MUD SYSTEM | DRILLING FLUID, TYPES OF DRILLING FLUID

 

MUD SYSTEMS

Drilling mud, also called drilling fluid, in petroleum engineering, a heavy, viscous fluid

mixture that is used in oil and gas drilling operations to carry rock cuttings to the surface

and also to lubricate and cool the drill bit. The drilling mud, by hydrostatic pressure, also

helps prevent the collapse of unstable strata into the borehole and the intrusion of water

from water-bearing strata that may be encountered. [BRITANNICA]

Types of Drilling Fluids:

Liquids

• Water-base muds (WBM)

• Oil-base muds (OBM)

Gases

• Air

• Natural gas

Gas-Liquid mixtures

• Foam (mostly gas)

• Aerated water (mostly water)

Water base muds (WBM)

Solid particles are suspended in water. Any oil added to WBM is emulsified into the water phase and is maintained as small, discontinuous droplets. It is called oil-in-water emulsion or emulsion mud.

Oil base muds (OBM) and Synthetic Oil Base Muds (SOBM)

When Diesel is the continuous phase, it is called OBM and when Synthetic oil is the continuous phase it is called SOBM. 

Some of the advantages of OBM/SOBM are

• Good rheological properties at high temperature.
• More inhibitive than WBM.
• Effective against all types of corrosion.
• Superior lubricating characteristics.
• Permits mud densities as low as 7.5 ppg and as high as 19 ppg etc.

Disadvantages of OBM/SOBM

• Higher initial cost.
• Requires very stringent pollution-control procedures.
• Reduced effectiveness of some logging tools
• Remedial treatment for lost circulation is more difficult AND EXPENSIVE
• Detection of gas kick is more difficult because of gas solubility in diesel oil.
• Formations can become oil wet on exposure to SOBM. This can hamper productivity.

WBM v/s OBM:-

If a kick is taken in WBM, an increase of pit level can be observed from surface shortly

after influx, this is because the inflow fluid displaces large volumes of drilling fluid as the

kick propagates.

 If using OBM instead of WBM it will yield a higher risk of a blowout compared to taking a kick in WBM. Why? The reason is that the inflow gas is dissolved into the OBM, which will increase the detection time before an action to the well control situation can be initiated.

In HPHT wells the solubility of gas in OBM is almost infinite, which means that large

amount of gas can be dissolved in OBM without detecting it. If the dissolved gas reaches

the flash point or the bubble point above the BOP before it is closed a catastrophe is the

end result and will be disastrous. 

The use of OBM is a major concern in the industry due to this lack of visibility when taking

a kick.

If a kick is suspected in OBM and mud pumps are turned off, the dissolved gas will remain

in place until circulation is initiated. The dissolved gas will when circulated move as a

passive tracer, suspended in the OBM towards the surface, until it reaches the flash point,

also called the bubble point.

This point is where gas goes out of suspension and back into free gas, and in some sense

"explode" out of suspension, lifting the entire mud column and create a major pit gain. This

may lead to a very difficult well control situation.

The result if a large kick reaches the surface are much more serious, a known example of

such a disaster is BP`s Macondo well incident in the Gulf of Mexico in 2010, where the rig

Deepwater Horizon sank, taking 11 lives, and causing one of the largest oil spills in history.