Choke Manifold:

The purpose of the manifold is to provide a method of circulating from the BOP stack under a controlled pressure. The manifold provides alternate routes so that chokes and valves can be changed out or repaired. The  API bullletin RP-53 3 A3 provides a description of the choke manifold and recommended practices for planning and installation. The recommendations include.

  • Manifold equipment subject to well and/or pump pressure should have a working pressure at least equal to the rated working pressure of blowout preventers in use.
  • The choke manifold should be placed in an accesible location, preferably outside of the rig substructure.
  • The choke line ( which connects blowout preventer stack to the choke manifold) and line downstream of the choke should be as straight as practicable, turns, if required,should be targeted, and have a bore of sufficient size to prevent excessive erosion or fluid friction.


A choke controls the flow rate of fluids by restricting flow through an orifice, friction or backpressure is placed on the system, allowing a control of flow rate and well bore pressure.

Well control chokes are of different design than gas and oil production chokes. In general, the production choke is not suitable for well control. Manual adjustable chokes are used for some well control applications but most pressure operations use remote adjustable chokes.


Fixed Chokes:

The fixed choke usually has a choke body in line to permit the installation or changing of a bean choke with a certain size orifice.

Manual Adjustable Chokes:

This is the basic type of choke. It has a tapered bar and seat. As the bar gets closer to the seating area, there is less clearance and more restriction for fluid going through it, producing more backpressure on the well. The type of choke is often the most neglected piece of well control equipment. It serves as a backup choke, and often as a primary chjoke in operations.

Remote Adjustable Chokes:

Remote adjustable chokes are the choke of preference in drilling operation and for pressure related work. They provide the ability to monitor-follow or check what something happens-pressures, strokes and control the position of the choke all from one console.


Mud Gas Separators ( Gas Busters):

Mud gas separators generally are the first line of defense from gas around the location. A gas separator is a simple, open vessel connected to the end of the manifold or choke line, just beofre fluid enters the return line-possum belly-.The greatest amount of gas coming up with a kick will separate handles this gas. The gas separator allows the free gas that breaks out the fluid to leave the system and gravitate or be pushed to the flare line or water table.



The degasser has a limited capacity to handle gas volume, but since gas volume-trapped in the fluid- is low, the degasser is usually adequate. If the fluid’s viscosity is high or fluid is contaminated, gas may not freely break out. Degassers may separate entrained gas from fluid using a vacuum chamber, a pressurized chamber, a centrifugal spray or a combination of these designs. The most common degasser is a vacuum tank or a pump sprayer, but there are many degassers and some combine functions. The maintenance on degassers is slight,  the pumps must be lubricated and sized properly.

Trip Tanks:

The trip tank is small, allowing accurate measurement of fluid pumped into well. It is the best way to measure the amount of fluid it takes to fill the hole on a trip out or the amount of fluid displaced on the trip back in. As each stand of pipe is pulled from the hole, the wellbore fluid level lowers by displacement of the steel, or if wet, displacement and capacity.


It is necessary to measure the amount of fluid for fill-up to be sure a kick has not entered the well. There are several types of trip tanks. A simple gravity-fed trip tank includes a small tank on the rig floor or elsewhere at a point above the flow line, marked in portions of a barrel (m³). A valve is required to release fluid from the tank into piping directing fluid into the bell nipple above flow line. The valve is manually opened, then closed when the hole is full, and the amount of fluid used is reported, recorded and compared to theoretical fill calculations.

Safety Valves and floats:

A method of closing off the string is a basic part of well control equipment. Equipment for closing off tubing or drillpipe includes safety valves, floats and inside blowout preventers. This equipment is handled by the floor crew. It is essential that the driller and toolpusher make sure the crew understands the rules for operating and maintaining this essential equipment.

Upper Kelly Cock:

The upper kelly cock is a standard part of the upper kelly assembly. Some upper kelly cocks are simple ball, flapper or plug type valves. The basic purpose of the upper kelly cock is to protect the kelly hose, swivel and surface equipment from high well pressure. It is normally pressure tested when the stack is tested. There is limited maintenance for the upper kelly cock.


Lower Kelly Cock:

The lower kelly cock is a full-opening valve which backs up the upper kelly cock. It allows removal of kelly when pressure on the string is greater than surface equipment rating. It is common practice to use the lower kelly cock as a fluid or mud saver valve. Continual use of the lower kelly cock has mixed advantages. The valve is operated at every connection so it is kept free and in operating condition. The crew learns how to operate the valve and the wrench is kept available. On the other hand, repeatedly using this ball valve for this purpose can reduce operation life. Some rigs have reported galling of valve threads from continual makeup and breakout. Galling can be eliminated through use of a saver sub.

Gas Detector:

The gas detectors on rigs are used to warn personnel of increasing gas flow out of the welland areas of gas concentration in places where an explosion or fire could occur. Other types of gas detectors are placed in areas where toxic gases, such as H2S, can accumulate and harm personnel. Gas detectors should be tested on a regular basis with an approved gas source. Sniffing lines should be blown out periodically to remove stale or trapped gases. Maintenance should be performed according to manufacturer’s specifications. Obvious problems with gas detectors are broken and plugged lines or dirty detector heads. If the alarms are placed in the mud logging unit only, then this unit must be manned 24 hours a day.

Mud Return indicator ( Flow Line Sensor):

In terms of kick detection equipment, the return indicator is probably the most important piece of equipment used. The mud return indicator is usually a paddle in the flow line. The paddle in the flow line reports flow of fluid in the line.


This signal is sent to the driller’s console where it is reported as percent of flow. In most operations, a relative change from an established trend is an indicator of potential hazard. So it is crucial to detect any change in flow. If a well kick occurs, something has entered the wellbore. This will push fluid out of the flowline, showing as an increase in flow.


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