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Centrifugal Compressor Relieving Scenarii


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#1 julie

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Posted 07 June 2019 - 08:25 AM

Hello,

 

This is my first post so I apologize if it is not clear ... do not hesitate and correct me if I am giving wrong statements or assumptions.

 

We are designing a new process Platform in the company I work for.

 

During a 1st phase a 3phase separation vessel will be installed to produce the surrounding wells and help reducing their WHP. Gas from the vessel will be routed to the flare. We estimate roughly 7mmscfd.

 

In a second phase this production gas along with gas from other platforms (through gas scrubber) will be routed to a compressor in order to provide gas lifiting.

The compressor will be designed for 28 mmscfd from 35 to 1100 psig. A 3 stage centrifugal type has been suggested, with constant speed and air cooler.

 

We are at a very early stage of the project meanwhile I would like to have an idea of the design of a suitable flare for both phase 1 (continuous flaring of 7 mmscfd + relieving flow from liquid outlet) and phase 2 (no continuous flaring, only relief / blowdown scenarii from 3phase vessel, compressor and slug catcher).

 

Thus I am wondering what would be the releiving scenarii of the centrifugal compressor... and how to arrange the compressor specifications in order not to have a full flow 28mmscfd releiving scenario since this would lead to a too big flare.

 

I have been told that I could disregard the case full flow by having a fully rated compressor meaning if my understanding is correct that I would need to have rouglhy 1250 - 1300 psig design pressure on the entire skid. Am I right ?

Is it to protect from anti surge HP valve failure in open position and possibility of HP gas flowing back from gas lift header to 2nd stage suction ?

But in that case only 2nd stage and 3rd stage shall be fully rated since only one single jeopardy is to occur and anti surge HP valve goes from 3rd stage discharge to 2nd stage suction. And 1st stage shall be designed to max pressure from 2nd stage discharge + extra. right ?

 

any other means ? since having a fully rated compressor seems quite expensive...

Besides since this is centrifugal type compressor and not reciprocating type, I would say we cannot experience pressure build up on a blocked outlet. Is that correct ? but we can experience blocked outlet case for the air cooler

 

thank you for your kind assistance.


Edited by julie, 07 June 2019 - 08:25 AM.


#2 oilpmp

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Posted 10 June 2019 - 01:38 AM

Hi

Could you summarize your narrative in a set of three operating cases (one for each phase)?

something roughly like this:

 

|                    Phase I, II, III                  |

| Section 1  |   Section 2  |  Section 3  |

P inlet

T inlet

Mass or Std. Flow

P outlet

MW

 

Plus a basic process sketch or PFD would help.



#3 SawsanAli311

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Posted 10 June 2019 - 01:15 PM

Blocked outlet at compressor individual stage cannot be ignored and shall be considered as one of the overpressure contingencies with the PSVs set at each downstream's system limited design pressure.I believe your compressor stages are fitted within the same casing and share the same seal gas system,please confirm? Also please clarify if they are run by the same motor shaft. 

 

A blocked outlet at the compressor doesn't neccesarily translate to full rated capacity being relieved to flare since the increase in suction pressure would be coincident with the increase in suction density, this by itself can affect the amount to be relieved during blocked outlet and it all depends on the maximum compressor power limit  and the flow rate achieved during that scenario, this can be estimated in HYSYS.

Compressor stages will have segregating shutdown valves in between them mandating not only installing PSV at each discharge to cater for blocked outlet and also possibly fire case but also you should study the emergency blowdown and depressurization of the compressor system specially in cases mandated by prolonged shutdown duration forcing auto-depressurization of  the compressor stages to avoid seal gas system damage.

Additionally, every stage's suction scrubber/ suction cooler (both located after the SDV of the preceding stage) shall be designed for the settle out pressure of each stage multiplied by 1.05-1.1. If your compressor stages are in one casing, consider estimating the settle out based on the combined settle out since leakage can occur through the seal gas system. 

 

It is important to note that the scenario of anti-surge valve fail open has nothing to do with fully rating the preceding stages.As explained above, the design pressure of the suction of each stage depends on the settle out conditions.Even if the antisurge valve fails open, compressor trajectory point will be dragged towards stonewall limit of the compressor curve until it trips due to overheating as well as low discharge pressure (increase in suction T and suction P leading to reduction in the head along the same fixed speed H-Q curve).  The reduction in the head will lead to packing of the upstream system with subsequent flaring from the compressor inlet manifold/ separator flare PCV. 



#4 oilpmp

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Posted 10 June 2019 - 04:15 PM

I suspect that due to the intricated interactions between the compressor sections, some sort of quantitative assessment is needed. Also, this is a reason why I asked the OP to provide the data in some sort of datasheet format. Not necessarily a dynamic study would be needed, but a simple configuration of the operating cases in a process software / simulation system can provide estimates (Hysys, n-centrix, or even an excel sheet can do the trick). 

 

I have a comment in regard to the anti-surge valve(s). It is important to know the sizing criteria being used. For example if the "1.8 to 2.2 max CV" criteria is used, then most likely yes, a valve fail open may get the machine to operate near the choke. But some OEM's use different rules. 



#5 rangelanto

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Posted 12 June 2019 - 09:32 AM

Hi Julie

 

As far as the compressor is concerned, a gas lift installation is designed to operate at a certain injection pressure. If the pressure falls

 

below this value, the well will stop flowing (the well will die). The gas flow rate however can be varied within the producing range of

 

the well. Therefore, compressor performance is controlled by maintaining constant discharge pressure at all times. It means the gas

 

lift valves are essentially back pressure regulators and a certain operating pressure at the wellhead should be maintained at all times

 

in order to keep the valve in the open position and allow the gas to flow from the tubing to the casing. This is achieved by speed 

 

control. Thus, due to that characteristics of the gas lift system, it is important when selecting the compressor prime mover should

 

be a gas turbine (first option) or Variable Frencuency electric Drive (VFD) motor.

 

 

Good Luck

 

Jose Rangel

 

 

 

 

 






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