Possible Kick (wellbore influx) Indications Part1

Possible Kick Indications mean that there is possibility to get influx into wellbore. The indications can be either kick or just formation react while drilling. You need to remember that just only a single possible indicator cannot may not good enough to identify underbalanced condition in wellbore and the possible kick indicators must be used collectively. Therefore, drilling team on the rig needs to closely monitor the well and prepare appropriate action plans.

The possible kick indications are as follows;

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Why do we run casing in the well?

Simple question: “What are the reasons casing is run in the well?”

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There are several importance of casing as follow;

• To prevent collapse of the borehole

• To confine production to the wellbore

• To provide a flow path for drilling fluid

• To contain formation pressure and prevent fracturing of upper and weaker zones

• To provide an anchor for surface and sub surface equipment

• To provide a high strength flow conduit for drilling fluid to surface and ,with BOP , permit the safe control of formation pressure

• To prevent contamination of fluid in formations

• To exclude water zones from the producing formations

 

Any additional ideas are welcome.

Ref books: Cementing Technology Books

Pressure Loss and Equivalent Circulating Density Review – Reverse Circulation

We still have the same question as the previous post, Pressure Loss and Equivalent Circulating Density Review, but this case we will do reverser circulation, circulating from annulus to tubing , and see how much pressure and equivalent circulating density at bottom hole.

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Pressure Loss and Equivalent Circulating Density Review

This example that I got from my junior member is very simple but it helps you a lot to understand about how to determine pressure loss during normal circulation.

Information given is listed below;

Pressure Loss and Equivalent Circulating Density Review

Circulate at 3 bottom up through open end tubing (Down tubing and up annulus) with 12.7 ppg mud.

Pump pressure = 1000 psi

Annulus friction loss = 50 psi

Inside tubing friction loss = 925 psi

Surface line friction loss = 25 psi

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How much pressure will we see at cement head in case of float shoe fail?

I still have the simple but interesting question about hydrostatic pressure which you can apply this calculation into drilling/cementing operation. The question I got about how much pressure we will see at cement head in case of float shoe fail.

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