21 replies to this topic

[Christiano]

MAOP inputs on PIPELINE pls..

Edited by Raj India, 26 April 2013 - 03:01 AM.

[ankur2061]

Raj,

MAOP will not change along the pipeline route. The margin you will need to consider should consider the elevation changes along the pipline route. In other words, consider the MAOP based on the worst operating conditions of high pressure.

Another approach could be that if you have already decided the pound rating (600 or 900#) of the pipeline then based on the maximum operating temperature you can determine the pressure rating in terms of the MAWP or Design pressure as per the tables for pressure-temperature rating given in ASME B16.5- Pipe Flanges & Flanged Fittings.

Hope this helps.

Regards,
Ankur.

[Christiano]

Ankur, many thanks for your valuable inputs..I shall incorporate the same in to the design.

To make my understanding more clear, shall I ask if my below understanding is correct.

MOP for any reference point is Pump discharge pressure-frictional losses for the line from pump to the reference point + hydrostatic head difference. The worst MOP shall be considered and margin added to define the MAOP or design pressure.

[ankur2061]

Raj,

The MOP for any reference point on the pump discharge circuit should be:

MOP = Pump discharge pressure at the design or rated flow - dynamic losses (includes losses in discharge piping and pressure drop in any in-line equipment) ± Static head at the reference point (plus if the reference point is below the pump discharge nozzle centreline and minus if the reference point is above the pump discharge nozzle centreline)

Regards,
Ankur.

[paulhorth]

Raj,

You have ten pumps in series. Imagine the pressure profile along the pipeline, when operating with normal flowrate. The profile will be a sawtooth shape, with pressure at each pump discharge being high, then declining along the line due to friction, to the suction of the next pump. Superimposed on this profile is the static head variation.
Now consider a flow shutdown.The pumps will probably continue to run, on recycle.However the pressure profile now is different, because there is no longer the downward slope of the sawtooth due to friction loss since there is no flow. Each pump will raise the pressure by its differential at its running point, so that along the length, ten differential pressures will be added, but there will be no friction losses. This results in a very high pressure at the outlet end of the line, regardless of the static head (which of course is not affected by loss of flow). Much higher than the normal operating pressure at this point.

I admit this result seems unrealistic and there may be a factor which I have not properly understood. But unless you have safeguards - all the pumps are either shut down or isolated from the pipeline when there is a flow shutdown, or there are break tanks at each pumping station - I think this scenario should be considered. Add the ten differentials together.

Paul

[Therm]

What is difference between MAOP AND DESIGN Pressure of Pipeline.

[ankur2061]

vimalananth,

For the definition of MAOP refer what /i have written in the link below:

http://www.cheresour...3875#entry53875

MAWP (Maximum Allowable Working Pressure) and Design Pressure (DP) are terms used interchangeably many a times. However, some codes and standards provide a distinct differentiation between the two. It is also important to note that a mechanical engineer's vocabulary has only MAWP whereas a process engineer uses the term DP.

Let us illustrate it in the following manner. A process engineer starts the design process of any system. He or she decides a limit for the MAOP of the system and then provides some margin on the MAOP. This margin could be based on his or her company's engineering standards or based on the client's standard. Let us say he or she provides a margin of 20%. After providing the margin the value he or she arrives at, is what he or she calls it as a "Design Pressure". As an example of a system let us consider that a process engineer has arrived at the DP of a pressure vessel. The next step in the designing of a vessel is that the information related to the pressure vessel in the form of a process data sheet goes to the mechanical engineer doing mechanical design of the vessel. The mechanical engineer keeping in mind the DP value provided by the processs engineer does mechanical calculations to determine the thickness of the vessel walls. Let us consider that the mechanical engineer has arrived at a vessel shell thickness of say 5.8 mm corresponding to the design pressure provided by the process engineer. Commercial steel plates used in vessel fabrication are of standard thicknesses. Let us say that a commercial steel plate of 6 mm is easily available in the market. The mechanical engineer then decides that he will use a 6 mm thick plate for fabrication of the subject vessel. He can then back calculate the pressure that the vessel can withstand using the 6 mm thick plate. This pressure is what he calls as the MAWP.

In the example provided above it may be noted that the MAWP as arrived by the mechanical engineer is greater than the DP given by the process engineer. Most real life examples will show that the MAWP as arrived by the mechanical engineer is greater than the DP provided by the process engineer

There may be rare occasions where the calciulated MAWP by the mechancial engineer will be the same as the DP but this generally an exception.

The above explanation could also be applicable to a pipe. The DP of the pipe as determined by the process engineer and the MAWP determined by the piping engineer could either be the same or the MAWP could be greater than the DP with the latter being more common in real life.

For piping ASME B16.5 can be followed in determining the MAWP of the pipe. ASME B16.5 - Pipe Flanges and Flanged Fittings provides pressure -temperature charts for different pipe materials based on the pound rating of the pipe. Using the maximum operating temperature the corresponding MAWP for a given pound rating (150, 300, 600, 900, 1500, 2500#) can be read from the chart.

Regards,
Ankur.

[paulhorth]

Ankur,
I agree completely with everything you say in the last post.

I would like to draw the attention of the forum to the point I made in Post no. 5, concerning the design pressure (and MAWP) required when having ten pumps in series in this pipeline.
Does anyone have any comments on this?

Paul

[Christiano]

Paul,

i would like to state the combination of 10 pumps acting together is a very uncommon scenario as there is overpressure protection systems provided for every pump stations/pressure reducing stations. I guess relief valves of design flow capacity can solve this scenario as in a short time all pumps shall be emergency shut down. I guess this would be enough, comments pls...

[kkala]

Some additional notes on the topic:
1. Design pressure versus MAWP. See details (and example) at http://www.cheresou...ating-pressure/.
In early project stages, MAWP and design pressure (DP) are according to post of 11 Dec 2011(by Ankur2061). Nevertheless any difference between MAWP - DP is judged to be invalid after the hydrostatic test of the vessel or piping. If the system is designed for (say) 50 barg, constructed for 52 barg and certified for 46 barg according to hydrostatic test, its design pressure or MAWP is 46 barg. Higher design pressure cannot be accepted, unless proven through a new hydrostatic test. The latter can be conducted on field (upgrading), in case that new conditions require somehow higher design pressure.
Hydrostatic test is conducted at ambient temperature. For higher design temperatures, tensile strength decreases, thus test pressure is accordingly increased to certify given design pressure. Link (http://www.onetb.com...ance-t1062.html ) also indicates that test pressure is accordingly increased to compensate for the extra thickness of corrosion allowance. Thus design pressure or MAWP is valid at design temperature and af if corrosion allowance thickness were "cut" from actual thickness.
Opinion on the above would promote clarification on the matter, believed to be of general interest.
2. Concept of successive shutoff pressures. See more details in the post of 11 Dec 2011(by paulhorth).
α. Crude oil pipeleine. Assuming there were no PRVs along the 1400 km line (neither atmospheric suction tanks), concept (reverse sawtooths changed into horisontal lines placed higher and higher) could occur on closing a valve downstream last pump. Considering ΔPf=0.1 psi/100 ft and neglecting static heads (for simplicity), overall frictional pressure drop in full flow would be 323 kgf/cm2. Just upstream mentioned valve pressure could be 1.15*323 = 370 kg/cm2 g. These pressures are excessive and far beyond design pressure of 79.2 barg, so pipeline has to be protected otherwise from overpressure . For instance, Saudi Aramco local pipeline seems to have installed PRVs discharging into surge relief tanks http://www.psig.org.../1990/9202.pdf . These PRVs cover the numerous cases of surge too, probably including case of mentioned valve closure. Event of PRV opening rarely happens, due to a sophisticated SCADA system acting on the DCS of every station.
β. Gas pipeline. Even for gas, surge analysis by software is necessary, as local NG practice indicates.

Edited by kkala, 14 December 2011 - 06:14 PM.

[ankur2061]

The hydrotest pressure does not become the Design Pressure or MAWP of any pipeline after the hydrotest. No standards related to piping or pipeline support this including:

ASME B31.4 - Pipeline Transportation for Liquid Hydrocarbon and Other Liquids

ASME B31.8 - Gas Transmission and Distribution Piping Systems

ASME B31.3 - Process Piping Design

The design pressure or MAWP for any pipe is a calculated value based on the yield strength of the pipe material with different equations used to calculate them for all the three standards above. Refer the link below for these equations:

http://pipingdesigne...Tips/piping.pdf

For pipelines a most common material used is API 5L and API 5LX.

As a sidenote it is not compulsory nor it may be feasible to do a field hydrotest for long pipelines installed in remote and environmentally hostile terrain. If you are buying grades of pipe such as the ones mentioned above they usually come with test certificates indicating shop hydrotest which can be relied upon.

Whatever is mentioned above is in context to pipelines and piping and does not have anything to do with pressure vessels.

Regards,
Ankur.

[kkala]

Below are comments on the post of 15 Dec 2011 by ankur2061, on issues about hydrostatic test, MAWP, design pressure (DP) of piping. Reference is made to link http://pipingdesigne...Tips/piping.pdf reported in above mentioned post, actually being a Practical piping course. I believe the matter needs still investigation, which is worthy.
The hydrotest pressure does not become the Design Pressure or MAWP of any pipeline after the hydrotest. No standards related to piping or pipeline support this including:
ASME B31.4 - Pipeline Transportation for Liquid Hydrocarbon and Other Liquids
ASME B31.8 - Gas Transmission and Distribution Piping Systems
ASME B31.3 - Process Piping Design
Required DP specifies hydrotest pressure, being at least 50% higher. Purpose of hydrotest is to prove that DP is valid, under given design temperature and corrosion allowance.
The design pressure or MAWP for any pipe is a calculated value based on the yield strength of the pipe material with different equations used to calculate them for all the three standards above. Refer the link below for these equations: http://pipingdesigne...Tips/piping.pdf
Process reasons specify DP, not vice versa. MAWP can be based on selected piping components though. Piping is an assembly of components (para 1.1). MAWP is defined by the weakest of them. Strength of single pipe parts is usually adequate for much higher pressure.
Formula P=2*S*t/D*F*E*T (page 30) may merely express relation between DP (named P) and pipe wall thickness (named t), without meaning that DP is defined by t. DP is specified (e.g. by max pump shutoff pressure), then thickness t is calculated as a minimum requirement.
For pipelines a most common material used is API 5L and API 5LX. Noted.
As a sidenote it is not compulsory nor it may be feasible to do a field hydrotest for long pipelines installed in remote and environmentally hostile terrain. If you are buying grades of pipe such as the ones mentioned above they usually come with test certificates indicating shop hydrotest which can be relied upon.
Not aware of piping codes (local Process Dept does not deal with them), cases of installed piping not hydrotested has not been seen. Even if all piping components are certified for adequate design pressure (not limited to pipe parts), mounting has to be checked on field. Leakages from flanges or welds are frequently observed. Long pipelines are separated into smaller isolated ones, to be hydrotested.
Whatever is mentioned above is in context to pipelines and piping and does not have anything to do with pressure vessels.
Noted. For ambient design pressure hydrostatic pressure is 1.5*design pressure (not valid for vessels nowadays).

Regarding the example of 50, 52, 46 barg reported (say for a piping case) in the post of 14 Dec 11 by kkala (1st part), let us say it more precisely: Design pressure hydrostatically proven is 46 barg. New conditions impose a design pressure of 50 barg. Pipeline constructed (but not tested) for a design pressure of 52 barg. The question is, can we consider 50 barg as design pressure? I believe not, unless a new hydrotest has been conducted to evidence design pressure of 50 barg. Pressure differences (50, 52, 46 barg) can be greater than indicated in the example.
At any case MAWP has no meaning, going beyond the test-evidenced DP. Any value higher than what test has proved is only an hypothesis that needs testing to get valid.
Above view has not been found in writing. But I understand this represents applied local practice, more or less. Comments or advice would be appreciated.

Edited by kkala, 15 December 2011 - 06:59 AM.

[ankur2061]

I have really no intentions to reply to the post above since it is opinionated and has no grounds (no international standards or practices provided as reference or evidence) and only talks of the ubiquitous "local practice" about which I have already written in my blog entry at:

http://www.cheresour...ineering-forum/

I have also mentioned that engineering is based on international and well recognized practices in the form of codes, standards, recommended practices and design guidelines.
I personally would never make a statement regarding any engineering or design practice if I could not back it up by evidence. I would also consider it as irresponsible for anyone to provide opinion on engineering and design issues based on one's own perception of how engineering design should be.

Ankur.

Edited by ankur2061, 15 December 2011 - 07:11 AM.

[kkala]

I have really no intentions to reply to the post above since it is opinionated and has no grounds (no international standards or practices provided as reference or evidence) and only talks of the ubiquitous "local practice" about which I have already written in my blog entry at: http://www.cheresour...ineering-forum/ I have also mentioned that engineering is based on international and well recognized practices in the form of codes, standards, recommended practices and design guidelines.
I personally would never make a statement regarding any engineering or design practice if I could not back it up by evidence. I would also consider it as irresponsible for anyone to provide opinion on engineering and design issues based on one's own perception of how engineering design should be. Ankur.

A rather objective style helping communication in Engineering is preferable, developing specific arguments on the points. Otherwise correct answer is not revealed. Topic does not seem to have settled by the first para of post No 11 (by ankur2061, 15 Dec 2011). Post No 12 (by kkala,15 Dec 2011) tries for the correct answer and tries to follow mentioned principle. Characterizations, such as those in the framed box above, are not fair.

[Christiano]

Hi,

In continuation with the above, can any one comment if MAOP and DP has to be above HYDRAULIC gradient line while considering pipelines at higher elevation? Hydraulic gradient is the head of the fluid at 0m elevation.

I am attaching hydraulic profile created for 1 section of a 54 inch line which runs about 640KM through a hilly terrain. My operating pressure is 70 bar and I have kept 77 bar as design pressure for preliniminary estimation. I am attaching one more hydraulic profile (Hprofile-BTC) of another project where MAOP has been kept over HGL.

I am trying to understand why MAOP and DP should be always more than hydraulic grade line whreas hydraulic grade line refers 0 elevation where as actual elevation differences between two reference points would be different.. I felt as per API 31.4 DP shall be more than MOP for any point which is (Line loss till the ref point+hydrostatic head+ back pressure at ref point).

Is hydraulic gradient to be refered or hydraulic grad difference between 2 reference points?

Sorry for sounding not very clear. Hope i have managed to communicate.

Attached Files

•  H-Gradient-Sec-2-52inch.bmp   1.4MB   34 downloads
•  Hprofile-BTC.pdf   246.86KB   83 downloads

[Narayanan.u]

Hi All,

MAOP should be above net hydraulic head. Is it right?

Narayanan

[sheiko]

Raj,
For your information: http://www.red-bag.c...#designpressure

Kkala,
I was involved in precommissioning/commissioning a LNG plant last year and I don't remember having changed the whole project documentation regarding design conditions after hydrotests. The only criteria (not mentionning safety requirements) to validate the hydrotest of piping was to reach the test pressure (at least 130% of design pressure). If the objective was not met, we (the contractor) had to fix the problems (leaking flange, ...) until we succeed...and we did.

Edited by sheiko, 22 December 2011 - 06:20 PM.

[kkala]

From mentioned 130% it is understood, shieko, that a pressure vessel (of design pressure P) was hydrotested, and the test actually proved the validity of P. The question is whether any specified MAWP (generally higher than P) has meaning from now on. I think that now MAWP=design pressure=P. " Any value higher than what test has proved is only an hypothesis that needs testing to get valid". If conditions change in future and the vessel needs a design pressure P1 higher than P, it has to be hydrotested again to prove validity of P1, even if its MAWP had been specified as higher than P1.
Comments - clarifications on this view are of course welcomed.
Reading your web reference, I observe that:
1. Design pressure is based on process conditions, not on thickness of metal (or generally strength of the material).
2. You do not use MAWP (neither do we); or is it defined elsewhere?
3. MOP=MAOP (the term in not used here). MOP can be RP= relieving pressure=1.1*DP. On the other hand PD (understood as DP) = MOP . Do I miss something?

Edited by kkala, 22 December 2011 - 05:50 PM.

[sheiko]

From mentioned 130% it is understood, shieko, that a pressure vessel (of design pressure P) was hydrotested, and the test actually proved the validity of P. The question is whether any specified MAWP (generally higher than P) has meaning from now on. I think that now MAWP=design pressure=P. " Any value higher than what test has proved is only an hypothesis that needs testing to get valid". If conditions change in future and the vessel needs a design pressure P1 higher than P, it has to be hydrotested again to prove validity of P1, even if its MAWP had been specified as higher than P1.
Comments - clarifications on this view are of course welcomed.

Kkala,

I had not read your post carefully enough. Apologies.

In my example, I just wanted to point out that, during an Engineering project, design pressures usually remain the same in the project documentation from the end of detailed Engineering design to Start-Up/Hand-Over. By the way, I was talking about piping hydrotest.

However, once the plant is in operation, it indeed makes sense that validation of a new design pressure (due to re-rating), HIGHER than the one of the original Engineering design, would need field testing and certification. It does make sense, BUT the other question is:
Is it a standard or legal practice somewhere?

Edited by sheiko, 22 December 2011 - 06:52 PM.

[kkala]

Sheiko, you did not say something wrong to apologize. Besides notices and queries help in finding the right answer.

• I have thought so far that piping has to be hydrotested at 150% of design pressure*; equipment at 130%, according to new requirements* (probably since 2005). http://www.cheresour...-vessels-piping. Seen lists for new lines complied with the 150%. So 130% may indicate revision in some code. Do you have some relative information on the pipeline tested (code etc) ?
• By the way, clarification on following matters mentioned in this thread would be welcomed.
  α. Is corrosion allowance considered in hydrotest, which would increase actual test pressure? (refer to post No 10). It may not be so for piping.
  β. MAOP (post 1) seems same as MOP (per attacment of post 17). Can this be higher than design pressure? (refer to post No 18).
  γ. If MAWP has a value higher than design pressure, does MAWP have any meaning after the hydrostatic test? (refer to posts No 10, 11, 12). Successful hydrostatic test verifies design pressure, but no pressure higher than this**. Probably this higher MAWP is only a theoretical indication of how high a rerating could be, to be verified at any case by a new hydrotest. Margins over the already certified design pressure may not be acceptable without test.
• Yes, in a new project design pressures are usually verified through hydrotests with no problem. The question comes in a revamp, when part of equipment / piping has to be rerated for a higher design pressure. Locally, the equipment is first mechanically investigated to see whether it can bear the new design pressure, then a new hydrotest takes place to check its validity. MAWP is not used here as a term. But this hydrotest has not occurred, it will, while available documentation seems quite poor. Local chemical engineers are not specialized in hydrotests, yet some clear basic data would be useful.
  However querie (γ) of above para 2 concerns new projects too.
  
  
  * Note: If design temperature is ambient
  **Note: If hydrotest was based on the value of MAWP, it would seem OK.

Edited by kkala, 23 December 2011 - 11:37 AM.

[sheiko]

Kkala,

I don't have all the answers and I believe this is a difficult subject as european countries such as France, where I'm from and live, don't have to follow ASME code but each country develops its own based on PED (Pressure Equipment Directive). For example, France uses CODAP for pressure vessel and CODETI for piping. I have also noticed that MAWP or "design pressure" terms do not exist as such in PED, but let's keep that for another thread.

Edited by sheiko, 23 December 2011 - 02:57 PM.

[kkala]

Since argumentation has been developed on the subject of design pressure versus MAWP, following can be useful (but queries of recent posts still need clarification).
http://www.cheresour...-pressure-mawp/ '> http://www.cheresour...-pressure-mawp/ ,
http://blog.naver.co...No=140020057824 '> http://blog.naver.co...No=140020057824 .