Drilling Fluids

 

Although the drilling of a well is a complex operation involving many different mechanical elements and processes,

 the single most important factor upon which the successful completion of the well depends is the drilling-fluid circulation system.

 The majority of serious problems encountered during drilling,

including lost circulation, stuck pipe, kicking wells, poor penetration performance, high costs, blowouts, and poor-quality well logs,

 can all be traced back to poorly designed, misunderstood, and misused drilling-fluid systems.

The primary functions of the drilling fluid and its circulation systems are:

1. To remove rock cuttings from the bottom of the hole so that the bit can drill on a fresh rock surface,

 thereby increasing the efficiency of the drilling operation.

2. To transport the cuttings to the surface where they can be removed from the drilling fluid.

3. To suspend the cuttings in the hole whenever mud circulation is stopped.

4. To cool and lubricate the bit and clean its cutting surface.

5. To exert sufficient hydrostatic pressure to exclude formation fluids from the hole.

6. To maintain a stable, lubricated well bore that can be reentered at any time during the drilling operation.

Oil-Base Muds

Drilling fluids that contain oil as the continuous liquid phase are called oil-base or oil muds.

 Such muds always contain some water,

and if the water is emulsified as a useful constituent, the mud is called an invert-emulsion mud.

Principal applications for oil muds are: to prevent damage to the productive formation by the drilling fluid

to drill or core evaporites

 to drill troublesome shales

 to overcome wall sticking of drill pipe

 to release stuck pipe

 to drill under extreme temperature conditions, high temperatures in very deep holes and low temperatures in permafrost and cold climates

 to place in the tubing-casing annulus and the casing-hole annulus to facilitate recovery of pipe

to drill formations containing corrosive fluids, such as hydrogen sulfide.

Oil makes up 60 to 98% of the liquids in oil muds.

 Diesel fuel is commonly used, although some crude oils are satisfactory.

 For reasons of safety, the flash point of the oil should be above 160°F.

Water, the dispersed or emulsified phase, is present in amounts of 2 to 40% by volume.

 Between 15 and 30% is normal for invert-emulsion muds.

Water from almost any source is acceptable an exception is produced water that contains emulsion breakers

 because the chemical composition of the water usually is adjusted for the particular application of the oil mud.

 For example, calcium chloride is added to the water to improve the hole stability in shale.

The other components of oil muds are varied.

 Often the oil mud is mixed at a central mixing plant and delivered to the well site where barite is added if needed.

 Although the composition differs among the several commercial oil muds,

the constituents serve to provide the properties necessary for suspension, such as organophilic clays, asphalt

emulsification, such as calcium soaps, may be formed in the system by reaction of quick lime and fatty acids

 filtration, such as asphalt, resins, lignite derivative

 oil wetting, such as lecithin

 shale stabilization, such as calcium chloride, salt

 viscosity reduction, such as petroleum sulfonates

and increase density, such as limestone, barite.

Shale Stabilization by Oil Mud

An obvious solution to hole problems arising

 from the absorption of water by shales would appear to be the use of a drilling fluid that has oil as the liquid phase.

 oil muds always contain some water and that the hole stability sometimes is affected.

Laboratory studies show that wet shales can be hardened by exposure to invert-emulsion mud

 that contains a high-salinity water in the emulsified phase.

Two methods have been used to estimate the salinity required.

The first method (Mondshine) equates the surface hydration force of shale with the matrix stress

 equal to the overburden pressure minus the pore fluid pressure.

 The salinity of the interstitial water is measured or estimated,

The other method (Chenevert) involves the measurement of the equilibrium vapor pressure of the shale

and adjustment of salinity of the emulsified water to the same or somewhat lower vapor pressure.

 As a practical field approach, the salinity of the water in the oil mud is raised to a concentration substantially

 above that estimated for the water in the shale.

Maintaining a stable emulsion takes advantage of osmotic forces across the semipermeable membrane to transfer water

from the shale into the drilling fluid. In this way, the borehole wall may be made stronger.

Gas Drilling Fluid

The term reduced-pressure drilling has been applied to drilling with a circulating medium with a density less than that of water.

 This class of drilling fluids ranges from dry gas through mist, foam, "stiff foam", to aerated mud.

The principal benefit derived from air and aerated drilling fluids is the gain in penetration rate resulting from the lowered differential pressure.

 Weak formations can be drilled without loss of circulation.

 Producing formations are not damaged by invasion of the drilling fluid.

 Problems arise with dry-air drilling water bearing strata are penetrated.

 Cuttings stick to the wet borehole and may plug the annulus.

After a water-producing formation has been entered, the amount of water coming into the hole will control the drilling rate.

If water-sensitive formations are exposed, hole problems will develop.

Often the difficulties involved in "mudding-up" an air-drilled hole offset the savings made during that period of fast drilling.

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