES in PDMS. In PDMS there are individual SITES created for different disciplines for each sub-areas. Referring to the example the deck area is divided in to four sub-areas AREA-1, AREA-2, AREA-3 & AREA-4 by the thick red lines. For AREA-1, there are different SITES created in PDMS as PIP_AREA-1, EQUIP_AREA-1, STRU_AREA-1, ELEC_AREA-1, INSTR_AREA-1 for modeling of Piping, Equipment, Structural, Electrical & Instrumentation respectively. Similar SITES will be created for each of the sub-areas. ZONE in PDMS: In each of the SITES created there are different categories of components which are required to be modeled under each discipline. For each category there is a ZONE created in PDMS. eg. In a project there are different fluid codes or services (i.e. CD, CO, FW, OD, etc.), so the pipes can be categorized as per the fluid codes or services. Using the above categorization in the example there are different ZONES created for each fluid code or service as PAREA-1/PIPE-CD, PAREA-1/PIPE-CO, PAREA-1/PIPE-FW, PAREA-1/PIPE-OD.

The above split of WORLD, SITE & ZONE can be seen in the Fig.3. Generally in a project the creation of SITES & ZONES is the responsibility of PDMS administrator. The PDMS designer will not have permission to create SITE & ZONE in the project. PDMS designer has the rights only to model the equipment & component in the ZONE. So while modeling the PDMS designer has to check the physical location of the component on the Plot plan & equipment layout then select the proper ZONE in PDMS before start of the modeling. In the example shown in fig.2, to model a pipe with line number CD-4”-AL0NL1-PP in AREA-1 you should be on the ZONE PAREA-1/PIPE-CD to model the pipe. The names used to identify database levels below Zone depend on the specific engineering discipline for which the data is used. For piping design data, the lower administrative levels (and their PDMS abbreviations) are: • Pipe (PIPE) • Branch (BRAN)

Fig 2 Example of a Deck layout

Fig .3: Hierarchy in PDMS for EXAMPLE project

Plant Design And Management System PDMS – An Overview Table of contents:

1. Features Of PDMS 2. How PDMS is organized 3. Different Modules In PDMS Plant design management system (PDMS) and it’s related application provides a powerful suit of facilities for the creation analysis documentation of a real-life plant in three dimensional representation in a logically interconnected system.

1. Features Of Plant Design And Management System (PDMS)       

Concurrent engineering Controlled catalogue database Automatic drawing production Isometric generation Material takeoff Report generation Clash checking

   

Interfacing with third party software Project progress monitoring Customization -PML Programming Training and maintenance

How PDMS is organized

How PDMS is organised

Different Modules In PDMS The different modules available in PDMS are listed below:            

Monitor Design Diagrams Schematic Model Manager Spooler Draft Isodraft Paragon Specon Propcon Lexicon Admin

Modules in PDMS

1. Admin module in PDMS PDMS Project Administration: The Project is a fundamental concept in PDMS, and all work takes place within a project. Everything that is defined in PDMS ADMIN is specific to a given project, although it is possible to read databases in another project. This module is only used by project PDMS administrator to create piping specification required as per the project material specification. The following are the key operation in admin module 1. Creation of MDB 2. Creation of DBS 3. Creation of TEAM 4. Creation of users 5. Access control 6. Replication 7. Reconfigure 8. Communication 9. Backtracking 10. Session control

Admin in PDMS 2. Monitor Module in PDMS Monitor allows the PDMS user to enter into a pdms project . This is a real life simulation of working in a controlled working environment . This feature controls unauthorized access to the project and also checks the user status for access. This module gives the project information which has been assigned during the PDMS project set up. The information like Project, Project name, Project code, Project Number is available in this module. It also lists the different MDB available in the project which can be used.

Monitor module in PDMS 3. Design Module in PDMS This module has different sub-modules like General, Equipment, Pipework, Cable Trays, HVAC Designer, Structures, Design Templates & Cabling System. Each of the sub-module is used by the modeler to model or create a graphical representation of the component required as per design requirement. There are many general commands and sub-module specific commands which are available to the user in different submodule.

Design module in PDMS  

Design module screen in PDMS 4. Isodraft Module in PDMS ISODRAFT can be used to produce isometric plot files of pipes and networks, from either the Design or Fabrication databases, to your own required standards. These drawings can be used for pipe work fabrication, as well as during on-site erection. The isometrics produced can be fully dimensioned and annotated to ensure that you find them easy to use and unambiguous. PDMS administrator has to create the back-up project template so that all the isometrics are extracted in the project required. This back-up template is available to the modeler when he starts extracting the isometrics using the standard isometric utility. Using isodraft system isometrics can also be extracted.

Isodraft module in PDMS   Isodraft enables you to do the following - System isometric showing a complete piping network and equipment trim

- Automatic spool identification - User defined Drawing Format - Automatic splitting of complex Drawing - Automatic isometric including the associated material list - Standard isometric of pipe zone or spool 5. Draft Module in PDMS This module is used to extract project general arrangement drawing. Using this module all discipline including piping, structural, electrical etc. extract all the required general arrangement drawing. PDMS administrator has to create the back-up project template so that all the general arrangement drawings are extracted in the project required. This back-up template is available to the modeler when he starts extracting the isometrics using the standard isometric utility. Extacting general arrangement drawing using draft module helps user to use annotation & tagging as required.

Draft module pdms screen Draft enables you to do the following - View creation - Dimensioning - Annotating - Labelling - 2-D drafting 6. Paragon Module in PDMS Paragon is used to input and modify the component catalogue stored in the PDMS Project Database .It is similar to the Manufacturers catalogue which we refer while conventional design This module is only used by project PDMS administrator to create different catalogue, section & categories required in the project. PDMS administrator also uses this module to create project bolt table & connection table (Coco table) as per project specification.

Paragon module display screen   Paragon enables you to do the following - Specifying the - Geometry - Connection information - Obstruction feature 7. Specon module in PDMS Specon is used to input and modify project specification. This is similar to manual pipework which assists and constrains the designer in the selection of components Specon enables you to do the following - Specifying the detail text - Pipng symbol - Catalogue reference 8. Lexocon module in PDMS Lexicon allows the PDMS Administrator to add new attributes to any element in the design catalogue or the drawing database. Once defined udas can be accessed in the same way as the standard attributes 9. Propcon module This module is used to construct a Properties Database . The database contains data for use with stress analysis package and safety auditing of all parts of design.The data structure is designed to provide information suitable for any stress analysis package if required.

Tank Settlement for Piping Stress Analysis In my last article on stress analysis of tank piping I have described the effect of tank bulging. Click here to refresh yourself on the effect of tank bulging. In this article I will describe about the effect of tank settlement on stress analysis of piping system connected to large tanks. Why settlement occurs for tanks but not for other equipments:

Equipment diameter is small (up to 3m). Therefore it is possible to design its foundation with large raft (say 10 m), to minimize or have insignificant settlement. Whereas tank diameters are generally large, of the order of 10 m to 60 m. Due to this it is impractical to design its foundation with raft, which would be much bigger than this. Many times it has ring foundation with soil compacted within this concrete ring. How much settlement to be considered: Amount of settlement depends on the location of tank. The amount of settlement is normally mentioned soil investigation report or geo-technological investigation report. IN CASE OF SAND: Majority of the total settlement occurs during hydro test of tank (before piping is connected). This is generally permanent. … Typically 60% For balance 40% of settlement, this occurs after piping connection, piping needs to be designed properly with settlement effect. IN CASE OF CLAY: Progressive settlement. The settlement is more at the center of tank, and typically 50% at the edge of tank. Since our nozzles and tank roof are connected / supported on shell, that is on outer edge of tank, we need to consider the settlement at outer edge of tank. Following Data to be obtained from civil for each tank (for each project)    

Total long term settlement. Settlement that will occur during construction and hydro test of tank. Recovery (if any) following construction and hydro test of tank. Further settlement, after hydro test of tank, (at the edge of the tank).

Sample Data from civil for each tank for a typical project is shown in Fig. 1 for understanding.  It contains each Tank number.  Settlement at Centre of Tank.  Settlement at Edge of Tank. Then out of total settlement at Edge, 40% of total settlement is what we consider in piping stress analysis.

Fig. 1: Sample tank settlement data for piping stress analysis Pipe routing guidelines (Fig. 2) to minimize effect of tank settlement: To reduce effect of tank settlement on piping:

 First support shall be kept sufficiently away from the tank nozzle.  Large dia. piping combined with large tank settlement may call for use of spring support. However use of spring support shall be avoided because accidental draining of line will cause excessive upward force on piping and tank nozzle. So, if spring support is used  WNC (Weight with No Content) load case shall be mandatory for liquid lines. In fact for all liquid lines with spring support, (whether it is connected to tank or any other line), WNC run shall be mandatory. In case of tank, all lines connected to tank will be carrying liquid only.  Spring setting should be adjusted in such a way, that nozzle load is within limit in normal operating case, as well as in WNC case.  That is set spring support for load lower than what is required. This will increase nozzle load in normal operating case, but will reduce load in WNC case.

Fig. 2: Figure showing pipe routing guidelines to reduce effect of tank settlement.

Propcon module in PDMS

Tank farm: Types, Design Considerations, Plot Plan Arrangement, Dyke Enclosure- Part 1 I. Introduction to tank farm: The use of tanks is common in all kinds of plants found in oil & gas industry. A. Process Plant o Refineries o Petrochemicals o Specialty chemicals B. Terminals C. Administration buildings D. Material Handling Plants

Storage tank are containers used for storage of fluids for the short or long term. Cluster of tanks together in a same are termed as “Tank Farms”.

II.        Types of Tanks: Types of Tanks in Process plant depend on the product to be stored, potential for fire, and capacity to be handled. 

Cone roof tank: Used for countless products including Petroleum, Chemicals, Petrochemicals, Food products & Water



Floating roof tank: The roof of tank rises and lowers with the stored contents thereby reducing vapour loss & minimizing fire hazard. Commonly found in Oil refineries.



Low temperature storage tank: Tanks stores liquefied gases at their boiling point. Products found in such tanks include Ammonia (-28 °F), Propane (-43.7 °F) and Methane (-258°F).



Horizontal pressure tank (Bullet): Used to store products under high pressure.



Hortonsphere pressure tank: Handles large capacity under high pressure.



Underground Tanks: Commonly used for drain collection of the plant at atmospheric pressure.



FRP Tanks: Commonly used for corrosive fluid at atmospheric pressure.

 

Fig Tank farms

 

Low Temperature Storage Tank

Underground Tanks

III.        Design Considerations for Tankfarm Layout: Below considerations are to taken into account while designing a Tankfarm for Process plants: General considerations:      

Local codes and regulations Client specification Topography Adjacent process units Neighbouring commercial and residential property Maintenance and operation

Detail design:     

Identification of storage based on fluid stored. Safety considerations/Statutory requirements General / Plot plan arrangement General piping layout Material of Construction.

Statutory and Safety Requirements: 

Following are the key statutory requirements (India). However these are to be relooked based on geographical location:

1. 2. 3. 4. 5. 6. 7.

OISD -118 ( Plant Layout ) OISD -116 / 117 (Fire Fighting ) Fire Hydrant Manual & Spray Manual. Factory Act of State. If Any Petroleum Act 1934 (Act N0.30 of 1934) Along with The Petroleum Rules. Static and Mobile Pressure Vessel (SMPV). National Fire Protection Act (NFPA).

  

Apart from this, local rules and regulations pertaining to State and local industrial requirement should be taken into consideration. Safety ensures proper protection and safe operation- Lifetime. Insurance Premium.

IV.        Plot Plan Arrangement for Tankfarm 



Hydrocarbon processing and handling plants are inherently hazardous involving large and complex processes and substantial risk potential; hence a careful consideration shall be given while developing a plot plan. Plot plan is a spatial arrangement of equipment considering proper flow sequence, system grouping, safety, statutory requirements, maintenance, operation, erection and construction with logistical economy. General classification of petroleum products for storage.

1. 2. 3. 4. 5.

Class – A: Flash Point below 23 °C Class – B: Flash Point of 23 °C & above but below 65 °C. Class – C: Flash Point of 65 °C & above but below 93 °C. Excluded Petroleum class: Flash Point of 930 °C & above. LPG doesn’t fall under this classification but form separate category.

 

Grouping of petroleum products for storage shall be based on product classification. Classification based on capacity and diameter:



1. Larger installations: Aggregate capacity of Class A and Class B petroleum product is more than 5000 cu.m or diameter of Class A or Class B product tank is more than 9m. 2. Smaller installations: Aggregate capacity of Class A and Class B petroleum product is less than 5000 cu.m or diameter of Class A or Class B product tank is less than 9m.

  

The storage tanks shall be located at lower elevation, wherever possible. The storage tanks should be located downwind of process units. Due to risk of failure of storage tanks and primary piping systems, means must be provided to contain the spills. The containment for petroleum storage tanks is in the form of Dyked enclosures.

Tank farm

V.        Dyke Enclosure 

Aggregate capacity in one dyke enclosure:

1. 2. 3. 4.

Group of Fixed roof tanks: Upto 60,000 m3 Group of Floating roof tanks: Upto 120,000 m3 Fixed cum floating roof tanks shall be treated as fixed roof tanks. Group containing both Fixed roof tanks & Floating roof tanks, shall be treated as fixed roof tanks.

     

Class – A and / or Class – B petroleum products :- Same dyked enclosure Class – C: – Preferably separate dyked enclosures. Tanks shall be arranged in maximum two rows. Tanks having 50,000 m3 capacities and above shall be laid in single row. The tank height shall not exceed one and half times the diameter of the tank or 20 m whichever is less. The minimum distance between a tank shell and the inside toe of the dyke wall shall not be less than half the height of the tank. Dyked enclosure for petroleum class shall be able to contain the complete contents of the largest tank in the dyke in case of any emergency.

1. Height of Dyke (H): 1m < H < 2m 2. Width of Dyke (W): Minimum 0.6m (Earthen dyke) Not Specific (RCC dyke)

Dyke enclosure  

Dyke enclosure   

Separation distances between the nearest tanks located in separate dykes shall not be less than the diameter of the larger of the two tanks or 30 meters, whichever is more. All process units and dyked enclosures of storage tanks shall be planned in separate blocks with roads all around for access and safety. In a dyked enclosure where more than one tank is located, firewalls of minimum height 600mm shall be provided to prevent spills from one tank endangering any other tank in the same enclosure.

Tank farm arrangement  

For larger installation, minimum separation distances shall be as specified in following tables.

Table 1: Inter unit Distances for large installations (D>9m or Agg. Cap > 5000cu.m)

Table 1  

Table 4 Table T4: Tank to tank distance within same Dyke Notes for Table 1:

Table 2: Interunit Distances for smaller installations (DPrimitives

Equipment modeling using primitives The following primitives are available for equipment modelling in PDMS

So while modelling equipment using primitives you have check the equipment drawing and decide which primitives are to be used for creating the 3D view of the equipment. Example of Equipment Modeling Using Primitives:

Modeling a horizontal vessel

Equipment modeling a horizontal vessel The above horizontal vessel can be modeled in PDMS using the primitives shown in the figure below

Equipment Modeling Using Templates An equipment template is a collection of primitives that make up the equipment shape grouped together under a template. There are many templates of standard equipment available in the PDMS database which can be used depending upon the requirement. Templates can be created using Create>Standard Equipment

Equipment modeling using templates Example of Equipment Modeling Using Templates:

The horizontal vessel shown in the above example can also be modeled using standard template.

Using Create>Standard Equipment open the required template as shown below

Click on to Properties button in the Create Equipment form. This opens the Modify Properties form where you can input the dimensions of the equipment as per the requirement. After completing the inputs of all dimensions click on to OK. Finally click on to the Apply button in the Create Equipment form, this will create the required equipment.

How to Change Hierarchy in PDMS 3D Modelling In many projects, there is 3D PDMS modelling procedure/work instruction which defines the hierarchy to be followed while 3D modelling. Example: In case of equipment, the nozzle shall be modelled as per the ascending order sequence. If we have modelled the nozzle in a different sequence than in the requirement, we have to reorder it as per the requirement in which case the Modify/Hierarchy function shall be used. Below example gives the stepwise commands which shall be followed change the hierarchy in PDMS Step 1: Check the current hierarchy in PDMS for the equipment V-1001/A. The nozzles are arranged as /V-1001/A/Elbowed-N2, /V1001/A/Elbowed-N4 & /V-1001/A/N3.

  Note: As per the procedure nozzle N3 shall be after nozzle N2 Step 2: To change the hierarchy of the nozzle using modify/hierarchy function got to Modify>Hierarchy>Reorder.

Step 3: The hierarchy reorder form as shown below will be displayed with equipment V-1001/A as the current element.

Step 4: Since we require need to move nozzle N3 after nozzle N2 select the nozzle N3 in the left display list and nozzle N2 in the right display list. Also make sure that the drop down list shows After since we have to reorder nozzle N3 after N2.

Step 5: Click Apply button to execute the reorder function. This will now move the nozzle N3 after nozzle N2 in the equipment hierarchy

Step 6: Once the hierarchy reorder function is done close the form by clicking Dismiss. Step 7: The changes done in the equipment hierarchy will also be displayed in the Member list Note: The Modify>Hierarchy>Reorder function can also be used to reorder the Member (Pipe, Equip etc.) under same zone.

1. How can flanges be classified based on Pipe Attachment? Answer: – Flanges can be classified based on pipe attachment as: – Slip – on. : – The Slip-on type flanges are attached by welding inside as well as outside. These flanges are of forged construction. Socket Weld. : – The Socket Weld flanges are welded on one side only. These are used for small bore lines only. Screwed. : – The Screwed- on flanges are used on pipe lines where welding cannot be carried out. Lap Joint. : – The Lap Joint flanges are used with stub ends. The stub ends are welded with pipes & flanges are kept loose over the same. Welding Neck. : – The Welding neck flanges are attached by butt welding to the pipe. These are used mainly for critical services where the weld joints need radiographic inspection. Blind. : – The Blind flanges are used to close the ends which need to be reopened. Reducing. : – The reducing flanges are used to connect between larger and smaller sizes without using a reducer. In case of reducing flanges, the thickness of flange should be that of the higher diameter. Integral. : – Integral flanges are those, which ar e cast along with the piping component or equipment. 2. How can flanges be classified based on Pressure – temperature ratings? Answer: – Flanges are classified based on pressure temperature ratings as: – A. 150 # B. 300 # C. 400 # D. 600 #

E. 900 # F. 1500 # G. 2500 # Pressure temperature rating carts in the standard ASME16.5 specify the non-shock working gauge pressure to which the flange can be subjected to at a particular temperature. 3. How can flanges be classified based on facing? Answer: – Flanges are classified based on facing as: – A. Flat face. (FF) B. Raised face. (R/F) C. Tongue and groove. (T/G) D. Male and female. (M/F) E. Ring type joint. (RTJ) 4. How can flanges be classified based on face finish? Answer: – Flanges are classified based on face finish as: – A. Smooth finish. B. Serrated finish. 5. Where the smooth finish flange & serrated finish flange finds its use? Answer: – The smooth finish flange is provided when metallic gasket is provided and serrated finish flange is provided when non-metallic gasket is provided. 6. What are the types of serrated finish provided on flange face? Answer: – A. Concentric or B. Spiral (Phonographic) 7. How the serration on flanges is specified? Answer: The serration on flanges is specified by the number, which is the Arithmetic Average Rough Height (AARH). 8. Where the concentric serration is insisted for face finish? Answer: – Concentric serration are insisted for face finish where the fluid being carried has very low density and can find leakage path through cavity. 9. How the Gaskets are classified based on the type of construction? Answer: – Based on the type of construction, gaskets are classified as: – A. Full face. B. Spiral wound metallic. C. Ring type. D. Metal jacketed. E. Inside bolt circle. 10. What is the most commonly used material for Gasket? Answer: – Compressed Asbestos Fibre. 11. Which type of gasket is recommended for high temperature & high- pressure application? Answer: – Spiral Wound Metallic Gasket. 11. What are the criteria for selection of MOC of Spiral Wound metallic Gasket winding material? Answer: – The selection of material of construction for Gasket winding depends upon: – A. The corrosive nature and concentration of fluid being carried. B. The operating temperature of the fluid. C. The relative cost of alternate winding material. 12. What are the most common materials used for spiral wound metallic gasket winding? Answer: – The most commonly used material for spiral wound metallic gasket winding is: – A. Austenitic stainless steel 304 with asbestos filler. B. Austenitic stainless steel 316 with asbestos filler. C. Austenitic stainless steel 321 with asbestos filler. 13. Which material is used as filler material for spiral wound gasket in case of high temperature services?

Answer: – For very high temperature services, graphite filler is used. 14. What is centering ring in connection to spiral wound gasket? Answer: – Spiral wound gaskets are provided with carbon steel external ring called centering ring. 15. What will be the AARH finish on flange face for using spiral wound gasket? Answer: – 125-250 AARH finish.

A short Presentation on Basics of Pressure Vessels A pressure vessel (Fig. 1) is a closed container designed to hold gases or liquids at a pressure substantially different from the ambient pressure. Basic type of vessel:  

Vertical pressure vessel Horizontal Pressure Vessel

There are various method used to support vessels,     

Lug Support Ring Support Skirt Support Leg Support Saddle Support

Types of end attached to the vessels are   

Dish ends Conical ends Flat Ends

Fig. 2 shows general configuration of a pressure vessel.

Fig. 1: A typical pressure vessel for a process plant               Design Input: While designing pressure vessel following inputs are required  

Internal Pressure / External Pressure Design temperature

  

Material of constructions Type of support Type of loading (wind load/seismic loading/snow loading)

Design Formula: Basic formula for designing the cylindrical shell is σ = PD/2t Therefore           t = PD/2σ Where,    

                t = thickness of shell                 P = internal pressure                 D = diameter of shell                 σ = tensile stress

Fig. 2: General Configuration of a typical pressure Vessel This basic formula is modified in international design codes. For ASME Sec VIII, thickness of the cylinder is calculated by following formula (Fig. 3)

Fig. 3: Formula for calculation of pressure vessel shell thickness Where ,     

t = thickness of shell P = internal pressure R = radius of cylinder S = tensile stress E = joint efficiency

Refer ASME Sec VIII Div 1 for design formulas for all sections of the vessel/cylinder. Type of Pressure Vessels:    

Vessel Supported on Lug Support (Fig. 4) Vessel Supported on Skirt(Fig. 4) Vessel Supported on Leg(Fig. 4) Vessel Supported on Saddle(Fig. 5)

Fig. 4: Various types of supports for pressure vessel

Fig. 5: Pressure Vessel Supported on Saddle Vessel Parts:      

Shell, head Nozzles Flanges Gaskets Internals Platforms & ladders

Design codes used for Pressure Vessel:          

EN 13445: The current European Standard, harmonized with the Pressure Equipment Directive (97/23/EC). Extensively used in Europe. ASME Code Section VIII, in addition supported by Sections II (materials), V (NDT/NDE) and IX (welding). Published by the American Society of Mechanical Engineers. ASME Code Section VIII Division 1: US standard, design by formula. Almost exclusively used in North America, widely used worldwide. ASME Code Section VIII Division 2: Alternative Rules, design by analysis. ASME Code Section VIII Division 3: Alternative Rules for Construction of High Pressure Vessel BS 5500: Former British Standard, replaced in the UK by EN 13445 but retained under the name PD 5500 for the design and construction of export equipment. AD Merkblätter: German standard, harmonized with the Pressure Equipment Directive. EN 286 (Parts 1 to 4): European standard for simple pressure vessels (air tanks), harmonized with Council Directive 87/404/EEC. BS 4994: Specification for design and construction of vessels and tanks in reinforced plastics. IS 2825-1969 (RE1977) : code unfired Pressure vessels

Internal used in Pressure Vessel: Internals are used to separate liquid from mixture of liquid & vapour. Refer Fig. 6

Fig. 6: Pressure Vessel Internals. Example of Pressure Vessel (Fig. 7):     

Separator Scrubber Distillation Column Shell & Tube Heat Exchanger Reactors

Fig. 7: Figure showing various types of pressure vessels. Material of Construction most widely used:    

Carbon steel and Cladding Plates Stainless Steel Duplex Stainless steel Fibre Glass Reinforced Plastic

Applications:

   

Refinery and Petro-chemical Fertilizer Oil and Gas Chemical

Shell & Tube Heat Exchanger Piping: A brief Presentation The purpose of this presentation is to provide guide lines for Shell & tube Heat Exchanger Piping Layout. Click here to get a preliminary idea about shell and tube heat exchangers. Use of Heat Exchangers: Heat exchangers are used to transfer heat from one fluid to another. They are generally named as cooler, chiller, condenser, heater, reboiler, waste heat boiler, steam generator & vaporizer in process plant. Types of Heat exchanger: The most commonly used types of  heat exchangers are     

Shell & Tube heat exchanger Air cooled heat exchanger Plate type heat exchanger Spiral heat exchanger Double pipe heat exchanger

Shell & Tube Heat Exchanger Construction (Fig. 1):

Fig.1 :Diagram showing construction of a typical Shell and Tube Heat Exchanger These heat exchangers are generally designed, fabricated, inspected and tested as per API 660 / EN-ISO 16812 / TEMA. The DEP for the design & construction of shell & tube heat exchanger is DEP 31.21.01.30 – Gen.

General Guidelines for selection for tube side & shell side fluids:    

Clean fluid through shell & dirty fluid through tubes Corrosive fluid through tubes as it is easy for cleaning & allows use of carbon steel for shell Water through shell & process liquid through Only sea water through tube side High pressure fluid through tubes which allows for min. wall thickness of shell

Layout of shell & tube heat exchangers other than in banks: As per the exchanger positions in a process plant the following general classification can be made: 1. 2. 3. 4.

Exchangers which should be next to other equipment: e. g. Vertical Reboiler Exchangers which should be close to other equipment: e. g. Overhead condenser Exchangers located between other process equipments: e. g. Exchanger with process lines connected to both shell & tube side Exchangers located between process equipment and the unit limit:e.g. Product coolers

Establishing elevations for the exchanger:   

Where process requirement dictates the elevation, it is usually noted on the PEFS Grade is the best elevation from economic point of view Located in structures where gravity flow is required or connected to pumps suction which has specific NPSH requirement e.g. overhead condenser

Layout of Shell & Tube heat exchanger in banks: Arrangement of exchangers (Fig. 2):

Fig. 2: Typical arrangements of shell and tube heat exchangers Various types of Exchanger orientation is possible as mentioned below: Sample exchanger orientation (Fig. 3):

Fig.3: Figure showing Heat Exchanger Orientation Single and Paired Exchangers (Fig. 4):

Fig.4: Single and Paired exchanger orientation Parallel Exchanger Installation (Fig. 5):

Fig. 5: Parallel Exchanger Installation Series Exchanger Installation (Fig. 6):

Fig. 6: Series Exchanger Installation Stacked exchanger installation: Two exchangers in series or parallel are usually stacked. Refer Fig. 7

Fig. 7: Stacked exchanger installation Nozzle arrangement for better piping (Fig. 8):

Fig. 8: Nozzle arrangement for better piping Structure mounted exchanger installation (Fig. 9):

Fig. 9: Structure mounted exchanger installation Supporting of shell & tube heat exchanger piping:   

No special guideline for supporting Stress analysis required to be carried out for the exchanger inlet & outlet lines Fixed saddle support near the tube bundle head, sliding support near the rear head

Heat exchanger maintenance: Tube bundle extractors (Fig. 10):

Consideration of Flanged Bend while modeling in Caesar II You must be aware that in most of the situation flanges are attached near elbows or bends (Near Control Valve assembly and equipment nozzles). This rigid attachment exerts a severe restraining force to the flexibility of the bend, thus reducing the flexibility of the bend and increasing the force and moment in the nearby support or nozzle. Code provides a currection factor C1 and C2 to take care of the same effect. In caesar the same can be easily taken care by modeling flanged elbow as mentioned below. Sometimes dummy attachments at elbow also provides similar effect that is why few organization have the practice of using flanged elbow while modeling the trunnions from elbow. Single or Double Flange Option should be applied to Stress Analysis, if there is any flanges or valves (heavy/rigid body) within two diameters of the ending weld point of the bend.

Fig. 1: Criteria for using Flanged Bend in Caesar II

Fig. 2: Caesar model showing the flanged bend application criteria   1. What is the main difference between Constant and Variable Spring Hanger? When to use these hangers? Ans: In Constant Spring hanger the load remains constant throughout its travel range. But In  variable Spring hanger the load varies with displacement. Spring hangers are used when thermal displacements are upwards and piping system is lifted off from the support position. Variable spring hanger is preferable as this is less costly. Constant springs are used: a) When thermal displacement exceeds 50 mm b) When variability exceeds 25% c) Sometimes when piping is connected to strain sensitive equipment like steam turbines, centrifugal compressors etc and it becomes very difficult to qualify nozzle loads by variable spring hangers, constant spring hangers can be used. 2. What do you mean by variability? What is the industry approved limit for variability? Ans: Variability= (Hot Load-Cold load)/Hot load= Spring Constant*displacement/Hot load. Limit for variability for variable spring hangers is 25%. 3. What are the major parameters you must address while making a Spring Datasheet? Ans: Major parameters are: Spring TAG, Cold load/Installed load, Vertical and horizontal movement, Piping design temperature, Piping Material, Insulation thickness, Hydrotest load, Line number etc.

5. How to calculate the height of a Variable Spring hanger? Ans: Select the height from vendor catalogue based on spring size and stiffness class. For base mounted variable spring hanger the height is mentioned directly. It is the spring height. For top mounted variable spring hangers ass spring height with turnbuckle length, clamp/lug length and rod length. 6. Can you select a proper Spring hanger if you do not make it program defined in your software? What is the procedure? Ans: In your system first decide the location where you want to install the spring. Then remove all nearby supports which are not taking load in thermal operating case. Now run the program and the sustained load on that support node is your hot load. The thermal movement in that location is your thermal movement for your spring. Now assume a variability for your spring. So calculate Spring constant=Hot load*variability/displacement. Now with spring constant and hot load enter any vendor catalogue to select spring inside the travel range. 7. Why horizontal displacement is specified in datasheet? What will you do if the angle due to displacement is more than 4 degree? Ans: For bottom mounted springs it is mentioned to avoid large spring bending by frictional force and displacement. So that additional measures can be taken to lower frictional force by providing PTFE/graphite slide plate. For top mounted spring hangers horizontal displacement is mentioned to check angularity of 4 degree to reduce transmission of horizontal force to piping systems as spring hangers are designed to take the vertical load only.

If angle becomes more than 4 degree due to large horizontal movement then install the spring hanger in a offset position so that after movement the angle becomes less than 4 degree. 8. Which spring will you select for your system: Spring with low stiffness or higher stiffness and why? Ans: Springs with lower stiffness provides less load variation for same travel. So this spring is a better choice than a spring hanger with higher stiffness.

B. Pipeline Material Selection The pipeline material type can be Rigid, Flexible or Composite There are different types of pipe which can be utilized for use as pipelines:      

Low carbon steel CRA Pipe Clad pipe Flexible pipe Flexible hose Coil tubing

The above pipes are manufactured in different forms:    

Seamless SAW ERW (mainly used in Onshore) HFI Welding

Seamless

SAW

Flexible Pipe  

Flexible Hose The material selection of pipelines is based on different parameters:    

Fluid properties Material cost Installation cost Operational cost

C. Pipeline Coatings Various Types of Coatings 1. 2. 3. 4.

Corrosion Coatings Insulation Coatings Concrete Weight Coating Field Joint Coating

1. Corrosion Coatings Commonly used Corrosion Coatings    

Fusion Bonded Epoxy (FBE), 0.4 – 0.5mm, 200°F 3 Layer polypropylene (3LPP), 3 – 4mm, 220°F 3 Layer polyethylene (3LPE), 3 – 4mm, 150°F Neoprene, 3 – 5mm , 220°F

2. Insulation Coatings  

Insulation coatings are provided to keep conveyed fluid warm. Pipeline should be heated either active or passive methods.



Active heating methods:

i. Electric heating ii. Circulating hot water (Pipe-in-pipe) 

Passive heating method:

i. Insulation coating) ii. Burial) iii. Additional cover 3. Concrete Weight Coatings)  

Ensure stability of pipe against wave and current loads. Provides protection against dropped objects

4. Field Joint Coatings

 

Field girth welds shall be coated with corrosion resistance coating. Typical field joints: o FBE o Heat shrink sleeve o Serwi wrap o HDPU for coated pipes

D. Pipeline Wall Thickness 

Pipeline wall thickness shall be designed for: o Internal Pressure – Hydrotest/Operation - Burst o External Pressure – Collapse/Propagation o Local Buckling o Buckle Propagation

Local Buckling

;

E. Pipeline Thermal Expansion  

Temperature and pressure tends to expand pipe Pipe/Soil Interaction will resist expansion

Influence of Excessive Force in Pipeline Fig: Influence of Excessive Force in Pipeline 

Thermal Expansion Mitigations o Expansion or U-Spools o Burial /Rock Dumping o Snake-lay o Random Buckle Initiators

Expansion or U-Spools

Snake lay

Buckling Initiators F. Pipeline On-Bottom Stability Design

Pipeline On-Bottom Stability Design 

Mitigations for On-Bottom Stability o Typical mitigation by concrete weight coating o Provide secondary stabilization If concrete coating thickness is excessive



Secondary Stabilization: o Trenching o Flexible mattresses o Rock dumping o Concrete blocks

Secondary Stabilization G. Pipeline Free Span Analysis   

Due to uneven seabed Re-route if possible Check for anticipated span is acceptable or not

> Dynamic Free Span Analysis:

Mitigations for Static/Dynamic Spans

H. Cathodic Protection Design  

Subsea Pipelines are protected against external corrosion by combination of anti-corrosion coating and sacrificial bracelet anodes CP system Pipeline, spool and riser protected by Bracelet Anodes

Cathodic Protection Design

I. Pipeline Shore Approach     

Shore approach is where pipeline cross the costal line Pipeline require additional protection at shore approach The most cost effective beach crossing is by open cut trenching When currents are strong, HDD (Horizontal directional drilling) is recommended Pipeline will be installed by beach pull

J. Subsea Tie-in Spool 

What is the purpose of Riser Tie-in Spool?

 

Pipeline End Expansion Varies from 200mm to 2000m subjected to temperature Pipeline Walking (short pipeline) 10mm per shutdown, from hot end to cold end

Checklist for Nozzle Orientation Further to my post related to requirements for preparation and issue of nozzle orientation, here is a checklist for the nozzle orientation. Project Name:

 

Job No:

 

Equipment type:

HORIZONTAL/ VERTICAL

Equipment Tag No.:

 

SL NO.

DESCRIPTION

Check Points  

Common for Horizontal or Vertical Vessel

1

Vessel modelling is completed and nozzle orientation is extracted from model & checked against latest vendor drawing.

2

30% Model review is completed and review tag related to subject vessel are closed.

3

Plant “North” is indicated. Nozzle orientation angle shall be w.r.t. north as ‘0’ degree(clock wise).

4

Any P&ID notes regarding particular nozzle location/ elevation/ orientation are taken into consideration.

5

All nozzles are shown as per P&ID and are designated with nozzle tag number, size and rating. Any mismatches are commented and resolved.

6

All nozzles are shown as per Mechanical Data Sheet(MDS) and are designated with nozzle number, size and rating. Any mismatches are commented and resolved.

7

All level instrument nozzles are shown as per Level Sketches. Any mismatches are commented and resolved.

8

Vessel dimensions OD (or ID & thk) and height/ length are shown.

9

Holds & notes are clearly listed & identified with cloud.

10

All reference drawings (P&ID / MDS / Level Sketches / Vendor GA) including revision number are listed in reference drawing section .

11

Nozzles projected above platforms have minimum clearance of 150 mm between bottom of flange and top of grating.

12

Inlet and outlet nozzles shall be located sufficiently away to avoid vortex flow.

13

All nozzle projections are shown with respect to TAN line for all dish end nozzles.

14

All nozzle projections (exclusive of dish end nozzles) are shown with respect to vessel centre line for all shell nozzles.

15

Insulation thickness of vessel is considered in determining the nozzle projection.

16

Insulation thickness shall be shown dotted in drawing.

17

Proper access and approach ladder is provided for all Nozzles/ Instruments as per project specification and all Platform dimensions, location & ladder location are shown.

18

Side entry from ladder has been provided to the top and intermediate platforms.

19

All valves are accessible from ladder for size less than or equal to 3” and from platform for sizes greater than 3” unless otherwise specified in relevant project specifications/ client operation and maintenance requirements.

20

Maximum height of ladder, without mid landing is checked with respect to project specifications.

21

Location and orientation of pipe support cleats are clearly shown.

22

For Instrument nozzles that require access, check the possibility of combining the nozzles for common access and also check for any obstruction in the surrounding.

23

Hand hole location/orientation shall be shown.

24

Nozzle schedule table (showing sl.no, nozzle name, rating, size, nozzle function, nozzle projection from vessel center line etc.) shall be shown.

25

Manhole location shall be shown. Manhole cover can be opened without any hindrance. Manhole davit orientation is marked and manhole envelope angle are shown. Sideways location is preferred manhole location.

26

Manhole height from platform shall be as per project specifications/ client requirements.

27

Orientation of skirt openings are shown

28

Minimum 750 mm clear space is available on all vessel Platforms for ease of access even after installing all Stand pipe, valves, Instruments.

 

Horizontal Vessel

1

One plan view with minimum two elevation views (front view & side view) are shown, if nozzles are on both Dish end, Both views are required, The views are clearly marked with A-A, B-B etc.

2

Vessel Bottom elevation is as per P&ID(If specified in P&ID)

3

Height of centre line of equipment with respect to bottom of saddle is shown.

4

Proper access, clearances are provided for bottom nozzles, boot mounted nozzles and nozzles are clash free with equipment support.

5

Slope in Sloped vessels is shown appropriately as per P&ID requirement.

6

Slope in Sloped vessels is shown appropriately as per Mechanical Data Sheet(MDS) requirement.

 

Vertical Vessel

1

One elevation view and multiple plan views at every platform elevation are shown.

2

Vessel Bottom Line elevation is as per P&ID(If specified in P&ID).

3

Based on Drop zone area, Pipe davit radius is marked. Pipe davit orientation is shown in the plan view of the top platform. Drop zone area to be accessible from common access.

4

Platform width, start angle and end angle are shown clearly.

5

Orientation of pipe supporting cleat of vessel is shown.

6

When there are two platforms one above the other (typically in columns etc.), ensure adequate headroom is available and space is not obstructed due to structural bracings.

 

Pig Launcher

1

Kicker line connection shall be shown on side/ top of major barrel near to end closure.

2

Balance line connection shall be shown on side/ top of minor barrel near to pig trap valve location.

3

Vent connection shall be shown on top of major barrel.

4

Pig signaler shall be located on top of minor barrel near to reducer.

5

Pressure transmitter connection shall be located on top of major barrel.

6

Pressure safety valve location shall be shown on top of major barrel.

7

Purge connection shall be located on top of major barrel.

8

Pressure indicator connections shall be shown on the top of major barrel near to end closure and also on minor barrel near to pig trap valve location.

9

Lifting lug (two nos.) location shall be shown on major barrel.

10

Drain shall be shown on bottom of major barrel near to reducer and also on bottom of minor barrel near to pig trap valve.

 

Pig Receiver

1

Kicker line connection shall be shown on side/ top of major barrel near to reducer.

2

Balance line connection shall be shown on side/ top of minor barrel near to reducer.

3

Vent connection shall be shown on top of major barrel near to end closure and also on top of minor barrel near to pig trap valve.

4

Pig signaler shall be located on top of minor barrel after near to pig trap valve.

5

Pressure transmitter connection shall be located on top of major barrel.

6

Pressure safety valve location shall be shown on top of major barrel.

7

Purge connection shall be located on top of major barrel.

8

Pressure indicator connections shall be shown on the top of major barrel near to end closure and also on minor barrel near to pig trap valve location.

9

Lifting lug(two nos.) location shall be shown either on major barrel or on major and minor barrel depending upon the total length of pig receiver.

10

Drain shall be shown on bottom of major barrel near to end closure and also on bottom of minor barrel near to pig trap valve.

Check List for Piping Layouts

Project Name:

Job No.:

Client: Drawing No. :

Date : DD/MM/YYYY

Drawing Title : PIPING GENERAL ARRANGEMENT DRAWING Notes: 1. This checklist is intended for checking of layout drawings extracted from 3D CAD models. 2. As a minimum, the checklist shall be completed for the first issue of the layout drawing. 3. Items like Fire and Gas detectors and other E, I & T items (e.g. JBs, switch boards, lighting fittings, etc.) need not be shown in Piping Layouts. Sr. Check Points No DESIGN 1

Plant North is shown.

2

Grade and paving levels and paving extents are shown. (Dimensions of paving not required.)

3

Equipment and instrument tag nos. are indicated as per P&ID.

4

All equipments are shown with locating coordinates/dimensions and elevations (centerline, BTL, u/s of base plate, etc.).

5

All equipment nozzles and vendor package terminal points are clearly identified and

Y/N Remarks

tagged.

6

All tie-in points and battery limits are clearly identified and tagged and coordinates/elevations are indicated.

7

All lines are identified by line numbers and major locating dimensions & elevation are given.

8

Flow directions and slope symbols are indicated as per the P&IDs.

9

All secondary pipe supports (standard & special) are indicated and tagged and the locating dimensions marked.

All primary pipe supports are identified by appropriate 10 symbols (e.g. guide, axial stop, etc.). Laydown/dropdown areas, space for exchanger tube 11 removal and maintenance access areas are identified. All buildings/shelters/technological structures are located with 12 coordinates/dimensions. Names/tag nos and overall dimensions are given. Structural grid numbers of pipe 13 racks, buildings and shelters are shown. Piperacks and sleepers are shown with locating 14 coordinates/dimensions, widths, TOS elevations and tag numbers (if applicable). The cross sections of piperacks, multi-level technological 15 structures, culverts, etc., are shown wherever required. All platforms and ladders/staircases are located 16 with dimensions and elevations are marked. DRAFTING The drawing border conforms to the Project specifications or 17 Company standards, as applicable. Drafting conventions e.g. font types/sizes, text styles, line types, coordinate/dimension 18 styles, layer structure, etc. are as per the Project specifications or Company CAD standards, as applicable. Drawing title, drawing number 19 and revision number in the title block are as per the TDR.

Electronic file name is indicated 20 at appropriate location on the drawing. Revision block contains initials of the originator, checker and 21 approver (both Discipline & Project). Drawing scale is stated in the 22 title block and graphic scale (bar scale) is shown. The drawing scale conforms to the Project specifications or 23 Company standards, as applicable. All general notes are checked and the units for dimensions, 24 coordinates & levels are given in the notes. Legend for applicable symbols is shown (e.g. pipe supports, 25 new/existing facilities, demolition, scope cloud, etc.). Reference drawing numbers and titles are listed and 26 checked. List shall include unit plot plan and piping key plan as a minimum. 27

Status stamp (e.g. “For Construction”) is shown.

Revision clouds, along with 28 revision number triangles are marked properly, if applicable. “Hold” clouds, if applicable, are 29 properly marked and the list of “Holds” is indicated. Key plan is shown and the 30 applicable area/unit of the plot plan is highlighted. Match line co-ordinates and drawing limits are clearly marked and are consistent with 31 the Key Plan drawing. Continuation drawing numbers are correctly written. 32

Drawing extracted from 3D CAD model is not manually edited. Back Prepared Checked Checked By By By

Final Checked By

Name: Designation: Revision number: Date:

Guidelines for Acoustic Induced Vibration (AIV), Flow Induced Vibration (FIV) Analysis

Introduction The scope of this topic is to define the design criteria and guidelines to be used for Design & Supporting for lines prone to Acoustic Induced Vibration (AIV) & Flow Induced Vibration (FIV), especially with regard to small bore connections, in line with EI (Energy Institute) Guide lines. This topic does not address lines subjected to other types of vibrations, such as vibrations due to pulsation, mechanical excitation, wind, earth quake etc. 

High Frequency Acoustic Excitation more commonly referred to as Acoustic Induced Vibration (AIV).



Flow Induced Turbulence more commonly referred to as Flow Induced Vibration (FIV).

Abbreviations AIV       Acoustic Induced Vibration DLF       Dynamic Load Factor EI        Energy Institute FIV       Flow Induced Vibration LOF       Likelihood of Failure NPS       Nominal Pipe Size IFC       Issued for construction SIF       Stress Intensification Factor SBC      Small Bore Connections TPI       Third party Inspection

References Energy Institute (EI) Guide lines: Guide Lines for the Avoidance of Vibration Induced Fatigue Failure in Process Pipe Work. ASME B31.3: Process Piping

Description of Activities 4.1  Acoustic Induced Vibration a)  Acoustic Induced Vibration – AIV Definition

Acoustic Induced Vibration (AIV) is generally applicable to lines in gas service. In a Gas System, high levels of high frequency acoustic energy can be generated by a pressure reducing device such as a Relief valve, Control valve or Orifice plate. The amplitude of this energy is governed primarily by the Flow rate & Pressure drop. Excitation due to this can lead to fatigue failure of welded downstream connections. Piping downstream of Pressure reducing devices as below is prone to Acoustic Induced Vibration AIV.     

Relief Valves. Blow Down valves & Restriction Orifices. Pressure reducing Valves. Compressor recycle Valve. Choke Valve.

b) Impact of Acoustic Induced Vibration – AIV

Acoustic Induced Vibration can lead to Fatigue failure at Small Bore branches. c)  Mitigation of Acoustic Induced Vibration – AIV

Detailed Acoustic Induced Vibration – AIV study shall be carried out by AIV Consultant based on the Multidiscipline responsibility Matrix as per Appendix-1. The study recommendations shall be incorporated in the design of Piping Systems. Generally the study recommendations will be available at a later stage of the Project. In order to minimize the modifications due to Acoustic Induced Vibration AIV Consultant’s recommendations, the following guidelines shall be followed during initial design of lines prone to AIV. 

Process to identify Acoustic Induced Vibration AIV Prone lines in Line list, at early stage of the Project.



A separate Pipe Class may be used for Flare system.



Generally after Acoustic Induced Vibration AIV study, the Consultant comes up with typical recommendations such as increase of Pipe wall thickness particularly, for low wall thick Flare lines, Sweepolet branch fitting in place of weldolet, forged lateral/ 90 Deg Tee in place   of stub –in lateral/ 45 Degree connections, Full encirclement pad for supports at PSV outlets etc. In case of reinforced Stub-in connection, consideration shall

be given to Clause 304.3.5 (b) of ASME B31.3 regarding use of Tee fittings or complete encirclement types of reinforcement for branch stub-in connection.

As this will have impact on material procurement & design, the study shall be expedited & provision for incorporation of such recommendations shall be kept to the extent possible in preliminary piping design itself. 

For high energy level PSVs like Slug Catcher/ Export Line PSVs, in low wall thick piping, D/T (Diameter/Thickness) ratios of pipes shall be reviewed & D/T