Drilling Fluids

Functions

  1. Remove cutting from the wellbore.
  2. Control formation pressures
  3. Suspend and release cuttings
  4. Seal permeable formations
  5. Maintain wellbore stability
  6. Minimize reservoir damage
  7. Cool, lubricate and support the bit and the drilling assembly
  8. Transmit hydraulic energy to the tools and the bit
  9. Ensure adequate formation evaluation
  10. Control Corrosion
  11. Facilitate cementing and completing
  12. Minimize impact on the environment

Cuttings Removal

As the cuttings are drilled they must be removed and brought to the surface through the annulus. The removal of the cuttings is a function of the size, shape and density in combination with the rate of penetration (ROP), drill string rotation, viscosity, density and annular velocity of the drilling fluid.

Viscosity- higher viscosities help to circulate cuttings out of the hole better. Most muds are thixotropic which means they will gel in static hole conditions. Such a characteristic can help to suspend cuttings when the mud is not being circulated (eg. between connections). For best hole cleaning fluids that are shear thinning and have elevated viscosities at low annular velocities are best used.

Velocity- higher annular velocities promote better hole cleaning. It must be noted that thinner muds reach turbulence faster which will help with hole cleaning but promote washouts. The rate at which the cuttings settle is called the slip velocity. In general the annular velocity should be greater than the slip velocity.

The net cuttings velocity = Annular velocity – Slip velocity

Cuttings transport in high angle and horizontal holes is more difficult than in vertical holes. This is due to fluid and cuttings settling on the low side of the hole. this accumulation with time may form a cuttings bed such a bed would narrow the bore hole restricting flow and increasing torque. If not used with proper hole cleaning techniques then they can be difficult to remove and may jeopardize the well bore.

Controlling Formation Pressure

While static this means that the hydrostatic presence of the fluid column is able to mitigate the normal formation pressure.

In general the well control means that there is no uncontrolled flow of fluids into the wellbore. The hydrostatic pressure is also used to balance the tectonic stresses. The inclination of the wellbore may also permit instability which could be helped by the presence of the fluid in the wellbore.

In practice the mud weight is limited to the minimum necessary for the wellbore control and stability.

Suspend and Release Cuttings

The mud must trap the cuttings while drilling but at the same time it must allow the solids control equipment to be able to remove the drilled solids.

If cuttings settle out during the drilling process then this may bridge the wellbore and cause problems. Also if the fluid is not designed properly then sag will occur and the solids will settle out of solution. Usually it will happen in a high angle well where the fluid is flowing at low annular velocities.

When cuttings get too high in concentration it will be detrimental to drilling efficiency and ROP. This would increase the mud viscosity and weight which increase the maintenance and dilution costs. The properties that promote cuttings removal must be balanced with that of solids removal.

To suspend requires high viscosity thixotropic properties while solids removal requires fluids of lower viscosity. For the best solids control the cuttings must be removed on the first circulation out of the hole. If not they are re-circulated and they may be broken down into smaller particles that may be even more difficult to remove.

Seal Permeable Formations

Permeability refers to the ability of fluids to flow though porous formations. When the mud pressure is greater than formation mud filtrate will invade the formation. Mud filer cake/ mid solids will be deposited on the wellbore wall.

A properly designed fluid system allows the deposition of a thin low permeable filter cake on the formation. This limits the further invasion of fluids. This improves wellbore stability and prevents production problems.

However if the filter cakes is too thick then the hole may be “tight” this may result in increase torque and drag, stuck pipe, lost circulation and formation damage. A thick filter cake can also reduce log quality.

For formations that are known to be highly permeable whole mud may invade the formation. In such a case effective bridging agents should be used (½ the size of the largest opening).

To achieve a good filter cake you can add bentonite, natural and synthetic polymers, asphalt, gilsonite and organic deflocculating agents.

Maintain Wellbore Stability

This is the maintenance of the balance of the complex mechanical and chemical factors of the mud.

The density and the hydrostatic properties must help to maintain pressures and stresses. However the chemical properties must help to provide an environment that won’t react with the formation.

Regardless of the chemical composition the mud weight must be maintained within the necessary range to balance the forces acting on the wellbore. Wellbore instability is often identified by sloughing shale. This often makes it necessary to ream.

When the hole maintains its original size the wellbore stability will be a maximum.

Larger hole sizes only complicate the matter at hand. When going through sand a conservative hydraulic program should be used. Sands that are poorly unconsolidated and weak require slightly overbalance to limit wellbore enlargement.

If mud weight can balance these formation pressures then this is enough and the well shall be stable. However if a water based mud is used care must be taken to avoid unnecessary interactions between the drilling fluid and the formations, chemical inhibitors may have to be added to minimize the interactions.

Highly fractured highly dipped formations can be extremely unstable when drilled. Such a failure is due to the mechanical interaction between the fluid and the rock.

Systems with high levels of calcium and potassium or other chemical inhibitors are best for drilling into salt water sensitive formations. Shale is so varied that no single additive may be applicable.

For sensitive formations oil or a synthetic bas fluid is used. They provide better shale inhibition then water based fluids. The continuous phase prevents swelling in clays and shale.

Salts may be added to further prevent inhibition. The salts prevent absorption on the water by the shale by osmosis.

Minimize Formation Damage

The drilling fluid should not impair or damage the formation reservoir in any way.

Cool and Lubricate The Bit and Assembly

If lubrication fails the BHA may fail. Poor lubrication results in high torque and drag, abnormal wear. However this is not the only thing that causes these problems.

The fluid acts like a fluid an helps to support weight of the well bore tools. this reduces the hook load on the derrick. This is of use when you may want to overdesign and exceed the rig load/parameters.

Transmit Hydraulic Energy To the Bit and Tools

Transmits power to the mud motor, as well as power to the MWD/LWD tools.

The hydraulic programme is based on sizing the bit for maximum pressure drop across the bit (50-65%). With higher densities, viscosities and solids then the pressure losses are greater.

Ensure Adequate Formation Evaluation

The drilling fluid should allow for the of or aid in the analysis of the chemical and physical composition of the formation. The fluid should allow for the proper analysis of cuttings for the hydrocarbons.

The drilling fluids must be able to transport the cuttings to the surface such that the mud logger is able to quickly analyze the formation.

When running wire-line logs the drilling fluids may affect the conductivity of the signal to and from the formation. This may affect the reading that is produced. The mud must be appropriately conditioned for the least interference to the logging job.

In general for optimum logging conditions the mud should not be too thick bit it must keep the borehole open and stable and must suspend cuttings. Too large a bore hole or to thick a filter cake may affect the logging results. This may also increase the chance of sticking the tool.

In some instances a “bland” mud is used when no effect on the formation is wanted.

Corrosion Control

The fluid must be able to get rid of gases in the mud such that it does not accelerate the corrosion of the down hole metals and tools. Also the pH should be high, lower pH tends to aggravate corrosion.

Sometimes chemical inhibitors may be added to help mitigate corrosion.

Care should be taken especially when drilling in hydrogen sulphide environments. This can lower mud pH to a point where it is dangerous to the tools in the hole. it is best to drill with high pH and use sulphide scavenging chemicals in the fluid.

Facilitate Cementing and Completion

Just as with logging the drilling fluid must provide an environment that eases the running of casing as well as cementing.

During casing running the mud should not gel, it should remain fluid so as to minimize pressure surges so as not to induce lost circulation. The mud should have a thin slick filter cake.

To properly cement then the mud must be effectively displaced by the cement spacer. For good displacement the mud should have a low viscosity and low progressive gel strength.

Minimize Environmental Impact

Eventually the mud has to be gotten rid of. The mud can be reused and reconditioned depending on the exiting condition. However it will eventually be disposed off and in this instance it must be treated properly such that it is not in breach of the environmental policies of the block that is being drilled.

 

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