23 replies to this topic

[neel_avi]

Dear Experts,

 

Back ground - I am having a debate with my colleagues regarding the below mentioned facility. 

 

A running pipeline (PIPE-A) has a design pressure of 106 barg (about a kilometer in length) and is going to get connected to its downstream with another existing pipeline (PIPE-B at a design pressure of 98 barg (1700 kilometer).  - The reason for such a connectivity - transporting natural gas from offshore pipeline (PIPE-A) to cross country pipeline (PIPE-B ). As obvious since the pressures are dissimilar, a protective mechanism should be introduced to prevent failure of PIPE-B which is at a lower design pressure. A suggestion for a slam shut valve, a pressure regulator with a redundancy (as in any custody transfer line), has been provided by the consultant along with a creep relief valve (designed to operate for a flow of 1% of the total pipeline flow).

 

It may be noted that the facility doesnot have any equipment or vessel other than a filter separator which is located almost a kilometer downstream from where PIPE-B starts. 

 

My contention with my colleagues and consultant was that a relief valve for the full flow needs to be installed the above overprotection system along with creep relief doesnot serve the purpose of ultimate safety. 

 

I have referred to a previous posts, but need a specific direction. Is it that it depends on the client or owner how they perceive the safety system? 

 

Please guide. 

 

Regards

 

Avijit

Edited by neel_avi, 16 April 2013 - 05:19 AM.

[shan]

Owner.  But who is the client?  Is the owner is your client?

[neel_avi]

Mr. Shan,

 

In this case we have to decide as the owner and thus the client. Can I request for some inputs or experiences on basis of which we can arrive at a conclusion about what we require and what we dont. 

 

regards

 

Avijit

Edited by neel_avi, 16 April 2013 - 06:48 AM.

[ankur2061]

Avijit,

 

You can think of providing a instrumented HIPPS or OPPS system in the form of a shutdown valve with SIL level of 3 and with a triple overpressure sensor redundancy to have a 2oo3 voting system to prevent spurious shutdown. Open a discussion with an experienced instrument engineer for the feasibility of providing such a HIPPS system.

 

The reliability of HIPPS systems has increased tremendously in the last few years and they have been gaining popularity considering that environmental concerns of release from relief valves and flares to the atmosphere have taken center stage in many parts of the world.

 

Regards,

Ankur

[Erwin APRIANDI]

Hi neel_avi,

 

In any pressure break interface, you have to make sure that the lower pressure side is adequately protected.

This can be achieve by having a pressure relief, or a HIPPS.

 

If a pressure relief is selected, you have to determine the max possible flowrate in order to correctly specifiying a relief valve which can overcome the max possible flowrate.

 

You also have to ensure that if a relief valve is preferred, no restriction in the relief line or possibility of being isolated.

 

Moreover, you have to ensure that the backpressure during reilef in the pressure break interface (if relief valve is used) is not more than the allowed pressure of the lower pressure side.

[neel_avi]

Dear Mr. Ankur and Mr. Erwin,

 

appreciate the feedback and thanks for the direction. Avoidance of a relief valve however, is not possible in application of HIPPS even - isn't that so?

 

Here the case is that we want to safeguard the system with a typical  gas pipeline metering skid assembly a PID of which I am attaching along with this post for further clarity. This is indeed the preliminary drawing provided to us over which the debate started. It seems, its solely me who has a problem with the scheme provided. 

 

I tried to look for technical sources for creep relief valves and found some. However, the effectiveness of relieving of 1% of entire load during a relief requirement against a relief of entire load intrigues me. 

 

Will keep the forum updated once a final decision is taken, however, would be happy to receive fresh suggestions on basis of the attachment provided. 

 

Thank again for your valuable time.

 

Regards

 

Avijit

Attached Files

•  PID.png   439.84KB   73 downloads

Edited by neel_avi, 17 April 2013 - 02:22 AM.

[ankur2061]

Avijit,

 

Unless your company policy states that it is mandatory to have an ultimate safeguard as a mechanical relief device, I don't see any reason for having a mechanical relief device as an ultimate safeguard. 

 

As I mentioned, the reliability of instrumented HIPPS system has increased tremendously in the last few years and many companies have started adopting HIPPS as an alternative to mechanical relief devices.

 

In fact HIPPS system have in vogue in the chemical process industry since long and specifically for those plants and units where highly toxic and flammable chemicals are being manufactured and any emission to the environment cannot be permitted. Also plant and units that use or manufacture chemicals that are sticky / gummy and can tend to solidify have no alternative but to use HIPPS system since a mechanical relief device can get plugged or choked endangering the safety of the equipment and the personnel.

 

If you are seriously interested in adopting a HIPPS system then you will require to do quite a bit of background study. They work well and reliably if sound engineering practices are adopted and can be used as an ultimate safeguard instead of a mechanical relief device.

 

Regards,

Ankur.

[Zauberberg]

Considering complexity and cost of HIPPS or a full-flow relief valve, it might be worthwile investigating if there is any credible scenario that could lead to exceeding 98 barg pressure in the pipeline with lower design pressure. If such a scenario is not credible, you might as well leave the entire system as it is.

[neel_avi]

Dear Mr. Ankur and Mr. Zauberberg

 

Thanks a ton again for your valuable comments. As an operating company, this organisation had been mysteriously been following the recommendations of the consultant in the past without raising an eyebrow. Present questions to them are disturbing them and as a repurcussion, me as well.

 

Mr. Zauberberg, since the upstream design pressure is greater than the downstream pressure by more than 10%, I am looking for something fullproof, and failure of any of the above  facility in the attached drawing above will cause excess pressure in the downstream pipeline.  

 

Probably we would be going ahead with the recommended scheme as attached above. But before doing that it would be my ethical responsibilty to check the integrity of the system and do any amount of reading and discussion on this. It would be worth. 

 

Thanks again and regards

 

Avijit

[Zauberberg]

Has any scenario leading to pressure excursion above 98 barg in the lower-design pressure section been identified? Is it credible?

[neel_avi]

Dear Mr. Zauberberg,

 

As such I fail to see scenario where the two PCVs and the SSV will fail to work. However, before concluding on that we ned to discuss over the subject matter internally.

 

The fact is that I am not able to get past the idea that PSV should be the last line of defense.

 

Regards

 

Avijit

[Atttyub194]

Dear All
 
Good day!
 
 
The attached P&ID is not very clear. While , designing such a system one should go through following standards which off course defines the minimum requirement for such system

• CSA Z662 General design requirements for pressure control and overpressure protection
• EN 334 - Gas pressure regulators for inlet pressures up to 100 bar
• EN 12186 – Gas Supply systems – Gas pressure regulating stations for transmission and distribution
• EN 14382 - Safety devices for gas pressure regulating stations and  installations - Gas safety shut-off devices for inlet pressures up to 100 bar

In designing a pressure reducing station three main concepts are used as a guideline:

• Safety
• Continuity of Supply
• Environmental impact

One must prioritize , the requirement with respect to acceptable level of each parameters for a given site or the project so that a balanced system could be designed without compromising one objective over the other . Needless to say that giving more emphasis on one objective will definitely  affects the other objectives. Just to explain , adding a slam shut valve will add to safety and environmental impact but reduces the continuity of supply
 
Perceiving the philosophy, I think it would be much better if you have used active pressure regulator (PRC) with Fail open condition and monitor as fail close condition. A regulator is considered Fail Open if in case of an internal failure or a destruction of internal parts, the main valve will open whereas a regulator is considered Fail Close if in case of an internal failure or a destruction of internal parts, the main valve will close.
 
The predictable behavior of a regulator in the case of failure is a key factor to designing a pressure reducing station and allows the to fulfill the requirements of safety and continuity of supply.
 
I would personally prefer to protect the down stream line through PSV with no isolation or two PSV's with lock open arrangement and try to eliminate slam shut valve and reduce the pipeline rating as desired. However, this will totally depends on possible hazard situation in the vicinity , accordingly please review the layout critically
 

According to NFPA 86, 7.7.1.8, “If the inlet pressure to a fuel pressure regulator exceeds the pressure rating of any downstream component, overpressure protection shall be provided.” In other words, if a system designer has selected safety-shutoff valves or other components that are not rated for the fuel-supply pressure upstream of the pressure regulator, some method of preventing an overpressure condition must be added.

However, this statement never eliminates the requirement of PSV as the safety relief valve is designed to reduce temporary pressure surges downstream of the pressure regulator caused by fluctuations in system operations. The set point of a safety relief valve is always lower than the setpoint of the slam-shut valve. In this cases, use of a small vent valve or PSV may serve the purpose. However, such consent is definitely required from local bodies

 

While specifying slam shut, it is to be well understood that a manual reset  is required in addition to intervention for  understanding what happened in the station every time the station trips Additionally, please ensure that the manufacturer perform an impact test in order to guarantee that the valve will not trip, when not required, in case of vibration in the station in accordance with EN 14382
 
For re-engagement of  a slam shut valve  many manufacturers publish by what amount of ΔP, the pressure must at least be reduced after an overpressure  release or must at least be raised after an under pressure release to be able to securely reengage
the valve. Where the Valve is designed with  both under and over pressure protection simultaneously, a minimum outlet pressure range must also be maintained
 
If addition of slam shut valve become mandatory. then it is better to use active pressure regulator (PRC) with Fail close condition and monitor as fail open condition as this will further enhance safety and reduces continuity to some extent
 
 
 
Best regards and God Bless you

 

 

 

Edited by Attyub194, 19 April 2013 - 09:06 PM.

[neel_avi]

Dear Mr. Attyub,

 

thank you for the advice. 

 

I always thought that the regulators fail because of the failure of the mainline pressure getting transmitted to the spring of the regulator for its action. 

 

regards

Avijit

Edited by neel_avi, 21 April 2013 - 11:39 PM.

[bpc]

Dear Attyub,

 

The arrangement suggested by your consultant is typical PRS (Pressure Regulating skid) and is typical in Consumer reciept station (in middle east).

 

In this Two rungs of 2 x 100% capacity pressure regulation system is provided in parallel rungs each having inlet isolation valves (typically MOVS in consumer reciept stations), Self actuated slam shut valve (PV-X01 & X02), Monitor regulator (PCV-X01 & X02), Active regulator (PCV-X03 & X04) and safety valves (PSV-X01 & X02). However, both the rungs will be online all the time except in cases of maintenance on either of the rungs and inlet isolation valves thus are in Locked-open condition.

 

All the self actuated control valves and slam shut valves have staggered set points to provide redundancy as well as reliability. At one time only one PCV will be controlling the pressure with other three PCVs will be in hot standby position. Hence possibilty of complete system failure is not considered. `

 

PSVs sized for low flow typically 5% of the inlet flow. They are not sized for the full relief as there purpose is just to avoid frequent/spurious operation of slam shut valve.

 

Pressure range for control will be operating pressure range. Slam shut valves are provided to close in case of pressure exceeds the maximum allowable pressure. 

 

Regards,

 

 

 

Dear Mr. Attyub,

 

thank you for the advice. 

 

I always thought that the regulators fail because of the failure of the mainline pressure getting transmitted to the spring of the regulator for its action. 

 

regards

Avijit

[jr31]

Hello, Avijit,

I am curious as to finally what you have done & also what is the line size & flow. I have a similar application for a 40 " Gas pipeline with 600 MMSCFD flow & possibly shall use a full flow Pilot operated safety relief Valves. I am trying to find out if I can use modulating pilot , i.e. whether API codes have any restrictions with respect to use of a pop or modulating pilots. (Preliminary size is 8 x 10 Pilot operated PSV with T orifice). Some other issues we still may have to resolve are high Noise ( 135 dB, may use silencer) & Inlet nozzle loss etc.  

One possibility we are considering ids to use multiple valves for lower flow (2 +1 Spare Combination). The Company's first preferences is Mechanical protection over HIPPS systems.

May other members can provide some suggestions!

Rgds

Jagdish

[Atttyub194]

Dear Jagdish

 

Good day

 

Could you elaborate your concerns and share some P&ID and schematic so that we can give you some sugession

 

Best regards and God Bless You

[neel_avi]

Dear Mr. jagdish,

 

we are in the process of selecting the scheme. However, I liked the concept of application of HIPPS as told by Mr. Ankur and Mr. Zauberberg, although post no 8 by Mr. Zauberberg also excites me. As promised earlier, I will definitely share the final outcome. 

 

Regards

Avijit

[chemsac2]

Since this application is about pipelines, I am not sure if systems that we typically use for ASME section VIII or ASME B31.3 would be relevant.

 

ASME 31.8 which is about gas pipelines has following on protection of mains:

"845.22 Control and Limiting of Gas Pressure in High-Pressure Steel, Ductile Iron, Cast Iron, or Plastic Distribution Systems

845.221

Each high-pressure distribution system or main, supplied from a source of gas that is at a higher pressure than the maximum allowable operating pressure for the system, shall be equipped with pressure regulating devices of adequate capacity and designed to meet the pressure, load, and other service conditions under which they will operate or to which they may be subjected.

 

845.222

In addition to the pressure-regulating devices prescribed in para. 845.221, a suitable method shall be provided to prevent accidental overpressuring of a high-pressure distribution system. Suitable types of protective devices to prevent overpressuring of high-pressure distribution systems include

(a) relief valves as prescribed in paras. 845.212(a) and (

( weight-loaded relief valves

© a monitoring regulator installed in series with the primary pressure regulator

(d) a series regulator installed upstream from the primary regulator and set to limit the pressure on the inlet of the primary regulator continuously to the maximum allowable operating pressure of the distribution system or less

(e) an automatic shutoff device installed in series with the primary pressure regulator and set to shut off when the pressure on the distribution system reaches the maximum allowable operating pressure or less. This device must remain closed until manually reset. It should not be used where it might cause an interruption in service to a large number of customers.

(f) spring-loaded, diaphragm-type relief valves"

 

 

Thus, a regulator (c above) or a shut-off device (e above) is sufficient protection and PSV is not necessary. Creep valve is installed to prevent overpressurization of downstream during periods of low flow.

 

In any case, blocked outlet scenario would lead to line packing which may take much longer to reach design pressure.

 

Regards,

 

Sachin

Edited by chemsac2, 29 April 2013 - 12:53 PM.

[jr31]

Thank You all for Feedback.

 

The proposed system supplies Gas to a Customer via app 40 km long pipeline. The Piping system at Customer end is designed for MAOP of 55 Bar however Customer does not want the supply Pressure to exceed more that 50 Bar at any point of time. The Gas shall be supplied through a metering skid and we can possible design Control valves such that Max pressure at Customer's end shall be 50 bar or less. However In addition to main source we also have an alternate source (jumper Line) where the pressure can go to 55 Bar & hence we need to consider a pressure reduction to restrict the supply pressure to 50 Bar & provide a PSV as an additional safety protection. The customer already has a pressure reducing station in his battery limit to regulate pressure to suit their requirement, However as already pointed out before We like to restrict the Pressure to 50 Bar at customer end. Maintaining supply is one the prime requirement & hence we are considering a fail open control valve which possibly can be ball Control valve to maintain around 50 Bar max at outlet of control valve & a modulating Pilot Safety valves (could be 2 in line +1 standby. However On preliminary calculations I note very high noise level. In addition we were concerned about inlet pressure drop.

I understand API is in the process of reviewing API 520 in regards to 3% drop & one of the solutions is to consider remote sense for Pilot Valve to reduce impact of any nozzle pressure drop.

 

I would welcome alternate solutions/suggestions. Any ideas on how to take care of High noise, I think we have restricted this Max 110 dB (for intermittent service). I believe use of modulating pilot should work like a creep as venting is expected to be proportionate to excess pressure in the system.

 

The Upstream system has no overpressure issues due to much higher design pressure,

 

Thanks for all suggestions

 

Jagdish

[Atttyub194]

Dear  All
 
Good day!
 
The ASME Code B31.8 covers the design, fabrication, installation, inspection, and testing of pipeline facilities used for the transportation of gas. This Code also covers safety aspects of the operation and maintenance of those facilities. Detailed scope is described in  Appendix Q '
I will be obliged if same is referred before using interpretation of the code. For convenience , it may be noted that the code does not apply to :

• Design and manufacture of pressure vessels covered by the BPV Code or ASME Boiler and Pressure Vessel Code
• Piping with metal temperatures above 450°F (232°C) or below −20°F (−29°C) (For low temperature considerations, see para. 812.)
• Piping beyond the outlet of the customer ’s meter set assembly (Refer to ANSI Z223.1/NFPA 54.)
• Piping in oil refineries or natural gasoline, extraction plants, gas treating plant piping other than the main gas stream piping in dehydration, and all other processing plants installed as part of a gas transmission system, gas manufacturing plants, industrial plants, or mines (See other applicable sections of the ASME Code for Pressure Piping, B31.)
• Vent piping to operate at substantially atmospheric pressures for waste gases of any kind
• Wellhead assemblies, including control valves,flow lines between wellhead and trap or separator, offshore platform production facility piping, or casing and tubing in gas or oil wells (For offshore platform production facility piping,refer API RP 14E.)
• The design and manufacture of proprietary items of equipment, apparatus, or instruments
• The design and manufacture of heat exchangers
• Liquid petroleum transportation piping systems (Refer to ASME B31.4.)
• Liquid slurry transportation piping systems (Refer to ASME B31.11.)
• Carbon dioxide transportation piping system
• Liquefied natural gas piping systems (Refer to NFPA 59A and ASME B31.3.)
• Cryogenic piping systems

Coming back to the subject, one may apply the referred code for design of the subject let down station, however, interpretation done by one of our college is not correct and probably he may have not gone through complete requirement of code . Therefore, I felt it is essential to elaborate the requirements so that any limited or partial application would not lead to a hazardous situation / design /or its use by any body resulting ina  safety incident
 
First of all , I would suggest to please refer 845.1 " Basic Requirement for Protection Against Accidental Over pressuring" which idicates that every pipeline, main, distribution system, customer’s meter and connected facilities, compressor station, pipe type holder, bottle-type holder, containers fabricated  from pipe and fittings, and all special equipment, if connected to a compressor or to a gas source where the failure of pressure control or other causes might result  in a pressure that would exceed the maximum allowable operating pressure of the facility (refer to para. 805.2.1), shall be equipped with suitable pressure-relieving or pressure-limiting devices. Special provisions for service regulators are set forth in para. 845.2.7 "
 
Therefore, we can not over rule requirement of relief valves or safety devices
 
Additionally, please refer 845.2.1, " Control and Limiting of Gas Pressure in Holders, Pipelines, and All Facilities That Might at Times Be Bottle Tight "   which states that " Suitable types of protective devices to prevent over pressuring of such facilities include:
 

(a) Spring-loaded relief valves of types meeting the provisions of BPV Code, Section VIII

( Pilot-loaded back-pressure regulators used as relief valves, so designed that failure of the pilot system or control lines will cause the regulator to open

 

© Rupture disks of the type meeting the provisions of BPV Code, Section VIII, Division 1

 

Before going into further discussion, I am referring the same para 845.2.4 as referred by one of our college as such 
 
a. " Each high-pressure distribution system or main, supplied from a source of gas that is at a higher pressure than the maximum allowable operating pressure for the system, shall be equipped with pressure-regulating devices of adequate capacity and designed to meet the pressure, load, and other service conditions under which they will operate or to which they may be subjected.
 
b. In addition to the pressure-regulating devices prescribed in para. 845.2.4(a), a suitable method shall be provided to prevent accidental over pressuring of a high pressure distribution system.
 
Suitable types of protective devices to prevent overpressuring of high-pressure distribution systems include

• Relief valves as prescribed in paras. 845.2.1(a)

and (

•  
• weight-loaded relief valves
• a monitoring regulator installed in series with the primary pressure regulator
• a series regulator installed upstream from the primary regulator and set to limit the pressure on the inlet of the primary regulator continuously to the maximum allowable operating pressure of the distribution system or less
• an automatic shutoff device installed in series with the primary pressure regulator and set to shut off when the pressure on the distribution system reaches the maximum allowable operating pressure or less. This device must remain closed until manually reset. It should not be used where it might cause an interruption in service to a large number of customers.
• spring-loaded, diaphragm-type relief valves

Careful review of the above para do not give any indication for over ruling the requirement of relief valves or safety devices . However, such provision is available for service regulators under 845.2.7  with limitation of  maximum allowable operating pressure of the distribution system to 60 psig (410 kPa) or less and regulator connection to 2" NPS. This provision is not available for the referred case
 
Please go through " Control and Limiting of the Pressure of Gas Delivered to Domestic, Small Commercial, and Small Industrial Customers From High-Pressure Distribution Systems para 845.2.7
 
Regarding slam shut valves as described earlier that requirement of  safety relief valve can not be eliminated, however, it may be  designed to reduce temporary pressure surges downstream of the pressure regulator caused by fluctuations in system operations. The set point of a safety relief valve is always lower than the set point of the slam-shut valve.In this cases, use of a small vent valve or PSV  may serve the purpose . However, such consent is definitely also required from local bodies /  Authorities.
 
Hope I may have clarified the requirements
 
Best regards and God Bless you
 
Ahmed Attyub

Edited by Attyub194, 01 May 2013 - 01:33 AM.

[Atttyub194]

Dear Jagdish
 
Good day!
 
Please attach a sketch for understanding  by all members. For proper sizing, the maximum pressure from where the gas need to be letdown must be known, which in not specified
 
I have designed similar systems and based on my experience I may suggest the following as preliminary guidelines:

• Please do check for hydrate formation as the gas temperature will definitely reduce after let down
• To avoid damage of the valve please limit the noise level to 100 dBA.
• You may have options of purchasing valves from different manufacturer , however, please do realize each manufacturer has some area of specialty and we as designer should use this area to get an optimum solution
• Use T-ball series of Dresser Becker instead of simple ball valve will definitely gives some relief 
• Additionally, some time you may considerably reduce noise by increasing the schedule of down stream piping upto 15-20. It may be noted that as per piping specification increase in schedule is not required

Generally, regulators  may be operated upto 105 dBA without damage . however, beyond you this limit frequent problems/ failure observed  due to flow induced vibration in internals of regulators
 
At the end , I would suggest to share relevant information including sizing sheet for regulators for better suggestion by all members

 
Best regard and God Bless you

 

Ahmed Attyub

Edited by Attyub194, 01 May 2013 - 04:15 AM.

[neel_avi]

Dear Mr. Atyub and Chemsac2,

 

thanks for your inputs. As Mr. Atyub says I too agree with his views on ASME 31.8 - 854.2.1 which do not talk about the boundary limits and genralise it by saying "Suitable types of protective devices to prevent over pressuring of such facilities include:

a....

b....

c... and so on.

 

Furthermore, the interconnection of the two lines is the lifeline to the entire pipeline network customers. 

 

I had raised the query in order to know the general practice around the world and to put my idea as in front of my experienced colleagues. 

 

regards

 

Avijit

[jr31]

Hello Guys,

 

Here is the Sketch of the Scheme. As previously mentioned Cotrol Valve with with modulating POSV is one of the options I am considering. However this is open to suggestions. But have to Follow ASME B31.8 as Protection Basis,

 

Thanks to all for all comments<

 

Cheers!

 

Jagdish

Attached Files

•  GasDeliveryScheme.pdf   304.26KB   86 downloads

[rajputg]

Dear Mr Ayttub,

 

I have a quqestion is it manadatory to provide slam shut off valve(safety shut off valve) for gas metering skid. Client asks us to provide slam shut off valve for each metering skid.

Metering skid has been designed with two regulators in active, monitor configurtaion with separate redundant safety relief valve.

As already stated above, set point of slam shut off valve is set higher than the setpoint of safety relief valve, slam shut off valve will not be operated at all. All the time safety relief valve will operate on pressure excursions.

 

Query : Is it manadtory to provide slam shut off valve for metering skid per AMSE B31.8 ? Is it code requirement? Please let me know with code reference. I tried to go through the code but i couldn't find it.