Sunday, February 13, 2011

Understanding Well Control


The function of Well Control can be conveniently sub-divided into two main categories, namely Primary Well Control and Secondary Well Control. These categories are briefly described in the following paragraphs.

1.1.1 Primary Well Control (Hmud > Pf )

This is the maintenance of sufficient hydrostatic head of fluid in the wellbore (HMUD) to balance the pressure exerted by the fluids in the formation being drilled (PF).
However, it should be noted that balancing formation pressure is a theoretical minimum requirement; good drilling practice dictates that a sufficient excess of hydrostatic head over formation pressure, be maintained at all times to allow for contingencies. This excess head is generally referred to as ‘Trip Margin’ or ‘Overbalanced’.

1.1.2 Secondary Well Control (Hmud < Pf )

If for any reason the effective head in the wellbore should fall below formation pressure, an influx of formation fluid (kick) into the wellbore would occur. If this situation occurs the Blowout Preventers (BOPs) must be closed as quickly as possible to prevent or reduce the loss of mud from the well.

The purpose of Secondary Well Control is to rectify the situation by either:

a) allowing the invading fluid to vent harmlessly at the surface, or

b) closing the well in. i.e. providing a surface pressure to restore the balance between pressures inside and outside the wellbore.

This latter procedure prevents any further influx of formation fluid and allows any one of a variety of ‘Kick Removal’ methods to be applied thus restoring a sufficient hydrostatic head of fluid in the wellbore. This re-establishes the preferred situation of Primary Well Control.


The term ‘bottom hole pressure’, as used here, means the sum total of all pressures being exerted on a well by our operations. Bottom hole pressure is the sum of the hydrostatic pressures exerted by the fluids in the well, plus any circulating friction loss (e.g. Annular Pressure Loss), plus any surface applied back pressures, where appropriate.

This is the total pressure exerted by us. It is usually intended to at least balance the formation fluid pressures in the exposed portion of the well.


The formation fluid pressure, or pore pressure, is the pressure exerted by the fluids within the formations being drilled. The sedimentary rocks, which are of primary importance in the search for, and development of oilfields, contain fluid due to their mode of formation.


Abnormal formation fluid pressures, or ‘sur-pressures’ as they are sometimes known, can arise for a number of reasons.

They can be categorised as:

a) Differential Fluid Pressure
b) Surcharged Shallow Formations
c) Sediment Compression
d) Salt Beds
e) Mineralisation.

The main causes of kicks are:

a) Failing to fill the hole properly when tripping
b) Swabbing in a kick while tripping out
c) Insufficient mud weight
d) Abnormal formation pressure
e) Lost circulation
f) Shallow gas sands
g) Excessive drilling rate in gas bearing sands


1) During Drilling

There are several indications which show that a kick is in progress:

2) During Tripping

The indication of the presence of a kick is:


If this indication is not noticed at an early stage, it should become progressively more obvious.
In the extreme case the hole would eventually stay full, or flow, while pulling out. This may sound ridiculous, but it has occurred.


The presence of some or all of these indications require that a flow check be carried out to determine whether or not a kick is in progress.

When a kick occurs, the surface pressure required to contain it will depend mainly upon the size of the influx taken into the wellbore. A small kick closed in early means lower pressures being involved through the kill. Furthermore it is easier to deal with a kick which is noticed early and closed in quickly.


Annular Closing Times

• API RP53 state that surface annular preventers closing times should not exceed 30seconds for smaller than 18 3/4” and 45 seconds for 18 3/4” and larger.

• Subsea annular preveters should not exceed 60 seconds.

Shaffer Spherical BOP

Shaffer annular BOPs are rugged, compact and will seal on almost any shape or size- Kelly’s, drill pipes, tool joints, drill collars, casing or wireline. They also provide positive pressure control for stripping drill pipe into and out of the hole. The annular BOP is one of the first lines of defence in controlling a kicking well. When the BOP is actuated, hydraulic pressure operates, and in turns closes the spherical shaped preventer. The closure occurs in a smooth upward and inward motion, as opposed to horizontal motion.

Special features include:
• Rugged and reliable sealing element provides positive seal after hundreds of tests to full working pressure.
• Strong and simple construction-only five major parts.
• Simple hydraulic system-only two hydraulic connections are needed.
• Wear rings on movable parts prevent metal-to-metal contact. This feature prolongs preventer life.
• Suitable for H2S service.
• Servicing is easy- Element can be changed without getting mud and grit into the hydraulic system.


A diverter is a safety system, which reroutes a well fluid flow away from the rig. Shallow gas is permitted to flow until depleted, or until the well is bridged over or killed by pumping in heavy mud. Ready during upper hole operations, a diverter is intended for use when there is a danger of penetrating a pressurised gas zone, while the casing shoe strength may not be sufficient to contain shut in pressures. Massive flows of gas and sand can quickly destroy a rig’s diverter system. Hydril incorporate integral valve functions and switchable target to minimise equipment and thereby decrease the risk of malfunction.


The height and diameter of an atmospheric separator are critical dimensions which affect the volume of gas and fluid the separator can efficiently handle. As the mud and gas mixture enters the separator, the operating pressure is atmospheric plus pressure due to friction in the gas vent line. The vertical distance for the inlet to the static fluid level allows time for additional gas break-out and provides an allowance for the fluid to rise somewhat during the operation to overcome friction loss in the mud outlet lines. As shown in Figure 39, the gasfluid inlet should be located approximately at the midpoint of the vertical height. This provides the top half for a gas chamber and the bottom half for gas separation and fluid retention. The 30 in. diameter and 16 ft minimum vessel height requirements have proven adequate to handle the majority of gas kicks. The separator inlet should have at least the same ID as the largest line from the choke manifold which is usually 4 in. Some separators use tangential inlet, which creates a small centrifugal effect on the gas-fluid mixture which causes faster gas break-out. The baffle system causes the mud to flow in thin sheets which assists the separation process. There are numerous arrangements and shapes of baffles used. It is important that each plate be securely welded to the body of the separator with angle braces.

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