Coiling
Replies to This Discussion
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Permalink Reply by Brian Day on
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On second thought, never mind. I did a Google search and discovered a host of reasons for this process. It is an interesting read if you do the search yourself.
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Permalink Reply by Brian Powers on
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Brian -
without having more context about the well in question, I surmise that the operator of the well is going to use flexible steel coiled tubing coupled with nitrogen (transported in liquid form, converted to gaseous state) to lift the well in to kick off flow.
This is a common method in wells not blessed with sufficient bottom hole pressure to unload the completion fluids to surface.
Once the well gets flow established and is cleaned up to sales quality, it will hopefully continue to flow on its own.
Brian
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Permalink Reply by Brian Day on
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What if the well is reported to have lots of pressure - say 8500 to 9000 psi?
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Brian -
A pressure range estimate without knowing the depth datum at which the pressure is estimated or recorded is not very useful data. In a well of 7,000 to 8,000 ft, this pressure should be sufficient to lift all but the heaviest brines. This depends, of course, on the diameter of the production tubing, the internal condition of the surface (new, rough, scaly or corroded), the fluid density and viscosity, and the gas properties and gas to liquids ratio
As I indicated earlier this week to another query involving coiled tubing (CT), the tube is thin walled carbon steel. It is particularly weak in collapse mode and is prone to collapse while running into the well. It is common practice while running into the hole to pump water at low rates to support the CT from collapsing. When CT collapses, it "pancakes", and if the collapse coincides with a pressure event, then the CT provider has a real rodeo on their hands.
A Coiled tubing operation uses blow out preventers similar to a rotary operation and integral check valves at the bottom of the CT that can mitigate against disaster in an unplanned pressure control event.
Brian
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Permalink Reply by Brian Day on
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The well is in the Utica at 12000 feet. News today is the township was notified that coiling had to be stopped temporarily and the well burned off for a bit because the pressure was too great. The figure of 8500 psi is second hand information, but a good source. It is also at a point where fracking was only about 60% complete. In fact, I don't know if psi is a common unit for pressures to be indicated on a well. What have pressures generally been on Utica wells in western Pa?
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Brian -
In oilfield terms, well pressures are recorded in psi. In international, or SI terms, pressures are recorded in atmospheres or bars. If your report of 8,500 psi is at surface, that's one thing, if its at 12, 000 ft, its quite another.
So long as the flow equiment is sufficiently stout, having 8,500 psi to work with at surface is not a bad thing, so long as abrasive solids are not being produced with the spare frac fluid and water.
I'll defer your question on Western Pa. Utica pressures to other forum members, as I'm not familiar with that particular area.
Brian
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Permalink Reply by Brian Day on
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Thanks Brian. the well pressure was reported to be twice tha t of wells in western Pa. The fact that the drilling company called the township to notify them that coiling would stop until the well was partialy burned off to reduce pressure concerns me a little bit. I live in Wyoming, but I have family and friends that live near that pad. I do not wish to promote hysteria because the situation is probably routine. just the same, this gas well industry is still an unfamiliar experience for these people in the Northeast.
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