Category Archives: Drilling Operation

Deal With Soft Clay Formation in Sea Water

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The well was drilled with sea water and the formation is soft clay formation. Then, the bit was totally plugged. We did not have any chance to displace well with water based mud prior to coming out of the hole. We flow checked and came out of hole to change the bit.

Because the formation is clay which will react with seawater resulting formation swelling, we need to develop specific rig procedure to deal with when tripping in hole.

What are the foreseeing issues?

• Clay formation swell

• Pack off due to formation instability

• Soft formation tends to get side tracked easily with mud motor

What is the objective?

• Attempt to condition the well before running back in hole with motor assembly to minimize chance of side track.

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Good Practice To Tag Top Of Cement

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After complete the cement balanced plug job, you should need to go back in hole and attempt to tag to see where the actual TOC is.

You should be careful when you try to find the top of cement otherwise you may not have a big problem.

These procedures are good drilling practice which you can adapt for your operation.

1. First of all, you need to know where the calculated TOC is.

2. Trip in hole to approximately 1-2 stands above TOC.

3. Make up top drive or kelly depending on the rig set up.

4. Bring pump up to slow rate. This depends on how the BHA is set up. I cannot specific flow rate.

5. Slowly wash down and monitor the weight.

6. Wash down until you see solid weight tagged on a driller gauge.

What will be happened if you don’t wash down to tag the top of cement?

The BHA may be in the green cement (cement is not properly set up) and when the pump is turn on, the cement will flash set. Finally, the drill string will get stuck.

 

If you want to know about struck pipe in the cement, please read this article “Soft Cement Causes Stuck Pipe”

 

 

BOP Stack Organization and BOP Stack Arrangement

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Blow Out Preventor (BOP) is a very important part of well control equipment and the first thing which we would like to discuss in this article is the BOP stack organization. The BOP stack can be configured in various configurations which must be suitable for the operation.

API has the recommended component codes for BOP as listed below:

A = Annular Preventer

G = Rotating Head

R = single ram type preventer with one set of rams, blind or pipe.

Rd = double ram type preventer with two sets of rams, blind or pipe.

Rt = triple ram type preventer with three sets of rams, blind or pipe.

CH = high remotely operated connector attaching well head or preventers

CL = low pressure remotely operated connector attaching; the marine riser to the BOP

S = spool with side outlet for choke and kill lines

M = 1000 psi

How can I know the BOP configuration and rating from the codes?

When you see the code, you need to read upwards from the bottom of BOP stack. Let’s take a look at the following example:

15M 13-5/8” – RSRRA

This BOP stacks has pressure rating of 15,000 psi with a bore size of 13-5/8” inch. There are following BOP component from bottom to top

Rams – Spool – Rams – Rams – Annular ( see the figure below)

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Importance of Choke Drill and Its Procedure

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Choke drill is one of well control drills that will improve crew competency in driller’s method. The advantages from the choke drill are as follows:

• Get more familiar to practice controlling the pressure via a choke on the rig

• Get more understanding about lag time

• Practice the procedure to obtain the shut-in drill pipe pressure

• Ensure the surface well control equipment as pressure gauges, choke, BOP is ready for work

• Get more practices when attempting to bring the pump up to kill speed, slow the pump down and change the pump rate

Choke Drill Steps are listed below:

1. Trip in hole above top of cement

2. Fill the pipe and circulate seawater or mud around for few minutes

3. Close annular preventer or upper rams preventer

4. Pressure up annulus to 200 psi (the pressure may be different depending on the company policy.)

5. Line up the pump

6. Pump slowly to bump the float and obtain shut in drill pipe pressure

7. Bring the pump to kill rate by holding casing pressure constant – personnel need to adjust the choke

8. Measure lag time for the drill pipe gage after the adjustment of choke is made.

9. Change circulation rate by holding casing pressure constant. Crew needs to adjust choke to achieve this.

10. Shut the pump down by holding casing pressure constant.

11. Bleed off pressure and line up for drilling operation

Reference book: Well Control Books

Do you have too much slug in the well?

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Slug is heavy drilling mud that is used to pump when you want to pull pipe dry. However, excessive volume of slug in the well can create higher mud weight and cause the problem. Today I would like to share my experience regarding slug in the well.

The situation happened on the drilling rig like this.

The well was TD with 13.0 ppg mud and circulation was conducted until the shale shakers. After that we pull 10 stands wet and pumped 40 bbl of 15.0 ppg slug and came out of hole without any problem. Then we run the logging and we got stuck. We picked the fishing gear and grabbed the fish. We pulled out 10 stands wet and hole was taking proper fill. We pumped same amount of slug 40 bbl of 15.0 ppg and came out of hole. The decision was made by town to trip in hole to do the wiper trip.

Tripping was done with caution and break circulation was conducted every 3000 ft to break the gel. Prior to TD 100 ft, we made up top drive and slowly washed down to TD. While we were circulating, the mud weight out was varied from 13.2 ppg to 14.2 ppg. Additionally, we start losing mud while circulating.

Do you know what went wrong?

The two slugs in the well cause us trouble.

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