Muds are a critical part of an optimised slim hole drilling system. The design of the mud for all slim wells must be closely integrated with the hydraulics program, which is in turn closely integrated with the mechanical design of the drilling, evaluation, and completion system. These interfaces are much more complex than with conventional holes.

1 Muds used for downsized conventional drilling

Muds used for downsized conventional drilling are generally conventional. Both water and oil-based muds have been used. In almost all cases polymers (rather than bentonite) should be used for friction reduction, shear thinning viscosity, and fluid loss control. The only exception is "Spud Mud" for surface hole where clearances are larger.

A shear thinning viscosity profile would be optimum. The mud viscosity should be low at high shear rates in the drillstring and through the bit nozzles, while a higher viscosity would give carrying capacity in the annulus. Such shear thinning viscosities are generated by water soluble polymers which can also act as friction reducers.

In water and the common brines, polymers usually begin to lose their properties above 125°C bottomhole circulating temperature. This applies to polymers used for both viscosity and friction reduction, such as XC-polymer and for fluid loss, such as starches and celluloses such as CMC, PAC, etc.

A high carrying capacity in the annulus is important when liners are used. For floating drilling where a 4 1/8" hole may be drilled with a 20" ID marine riser, annular carrying capacity becomes doubly important. In this case the use of booster lines would complicate the operation of the kick detection system.

The viscosity of a mud is largely dependent on four factors:

• the viscosity of the base fluid,
• the number of particles in the mud,
• the inter-particle forces,
• the use of polymeric friction reducers.

The base fluid with the lowest viscosity is water, followed by the various brines usually getting more viscous with increasing density. The viscous drag forces created by the water or brine can be reduced by the use of polymeric friction reducers such as Xanthan Gum (XC-polymer) and these should be used wherever possible.

The particles in the mud are weighting solids (such as barites, chalk, hematite, etc.), filter cake materials, lost circulation material, drilled solids, and the discontinuous phase of the emulsion (for example, the dispersed brine solutions used in invert oil emulsion muds, i.e. oil-based muds).

The inter-particle forces are due to the viscosifiers and thinners added to the mud, and the active clays from the formation being drilled.

The optimum drilling fluid for slim hole would be water or a brine with polymers for drag reduction and viscosity control and for filter loss control.

Some solids are usually required to assist in the initial formation of a filter cake. Sized chalk particles of sufficient size to bridge the formation pore throats (typically 1-30 microns) are the best filter cake material for use in brine-based drilling fluids. Typical concentrations would be 3% by weight. A thin hard external filter cake would appear to be desirable to minimise sticking tendencies of both drilling and wireline logging tools. For minimising differential sticking an internal filter cake would be preferable, although this might not be desirable from a formation damage perspective.

Some concentrated brine systems have shown strong shale stabilising effects which can help maintain borehole integrity. In difficult cases shale stabilisation may be provided by adding specialised additives, such as Tame glycols, recently developed to inhibit mud filtrate entering the pores.

Where high mud gradients are required, the optimum drilling fluids for slim holes are heavy brines as:

• The viscosities of the base fluids would be low.
• The viscosities and annular velocities required for carrying cuttings are lower as there is a flotation effect from the heavy brine.
• Weighting material is not required, thus minimising unwanted Newtonian viscosity.
• Solids removal is easier as there is no weighting material to be left in the mud.
• The resultant low concentration of drilled solids at the pump suction means that viscosifiers, thinners, and shale stabilisers are not wasted re-treating drilled solids which are constantly being re-circulated.

2 Heavy brine muds (formate brines)

• Formate brines are environmentally responsible and readily biodegradable.
• They are also easy to handle, are non hazardous and appear to be compatible with oilfield hardware.
• They are powerful anti-oxidants and can protect viscosifiers and fluid loss additives to temperatures of at least 150°C.
• They are compatible with formation waters containing sulphates and carbonates.
• They appear to contribute to shale stability.
• They are expensive, but can be efficiently recycled

The three brines of interest for SHD drilling fluids are:

Sodium formate Maximum unweighted density 1.33 SG

Potassium formate Maximum unweighted density 1.6 SG

Caesium formate Maximum unweighted density 2.37 SG

Sodium and potassium brines are now available commercially and have successfully been used to drill horizontal wells. Efforts are being made to commercialise caesium formate, initially as an alternative to zinc bromide as a completion fluid for HP/HT wells. If a mud with a density greater than 1.6 SG is required then potassium formate weighted with manganese oxide or hematite should be considered. Barite dissolves in potassium formate, and can therefore not be used. Potassium formate weighted with manganese oxide can also be considered for drilling into the reservoir.

Manganese oxide is rather less abrasive than hematite, and has a grain density of 4.8 SG, compared with 4.2 for barite and 4.7 for hematite. It has been used to weight up potassium formate mud, but with rather high viscosities which were attributed to the large number of inert particles. However the fine particles give a very thin tight HT/HP filter cake with a low fluid loss.

Hematite is very abrasive, and the grind is usually not as fine as manganese oxide. In use it tends to increase mud pump maintenance, reduce downhole tool life, and not provide as tight a filter cake. Hematite also increases casing wear.

These dense brines are very hygroscopic and need to be stored in closed tanks when not in use. The formate brines are therefore best supplied and shipped as concentrated liquids. On account of their high costs recycling in a similar manner to oil muds will probably be economic in practically all cases.

3 Hydraulics and mechanics for downsized conventional wells

The mutual interactions occurring in a system composed of a bit, a downhole motor and/or a hydraulic thruster are modelled in commercial models. This enables the user to estimate the downhole WOB and torque in thruster operations, as well as the resulting pressure drop over the motor which contributes to the standpipe pressure. But also the pressure effects in the calculation of the string tension (buckling neutral point) and total stresses are taken into account.

The laminar pressure drop calculations can be based on the flexible Herschel-Bukley model (as well as on the Power Law or Bingham Plastic models), while turbulent pressure drops are always calculated using the Power Law model. The often significant effects of the temperature and pressure variations in the well on drilling fluid rheology can be taken into account. To this end rheological measurements at different temperatures and/or pressures should be supplied by the user.

Experimental work shows that friction reducers can dramatically reduce the parasitic pressure drops down the inside of the drillpipe and up the annulus. In some cases the pressure drop was halved. However, concerns exist about the lack of repeatability of these results.

Drilling fluid compressibility and thermal expansion can have significant effects on static pressures.

ECD, SPP, static pressure, drag, torque, (thruster) WOB, string stress and fluid temperature can be plotted against AHD or TVD. These variables can be plotted as a function of two other parameters, taken from a large set including along hole depth, flow rate, mud motor and thruster characteristics, friction factors, bit/formation aggressiveness, etc. This provides a coherent frame work for planning and optimising normal and especially HP/HT wells.

4 Lost circulation for downsized conventional wells

Lost circulation for downsized conventional wells may be tackled with conventional lost circulation techniques. The pressure drop over the motor and thruster increased linearly with solids concentration. Moineau mud motors are capable of being powered by highly solids laden (up to 50%) fluids.

Minimising drillstring rotation, thus minimising the annular pressure drop can also contribute to minimising lost circulation problems, especially in HP/HT wells.

Various cross-linked gels can also be used. It may be possible to use an "internal filter cake" from such gels to provide some small measure of enhanced formation strength.

Although Moineau mud motors, and thrusters are highly resistant to plugging by LCM and weighted cement, there are still cases where running a backup circulation device or backoff sub of some sort would be prudent. Such devices would enable motors, MWDs, and thrusters to be run during critical stages in HP/HT wells. If these tools were not available then drilling of critical zones would be done with slick assemblies on rotary. This, could lead to rapid building of inclination in an uncontrolled manner due to collar buckling, twist-offs due to vibration, and slow penetration due to low power densities at the bit.

The proposed tools are:

Drilling Safety Joint. This would be run in tension and could be used to release the BHA by applying left hand torque in conjunction with 1000-2000 lb of compression. It would be used when:

1. The BHA is stuck as a safer alternative to running a backoff shot. A fishing string with jars could be latched back on.

2. In a kick loss situation to give a clear bore through the drillstring for setting a cement or LCM plugs.

If a tapered drillstring is in use (e.g. 5" ´ 3 1/2" ´ 2 7/8") then the floppy plugs from the 3 1/2" flexloc liner hanger can be run to provide isolation for the cement plug.

Drop Ball Release Sub. This is an alternative or addition to the drilling safety joint with the advantage that no rotation or set down weight is required to release the tool. The BHA below the sub is released when a ball is dropped or pumped down. The lower section can be fished with a spear.

Rupture Disc Sub. This contains a shear disc which could be sheared to provide a circulation path for cement, LCM, or heavy mud in the event of the BHA below the tool becoming plugged. The burst pressure could be controlled with an accuracy of about 10% at temperatures of up to 200°C. Care should be taken to select the pressure rating of the shear disc above the stall out differential pressure of the mud motor.