14 replies to this topic

[kkala]

A pump (max shutoff=24 Barg) will discharge liquid into exchangers (heaters) and then will be connected through a check valve and a manual isolation valve to a header of 36 Barg design pressure (attached sheme.doc indicates it). Design pressure of discharge line is 24 Barg (operating pressure at the connection to header will be 18-19 barg). At first look a PRV set at 24 Barg is indicated on the discharge line, but following queries aim at finding a way to avoid PRV (so PRV is not a way out) and clarify some misunderstandings.
1. The check valve will not "protect" discharge line from 36 Barg design pressure, what about two or more check valves in series (even of different type)? Is there a way to "protect" discharge line from 36 Barg back pressure without PRV?
2. Assuming above is not practically possible, what if the discharge line were successfully rerated to (say) 28 Barg? Exposure to ~29% overpressure will be rare and not for long.
3. To prevent back flow from (36 Barg design pressure header) on pump failure (check valves are not always in order) a cutoff valve has been proposed on the discharge line, to close at low flow. I believe that valves moved by signals (pneumatic or electric) are not recognized as reliable enough by codes. Apart from it, could a closed valve protect discharge line from 36 Barg? What if that valve has tight shut off?
Above is a simplified example taken from a desalter water feed to cold preheat train, but several similar issues are found also elsewhere. Clarifications (if possible with supporting references) would be highly appreciated.

Note: Mentioned design pressure is not related to piping class, but to equipment connected to the pipe.

Attached Files

•  scheme.doc   22.5KB   102 downloads

Edited by kkala, 16 May 2010 - 04:13 PM.

[daryon]

1. I have used two dissimilar check valves to eliminate back flow potential before; but only on small diameter lines and for low differential pressures. However, I have never used series check valves as a sole protection against overpressure.

API Standard 521, 5th Edition 2007 offers some guidance on this:
4.3.4.3. Pressure considerations for single check-valve leakage &
4.3.4.4. Pressure considerations for series back-flow prevention

Basically if you can guarantee inspection and maintenance to ensure the check valves operate reliably to stop backflow then you don't need other devices to stop backflow. If the reliability of the series check-valves can't guaranteed (which you probably can't) then the back flow leakage through the check valves should be estimated and this used as the basis for relief rate calculations. They state that "Where no specific experience or company guidelines exist, one may estimate the reverse flow through series check valves as the flow through a single orifice with a diameter equal to one-tenth of the largest check valve's nominal flow diameter."

2. I think ASME pipe code (B31.3) allows infrequent transients from design conditions, so the piping might be o.k. but what about the other equipment in the system? You would have to review the effect of overpressure on each item individually. Is there scope to increase the design pressure on the pump discharge to 36 barg? This would definitely solve your problem. Depending on materials and design temperature I would expect the system to still be within the limit of ASME 300 # piping class.

3. I'm not sure what code(s) you are referring to, but I think this solution maybe acceptable. API Std 521 (4.3.4.3) indicates a automatic isolation as potential protection against check valve leakage. You can be fairly certain that a tight sealing isolation valve from a reputable supplier will not leak, but is the actuation of the valve reliable? Failure anywhere in the loop (measuring instrument, controller, valve) will mean you have lost your protection. Specifying the shutdown loop with safety integrity level (SIL level)will increase reliability. You maybe a able to use the automatic isolation as primary protection and dissimilar check valves in series as secondary protection provided your client accepts this.

With all being fair i'd have a PSV sized to relief the series check valve leakage rate (as per API Std 521) installed on the 24 barg design pressure system, but if its a remote location, hard to access and service then maybe a you have to comprise and an SDV may be considered suitable protection.

Hope this is helpful

[fallah]

What would be the source(s) of pressure (36 barg) in the header? Seems a stronger source of pressure than the pump to be connected to the header.

What is the MAWP value of the pump?
What is the design pressure value of the discharge line?

By knowing the answers of the above, one can submit more comperihensive response to your queries.

[kkala]

Source of pressure (causing design pressure of 36 Barg) is the crude oil centrifugal pump (as well as its booster pump) introducing water into the header of cold preheat train. Due to numerous exchangers and control valves there is a considerable pressure drop along the crude header ending to desalter (14 Barg).

MAWP of pump casing is expected to be higher than 36 Barg (API 610 pump).
Discharge water line has a "proved" design pressure of 24 Barg. Operating pressure at the point connected to the crude header is 18-19 kg/cm2.

Above example simplifies real case, as said in the original post.

The main question is whether a PRV is mandatory on the water discharge, and under what conditions it is not.

Meanwhile subject is looked into. A recent mechanical check of the exchanger (shown on the diagram of previous post) has concluded that design pressure of its shell can be theoretically upgrated to 36 Barg (rerating). A hydrostatic test to confirm it has not yet been decided.

[Qalander (Chem)]

Dear kkala,

Sorry for jumping in,however.

• I do not feel like grasping/swallowing the idea of feasible/effective wash water injection into the system under discussion on sustainable basis and
• accordingly my thoughts would be to have this water injection pump with at least the same shut-off pressure capability 36 barg since
• otherwise wash water injection rate will not be possible to maintain at the desired Optimum(or even minimum) flow rate
• We face numerous fouling problems encountered in industry due to in-effective or incomplete desalting which has root cause in lack of sufficient wash water availability.

Hope this add another direction to your on-going discussion here,may or may not be of interest right now but our ex employer's water injection pumps were every now and then needing maintenance for providing needed shut-off pressure with very high system pressure up to desalter down stream HE's keeping water and Crude in liquid phase thereby desalting is possible.
Hope this is helpful!

[fallah]

If I have understood the process you described well, it seems that a PRV in the discharge line (as close as possible to header connection) is mandatory, because pump and exchanger (of course after rerating) would tolerate 36 barg and only the discharge line with DP of 24 barg can not.

Of course, I think a complete scheme including source of 36 barg pressure can better clarify the issue and therefore enable to better assistance.

Note: In your real scheme I don't know why check/isolation valves haven't considered just after the pump and before the exchanger.

[kkala]

The attached scheme (still simplified) gives more details, even though it is not a PID. There is an isolation valve just after the pump, as well as check valves at all branches, just upstream of their connection to crude header.

We have already proposed rerating the discharge line from 24 to 36 Barg design pressure, since exchanger (main equipment) seems able for it. Most probably piping class is suitable for 36 Barg, so hydrostatic test has to be performed on the whole line + exchanger. We have to search for "weak" components (e.g. some existing valve, etc) to replace.

Despite this direction, clarifications to original questions will still be valuable for similar cases. The questions concern this case, but also help other cases (more or less similar). Also non clarified "habits" / practices of the Client.

Attached Files

•  scheme.doc   33.5KB   45 downloads

[Qalander (Chem)]

Dear kostas Hello/Good Afternoon,

Your today's(22-5-2010) simplified sketch shows two water injection points

1) Just downstream of FCV but upstream of four heat exchangers.This may not be "achievable/ attainable" practically without having the discharge pressure of water injection pump 36 barg or higher; in all fairness.

2)Just closed to delta PCV downstream of four heat exchangers;even here 'point pressure might not be lower than 24 barg necessarily at all times.Thus the water injection into the main crude flow stream seems difficult.

Now I believe that the discharge pressure of water injection pump has to "by design" higher than 'Point Local Pressures' where water is entering main crude stream

[kkala]

Dear Qalander (Chem),

You are right to have queries, my friend, the case of equal design pressures (of crude header and water discharge line into it) would be best (by principle). As written before, we may realize equal design pressures (to avoid PSV) though max shutoff pressure of water pump will be lower than 36 Barg. Hydraulic calculations (not yet finalized due to additional water heaters to be placed at the line) indicate low operating pressure, hence low shutoff head (1.2*operating head) required for the water pump. Please note following in addition:

1. It is an intervention on existing equipment (not new design) having started from need to upgrade desalter brine cooling (heating desalter water feed) and increase water feed by ~ 67%.
2. A lot of parts / equipment of new water line are from existing water line, fed by a pump of max shutoff pressure ~23 Barg. The existing line and pump have been long in operation.
3. Operating pressure of 18-19 Barg (max) concerns the connection close to crude pump (pressure at next connection is about 3 Bar lower). 19 Barg is considered as max operating, we were informed that it can be as low as 15 Barg at that point. I assume that exchangers and line get progressively scales, FCV opens to keep constant crude flow (operator may help through manual valves), thus frictional ΔP increases till next cleaning. Frictional ΔP also depends on the kind of crude.
4. Design pressure of 36 Barg for crude line has been confirmed and can be attributed to high head of crude pump (hence high shutoff head). Still it must represent a very rare situation in this case, e.g. shutoff of both crude pump and booster pump (the latter is operating only at low crude tank level, as far as I know) and max crude density. During this event (not normal operation), it is not possible to inject water into the crude header, but our design intends to keep the plant safe in this (short) period.
5. Water flow will be monitored through flow meters at both branches.

Any advise on the case is welcomed, though decision is by Client in that type of design. Things would be different, if it were a new design with new equipment (not an upgrade of existing equipment / piping). Clarifications of queries of original post (16 May 10) are also useful, concerning several cases beside this one.

[kkala]

Sincere thanks for the post on 17 May 2010. As written meanwhile (21 & 22 May 2010), rerating of pump discharge line (with all connected equipment) from 24 to 36 Barg seems possible, which would eliminate the need of PRV (cutoff valve will remain). However the points (as answered) are of interest, irrespectively of the specific case. Following (found during investigation) may be worthwhile noting in addition, and comply with stands by daryon. Any comments are welcomed.

1. API 521 (2007), 4.3.4 (check valve leakage or failure) requires overpressure protection for single check valve when: max normal operating pressure of HP system exceeds design pressure of LP upstream system. (e.g. max oper=19 Barg versus design=28 Barg , no PRV necessary).
If the check valve is properly inspected and maintained (valve safety critical) hydrostatic test pressure can be considered instead of mentioned design pressure of LP system.
According to a practice applied here for "safety critical" check valves (not by API), design pressure of HP system should not exceed short term allowable pressure of LP system. The latter is 133% of LP system design pressure concerning piping, and probably 110-120% concerning equipment (e.g. design=36 Barg, short term=24*133%=32 Barg, PRV necessary). Difference between API & Practice is due to degree of “conservatism”.
Using safety critical check valves in series is accepted by API as a means to design pressure “break”; but “abstract” reserves seem to be involved in it (e.g. low differential pressure, low stored energy in HP system). So this method had better be avoided.
2. 10% over design pressure is acceptable for equipment, if of short duration. I suppose that 20% is similarly acceptable, for equipment hydraulically tested at 150% of design pressure (as it happened in the past).
3. A tightly closed valve is acceptable to “isolate” different design pressures. Nevertheles, in addition to mentioned risks (of loosing protection), the valve may “detect” high pressure late (that is after it has passed through it).

[demank]

I just look a latest scheme.
IMO, reclycle line back to upstream of FCV is not necessary.
Then, As long as the fluid is liquid, PRV is not necessary also cause already cut-off valve at the upstream of check valve. (If Header line which is have higher pressure contain gas, the valve may “detect” high pressure late).

That're my opinion,

[kkala]

I just look a latest scheme.
IMO, recycle line back to upstream of FCV is not necessary.
Then, As long as the fluid is liquid, PRV is not necessary also cause already cut-off valve at the upstream of check valve. (If Header line which is have higher pressure contain gas, the valve may “detect” high pressure late).

Thanks for the contribution, I will try to clarify points.
1. You mean the line injecting water into the crude upstream exchangers. We will not act on this existing line, transferring about 20% of total water flow. I guess it intends to "clean" the crude line, reducing exchanger scale.
2. The header contains crude oil heated in a series of exchangers and then going to desalter. We try to upgrade discharge line (with connected equipment) to 36 Barg design pressure (same as header), to avoid any problem. Cut-off valve combined with check valve could be a solution to overpressure (see previous posts), but since the valve is electrically or pneumatically motivated there are questions about its reliability. So the cut-off valve will not aim at overpressure protection, but rather to stop crude back flow to water network in case that the water feed pump stops. In this specific case, operators assure that there is enough time for the valve to close on low pump flow, which seems reasonable (valve and crude header have a distance ~40 m).

[Qalander (Chem)]

Dear Kostas,

Quote(from your 26th May 2010 Post)

2. 10% over design pressure is acceptable for equipment, if of short duration. I suppose that 20% is similarly acceptable, for equipment hydraulically tested at 150% of design pressure (as it happened in the past).
3. A tightly closed valve is acceptable to "isolate" different design pressures. Nevertheles, in addition to mentioned risks (of loosing protection), the valve may "detect" high pressure late (that is after it has passed through it).

Unquote

I can not agree to or endorse your opinion as Highly Risky and Unsafe.

Quote (From today's just preceding post)

1. You mean the line injecting water into the crude upstream exchangers. We will not act on this existing line, transferring about 20% of total water flow. I guess it intends to "clean" the crude line, reducing exchanger scale.
2. The header contains crude oil heated in a series of exchangers and then going to desalter. We try to upgrade discharge line (with connected equipment) to 36 Barg design pressure (same as header), to avoid any problem. Cut-off valve combined with check valve could be a solution to overpressure (see previous posts), but since the valve is electrically or pneumatically motivated there are questions about its reliability. So the cut-off valve will not aim at overpressure protection, but rather to stop crude back flow to water network in case that the water feed pump stops. In this specific case, operators assure that there is enough time for the valve to close on low pump flow, which seems reasonable (valve and crude header have a distance ~40 m).

Unquote


Again 1) refers to wash water Primary injection point
Argument in 2) for secondary water injection point


A)Dependence on operators for cut-off and


B)accepting 40 m distance sort of sufficient to safeguard do not seem really reasonable enough to be Safe, Reliable and Trustworthy sustainable operations and


possible water pump& Drive's

• numerous failures along with reversed rotation and
• a gross level water circuit crude oil Contamination

are Foreseeable.

Hope you realize the above and in "All fairness" Ethically convey it to the client!

Best of Luck for Safe& Sound way forward indeed.

Edited by Art Montemayor, 29 May 2010 - 08:25 AM.

[kkala]

Dear Qalander, herebelow are some justifications of the issues, subject of course to any further comments:

(from 26th May 2010 Post)
2. 10% over design pressure is acceptable for equipment, if of short duration. I suppose that 20% is similarly acceptable, for equipment hydraulically tested at 150% of design pressure (as it happened in the past).
3. A tightly closed valve is acceptable to "isolate" different design pressures. Nevertheles, in addition to mentioned risks (of loosing protection), the valve may "detect" high pressure late (that is after it has passed through it).
I can not agree to or endorse your opinion as Highly Risky and Unsafe.
Answer: Allowable 20% margin (for short duration) was supposed, seeing that few years ago PSVs were developing full flow at 20 or 21% overpressure in case of fire. And equipment was then hydraulically tested at 150% of its design pressure.
Nowadays PSVs are set to develop full flow at 10% overpressure even in case of fire and equipment is hydraulically tested usually at 130% of design pressure.
The real question concerns short term allowable overpressure and clarifications would be welcomed, if possible with reference to supporting codes. Above said is applicable to local Refineries, but I do not know the supporting codes (over here these do not make a responsibility of Process Dpt in general).
Heat exchangers (per API) make an example, concerning tube rupture case. Allowable (without need of PRV) short term pressure of the low pressure side equals its hydrostatic test pressure (hence the rule of 2/3 in the past versus 10/13 nowadays).
As read in WWW, allowable overpressure seems to be 0-10% in case of water hammer (depending on code), probably because relevant calculations cannot be very precise.
10% short term overpressure is considered allowable for equipment here.

(From today's just preceding post)
1. You mean the line injecting water into the crude upstream exchangers. We will not act on this existing line, transferring about 20% of total water flow. I guess it intends to "clean" the crude line, reducing exchanger scale.
2. The header contains crude oil heated in a series of exchangers and then going to desalter. We try to upgrade discharge line (with connected equipment) to 36 Barg design pressure (same as header), to avoid any problem. Cut-off valve combined with check valve could be a solution to overpressure (see previous posts), but since the valve is electrically or pneumatically motivated there are questions about its reliability. So the cut-off valve will not aim at overpressure protection, but rather to stop crude back flow to water network in case that the water feed pump stops. In this specific case, operators assure that there is enough time for the valve to close on low pump flow, which seems reasonable (valve and crude header have a distance ~40 m).
Again 1) refers to wash water Primary injection point
Argument in 2) for secondary water injection point
A)Dependence on operators for cut-off and
B)accepting 40 m distance sort of sufficient to safeguard do not seem really reasonable enough to be Safe, Reliable and Trustworthy sustainable operations and possible water pump& Drive's numerous failures along with reversed rotation and gross level water circuit crude oil Contamination are Foreseeable.
Answer: The concept is that the cutoff valve closes automatically on low water flow (close to water pump min flow) while the water pump is still operating. Reverse flow of crude meets two check valves before contacting the cutoff valve.
Worst condition would be at sudden stop of water pump, when the cutoff valve is still closing. Still crude has to pass through 40 m pipe with two check valves, and this only while cutoff valve does not get fully closed.

Edited by kkala, 29 May 2010 - 06:58 AM.

[demank]

Thanks for the contribution, I will try to clarify points.
1. You mean the line injecting water into the crude upstream exchangers. We will not act on this existing line, transferring about 20% of total water flow. I guess it intends to "clean" the crude line, reducing exchanger scale.
2. The header contains crude oil heated in a series of exchangers and then going to desalter. We try to upgrade discharge line (with connected equipment) to 36 Barg design pressure (same as header), to avoid any problem. Cut-off valve combined with check valve could be a solution to overpressure (see previous posts), but since the valve is electrically or pneumatically motivated there are questions about its reliability. So the cut-off valve will not aim at overpressure protection, but rather to stop crude back flow to water network in case that the water feed pump stops. In this specific case, operators assure that there is enough time for the valve to close on low pump flow, which seems reasonable (valve and crude header have a distance ~40 m).

Yes, I mean upstream the exchangers.,
btw2 if water discharge pump design pressure is 36 barg (as long as water pressure higher than crude's), I agree there is a water line into upstream of exchanger. Previously I think water discharge pressure is just 24 barg.