6 replies to this topic

Good day all;

I am in the upstream operations field. I have a small issue with a couple of lines coming into my facility here and I am certain that it is not a hydrate as there is 24.72 mmscf/d flowing through this 8" line. I have been hunting for a while to find an exact chemistry equation to give me a proper leg to stand on when I take this to the engineers. They don't see a problem here, but what works on paper, doesn't always work in practice. The volume of gas is fairly consistant as above, but from the header system to the facility, it goes from roughly +10 C to -5C in the inlet separator. All fluid from the wells needs to go into the flow line at the well level as access is very restricted. At the header, 3km away, the pressure is 1675 kPa and at the inlet is 975 kPa. I have been hard pressed to try and find concrete proof for the engineers.

HELP, please.

Thanks.

[Zauberberg]

So what is the problem? You have the flow, you have the pressure, what is your concern?
If there is a hydrate formation issue, most likely you would see the line gradually plugged by time and the flow would certainly decline over time.

Temperature drop for the given pressure drop seems to be too high though, but without knowing your concerns/problems in particular, we can't be of more help. Can you give us a more detailed description of what is the actual problem you are faced with?

I just need to know which chemistry equation will give the engineers the concrete evidence that they need to twin the 3 km of 8" if they want the rest of the field to pull down. They have an 8" (with 2 - 6" and 3 - 4" laterals), a 6" (with 4 - 4" laterals) and a 4" (at the header) all tying back into an 8". They seem to think that the field pressure should be lower on the far end, and I am telling them that they have a serious refrigeration issue in the short 8" line from the header to the plant. The only cure I am saying (without compression as it is remote) is twinning the line. It has been a long time since my last chemistry class and I am a little bit rusty.

[Zauberberg]

Ops,

Please take a look at the scheme uploaded below and confirm if this corresponds to the actual field layout. Do the necessary modifications, and add the twin 8" pipeline that you are proposing.

Speaking without knowing other details, it seems to be that a lot of liquid flashing takes place across the pipeline, causing high pressure drop (2 bar/km) due to increased flow velocities. The system is definitely below hydrate formation temperature so I hope water is not present in the wellstream. The actual 7 bar pressure drop - assuming pure gas flow, no liquids - cannot cause temperature drop of 15 degC due to Joule-Thomson effect. An approximate figure/guideline for J-T effect is ~1 degC for each 2bar pressure drop, if I remember well. So the normal arrival temperature should be in the range of 6-7degC assuming adiabatic flow.

Your reasoning is correct in my opinion, simply because there are flow limits for any given size of pipeline. Trying to pull more production will cause pressure drop to increase, which increases amount of flashing, which further increases pressure drop, and so on. It's really hard to give any other suggestion since we dont't know anything about production stream quality and other details of the production system (e.g. like ambient heat transfer - it can have a huge effect on the flow in 3km long pipeline). If you are interested in sizing of production piping system, grab a copy of API 14E. Although it covers offshore production platforms originally, it is equally applicable for onshore facilities as well.

Attached Files

•  Field Layout.xls   96.5KB   39 downloads

[Zauberberg]

Also, I suppose that your Flow Assurance grup has done the work required - simulating transient conditions, initial/actual operation and system behavior over the field life. There has to be a document somewhere on which the entire process design was based.

Do you control the pressure in the receiver section, or it is controlled somewhere upstream?

What we have here is a cluster of 33 offshore wells distributed between 3 platforms, with the production fluid flowing through the two identical pipelines in parallel. The pressure is controlled in the onshore Inlet Reception facilities (79 barg), while the pressure in the offshore test separators is somewhere around 100-105 barg. The pipelines are 38km long.

It would be good if we could know the exact description of your system - that way we can be of most help.

All of the fluids come to the facility, as well as the gas. The condensate/water ratio is about 45% water. Daily averages of fluid from the field range between 80 and 100 m3/d. Being as the wells are remote (caribou corridor), we do not have a choice in not putting everything down the line. Average well level methanol rate is 150 L/d. There are 19 wells in total. No insulated pipelines, no line heaters (hind sight is always 20/20). Most lines are pigged once a week. We have identified the liquid volumes from the 8" as the most problematic and have began to pig that line every two days. I thank-you for your patience and insight. Thanks for the link as well.

Ops,

Please take a look at the scheme uploaded below and confirm if this corresponds to the actual field layout. Do the necessary modifications, and add the twin 8" pipeline that you are proposing.

Speaking without knowing other details, it seems to be that a lot of liquid flashing takes place across the pipeline, causing high pressure drop (2 bar/km) due to increased flow velocities. The system is definitely below hydrate formation temperature so I hope water is not present in the wellstream. The actual 7 bar pressure drop - assuming pure gas flow, no liquids - cannot cause temperature drop of 15 degC due to Joule-Thomson effect. An approximate figure/guideline for J-T effect is ~1 degC for each 2bar pressure drop, if I remember well. So the normal arrival temperature should be in the range of 6-7degC assuming adiabatic flow.

Your reasoning is correct in my opinion, simply because there are flow limits for any given size of pipeline. Trying to pull more production will cause pressure drop to increase, which increases amount of flashing, which further increases pressure drop, and so on. It's really hard to give any other suggestion since we dont't know anything about production stream quality and other details of the production system (e.g. like ambient heat transfer - it can have a huge effect on the flow in 3km long pipeline). If you are interested in sizing of production piping system, grab a copy of API 14E. Although it covers offshore production platforms originally, it is equally applicable for onshore facilities as well.

That's right on the money. Flow rate on the upstream 8" is roughly 9/16 of the 25 mmscf/d flow rate. The 6" is 1/4 and the 4" that ties into the riser system is the remainder (1/16).