Tag Archives: Well Control

Volumetric Well Control – When It Will Be Used

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Volumetric well control method is a special well control method which will be used when the normal circulation cannot be done. It is not a kill method but it the method to control bottom hole pressure and allow influx to migrate without causing any damage to the well.

volumetric

There are several situations where you cannot circulate the well as follows:

• Pumps broken down

• Plugged drill string/bit

• Drill string above the kick

• Drill string is out of the hole completely

With the volumetric method, the volume of gas influx will allow migrating and casing pressure will increase till a certain figure then a specific amount of mud will bleed off to compensate the increase in casing pressure. The volumetric method will allow the kick to surface while the bottom hole pressure is almost constant. Successful use of volumetric method requires personnel understand three basic concepts – Continue reading →

Diverter Systems In Well Control

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The diverter is an annular preventer with a large piping system underneath. It is utilized to divert the kick from the rig and it can be used when the conductor pipe is set. It is not used if you drill riserless. The large diameter pipe typically has two directions diverting the wellbore fluid out of the rig (see the figure below for more understanding).

The diverter should be used only when the well cannot be shut in because of fear of formation breakdown or lost circulation. Use of the diverter depends on the regulations and operator policies.

The diverter is normally installed on a conductor casing with large diverter pipe pointing to a downwind area. Typically, the selective valves located at each diverter line can be operated separately so the personnel on the rig can divert the flow into the proper direction. It is designed for short periods of high flow rate but it cannot hold a lot of pressure. With high flow rate, the erosion can be happened easily so the bigger of diverter line the better. Additionally, the straight diverter lines are the most preferable.

** more details can be found here – https://www.drillingformulas.com/introduction-to-diverters-in-well-control/

In the market, there are several models provided by service providers as

Hydril Pressure Control FSP* 28-2000 Diverter

http://www.ge-energy.com/products_and_services/products/capital_drilling_equipment/hpc_fsp_28_2000_diverter.jsp

Hydril Pressure Control FS™ 21″ 500-psi Marine Riser Diverter

 

http://hydrilpressurecontrol.com/pressureControl/diverters/diverters-FS.php

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

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