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injection valves at well head are choke valves?
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(Chemical)
(OP)
28 Apr 15 09:51
Hi everyone,
I have always worked in refining projects but I'm involved now in a production project. I have to make a first approach of the gas lift, water injection and gas injection valves at the well head.
I've checked previous projects and I see these valves are always represented in P&IDs as angle valves. This makes me thing those are choke valves. However, the dP in these valves is not that high.
The client asked for certain pressures downstream those valves (our scope of work ends at those valves). Then, the deltaP is no high because we give the lift gas / injection gas / injection water upstream the valve at a similar pressure as the client requests downstream the valve.
My question is why those valves are choke valve.
If the client wants this pressure to inject the gas/water, those valves will only drop a few bars.
Besides, I've seen a project where there is no valves in each well head for gas injection. Only the lift gas valves down in the well (not in our scope). In case of water/gas injection, I always see choke valves.
I hope you could understand my question. Thank you very much.
(Petroleum)
28 Apr 15 10:02It can seem a bit strange, but without seeing the full operating range of the system it isn't clear.sometimes you have a choke valve like that simply so that you can control the start up. The running DP might not be very high, but the start up DP can be as the absolute pressure of the WI and GI is often very high.The same applies to the main choke valve. Often the running DP is very low and sometimes the choke is wide open, but shut in tubing head pressure might be much higher and it is how you control that crucial start-up period is why the choke valve is there.Lift gas is often not so high a pressure as the injection systems and so has much lower start-up DP.
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(Chemical)
(OP)
28 Apr 15 11:53Thank you very much. I understand now.
The thing is that I have to put a deltaP in the datasheet of those valves. I chose a small deltaP in order to obtain a big Cv. However, if the deltaP may be so high that it can reach choke flow, I may need to write a very wide deltaP range in the data sheet. Sometimes the injection pressure may be really high downstream the valve (low deltaP) but in the cases you mentioned, I should indicate a big deltaP, right?
I suppose suppliers are accustomed to see those big ranges in these valves.
Thanks again.
(Petroleum)
28 Apr 15 13:08That's more or less it. The flow rate at the high DP, if this is being used simply to pressure up the well on start-up you can probably put fairly low (say 25% of max flow).Yes, that's why cages are often designed to have low DP at full open, but much smaller holes / gaps at low opening per cent to give controllability with a high DP.
Remember - More details = better answers
Also: If you get a response it's polite to respond to it.
(Chemical)
29 Apr 15 04:51Other reasons for this also :
Reservoir engineers often change the mode of operation at these wells for all sorts of reasons - a GI or WI well may be converted into a production well later (or the converse).
So hard wearing choke valves are used in anticipation of wells being converted into production wells when operating dp can be high, with sand in the flowstream. Usually these chokes have seats with SiC on them to handle sand. Piping mods to enable changes in well operating modes are then minimised, while the expensive chokes may be retained.
Even then, there are cases where these expensive API 3000 lb or 5000lb chokes (some time made out of Sandvik 2205 duplex) didnt survive even 1 week in production.
(Chemical)
21 May 15 15:55I just got off a job that sounds very similar to what you are doing. We were connecting injection gas, injection water or lift gas as applicable to the annulus of several wells. The client would provide us with min/norm and max rates of each fluid as applicable and the corresponding annulus pressure needed (essentially, the downstream pressure of the valve). I also had the range of operating pressures of the injection headers.
Min Cv (somewhat simplistically) is the max differential pressure the valve will see and min flow
Max Cv is the min differnetial pressure and max flow
Normal is somewhere inbetween, basically normal flow and normal dP
This gives you a choke valve that covers the potential operating envelope.
This approach gave me two problems. Min flow and max dP gave me a very small Cv while the minimum header pressure was less than the annulus pressure required by the well for the max flow. In addition, even with some "small" dP across the choke valve, the range of min Cv to max Cv was so wide that the choke valve would give very poor performance. So it was back to the client to relook at the data because a 1:2000 turndown isn't going to work.
The min sizing case was tweaked in that they decided the dPs and flows they gave me were somewhat extreme. For the max flow case, we ended up using the max flow, corresponding annulus pressure and an arbitrary 100 psi pressure drop for the choke valve. Would it work under all cases? No, but in reality, by the time the choke valve was fully open, the limit wouldn't be really the valve Cv but simply that they didn't have enough supply pressure for what they wanted to provide to the well and you'd live with what you could get.
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Posted 09 February 2009 - 12:11 AM
Hello Jiten,
I happen to have a fair deal of experience with well head chokes,when i was working as production engineer for a gas production facility,so i thought i could contribute my 2 pence...in addition to the useful comments posted by the other members.
In my case what happened was that...our wells had started cutting water. Soon the water also started bringing in sand (which is the normal phenomenon in such a case).Soon the choke valves of 2 of our wells had failed. Subsequent investigation revealed that the choke internals as well as the casing body were severely eroded due to increased water and sand and also due to high differential pressure across the choke (high velocity with sand content/high erosion rate).
We could do well to keep in mind the that lead time for automated chokes is fairly long so failure of chokes invariabbly leads to downtime and loss of revenue.So (If possible)consulting the reservoir engineering about how the well/wells may be expected to behave over the lifecycle may be a good idea.
Next some care may need to be excercised while procuring the chokes.More realistically it may be wise to consider liquid/water production along with the gas which would ask for a greater Cv.If cost is not so much of an issue you may also allow some Cv upsides in future, because swapping of choke valves and other instrumentation or piping is not so uncommon in the oilfield.
Also make sure the vendor is well informed of water slugging & sand production problems (If any)
Last and most important, check the trim material .Almost always ...it has to be Tungsten Carbide.
Shetty.
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