Drilling fluid


In geotechnical engineering, drilling fluid, also known as drilling mud or drilling slurry, is used to aid the drilling of boreholes into the earth. Used while drilling oil and natural gas wells and on exploration drilling rigs, drilling fluids are also used for much simpler boreholes, such as water wells.
The two main categories of drilling fluids are water-based muds, which can be dispersed and non-dispersed, and non-aqueous muds, usually called oil-based muds. Along with their formatives, these are used along with appropriate polymer and clay additives for drilling various oil and gas formations. Gaseous drilling fluids, typically utilizing air or natural gas, sometimes with the addition of foaming agents, can be used when downhole conditions permit.
The main functions of liquid drilling fluids are to exert hydrostatic pressure to prevent formation fluids from entering into the well bore, and carrying out drill cuttings as well as suspending the drill cuttings while drilling is paused such as when the drilling assembly is brought in and out of the hole. The drilling fluid also keeps the drill bit cool and clears out cuttings beneath it during drilling. The drilling fluid used for a particular job is selected to avoid formation damage and to limit corrosion.

Composition

Liquid fluids are composed of natural and synthetic material in a mixed state, which can be of two types:
Water-based drilling mud most commonly consists of bentonite clay with additives such as barium sulfate to increase density, and calcium carbonate or hematite. Various thickeners are used to influence the viscosity of the fluid, e.g. xanthan gum, guar gum, glycol, carboxymethyl cellulose, polyanionic cellulose, or starch. In turn, deflocculants are used to reduce viscosity of clay-based muds; anionic polyelectrolytes are frequently used. Red mud was the name for a Quebracho-based mixture, named after the color of the red tannic acid salts; it was commonly used in the 1940s to 1950s but was made obsolete when lignosulfonates became available. Some other common additives include lubricants, shale inhibitors, fluid loss additives. A weighting agent such as baryte is added to increase the overall density of the drilling fluid so that sufficient bottom hole pressure can be maintained thereby preventing an unwanted influx of formation fluids.

Types

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Many types of drilling fluids are used on a day-to-day basis. Some wells require different types to be used in different parts of the hole, or that some types be used in combination with others. The various types of fluid generally fall into broad categories:
  • Air: Compressed air is pumped either down the bore hole's annular space or down the drill string itself.
  • Air/water: Air with water added to increase viscosity, flush the hole, provide more cooling, and/or to control dust.
  • Air/polymer: A specially formulated chemical, typically a type of polymer, is added to the water and air mixture to create specific conditions. A foaming agent is a good example of a polymer.
  • Water: Water is sometimes used by itself. In offshore drilling, seawater is typically used while drilling the top section of the hole.
  • Water-based mud : Most water-based mud systems begin with water, then clays and other chemicals are added to create a homogeneous blend with viscosity between chocolate milk and a malt. The clay is usually a combination of native clays that are suspended in the fluid while drilling, or specific types of clay processed and sold as additives for the WBM system. The most common type is bentonite, called "gel" in the oilfield. The name likely refers to the fluid viscosity as very thin and free-flowing while being pumped, but when pumping is stopped, the static fluid congeals to a "gel" that resists flow. When adequate pumping force is applied to "break the gel," flow resumes and the fluid returns to its free-flowing state. Many other chemicals are added to a WBM system to achieve desired effects, including: viscosity control, shale stability, enhance drilling rate of penetration, and cooling and lubricating of equipment.
  • Oil-based mud : Oil-based mud has a petroleum-based fluid such as diesel fuel. Oil-based muds are used for increased lubricity, enhanced shale inhibition, and greater cleaning abilities with less viscosity. Oil-based muds also withstand greater heat without breaking down. The use of oil-based muds has special considerations of cost, environmental concerns such as disposal of cuttings in an appropriate place, and the exploratory disadvantages of using oil-based mud, especially in wildcat wells. Using an oil-based mud interferes with the geochemical analysis of cuttings and cores and with the determination of API gravity because the base fluid cannot be distinguished from oil that is returned from the formation.
  • Synthetic-based fluid : Synthetic-based fluid is a mud in which the base fluid is a synthetic oil. This is most often used on offshore rigs because it has the properties of an oil-based mud, but the toxicity of the fluid fumes are much less. This is important when the drilling crew works with the fluid in an enclosed space such as an offshore drilling rig. Synthetic-based fluid poses the same environmental and analysis problems as oil-based fluid.
On a drilling rig, mud is pumped from the mud pits through the drill string, where it jets out of nozzles on the drill bit, thus clearing away cuttings and cooling the drill bit in the process. The mud then carries the crushed or cut rock up the annular space between the drill string and the sides of the hole being drilled, up through the surface casing, where it emerges from the top. Cuttings are then filtered out with either a shale shaker or the newer shale conveyor technology, and the mud returns to the mud pits. The mud pits allow the drilled "fines" to settle and the mud to be treated by adding chemicals and other substances.
The returning mud may contain natural gases or other flammable materials which will collect in and around the shale shaker/conveyor area or in other work areas. Because of the risk of a fire or an explosion, special monitoring sensors and explosion-proof certified equipment are commonly installed, and workers are trained in safety precautions. The mud is then pumped back down the hole and further re-circulated. The mud properties are tested, with periodic treating in the mud pits to ensure it has desired properties to optimize drilling efficiency and provide borehole stability.

Function

The functions of a drilling mud can be summarized as follows:

Remove well cuttings

Drilling fluid carries the rock excavated by the drill bit up to the surface. Its ability to do so depends on cutting size, shape, and density, and speed of fluid traveling up the well. These considerations are analogous to the ability of a stream to carry sediment. Large sand grains in a slow-moving stream settle to the stream bed, while small sand grains in a fast-moving stream are carried along with the water. The mud viscosity and gel strength are important properties, as cuttings will settle to the bottom of the well if the viscosity is too low.
Other properties include:
  • Most drilling muds are thixotropic. This characteristic keeps the cuttings suspended when the mud is not flowing, for example, when replacing the drill bit.
  • Fluids that have shear thinning and elevated viscosities are efficient for hole cleaning.
  • Higher annular velocity improves cutting transport. Transport ratio should be at least 50%.
  • High-density fluids may clean holes adequately even with lower annular velocities.
  • Higher rotary drill-string speeds introduce a circular component to the annular flow path. This helical flow around the drill string causes drill cuttings near the wall, where poor hole cleaning conditions occur, to move into higher transport regions of the annulus. Increased rotation speed is one of the best methods for increasing hole cleaning in high-angle and horizontal wells.

    Suspend and release cuttings

One of the functions of drilling mud is to carry cuttings out of the hole.
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  • Drilling mud must suspend drill cuttings and weight materials under a wide range of conditions.
  • Drill cuttings that settle can cause bridges and fill, which can cause stuck pipe and lost circulation.
  • Heavy material that settles is referred to as sag, which causes a wide variation in the density of well fluid. This more frequently occurs in high-angle and hot wells.
  • High concentrations of drill solids are detrimental to drilling efficiency because they increase mud weight and viscosity, which in turn increases maintenance costs and increased dilution.
  • Drill cuttings that are suspended must be balanced with properties in cutting removal by solids control equipment.
  • For effective solids controls, drill solids must be removed from mud on the 1st circulation from the well. If re-circulated, cuttings break into smaller pieces and are more difficult to remove.
  • A test must be conducted to compare the solids content of mud at the flow line and suction pit.

    Control formation pressures

  • If formation pressure increases, mud density should be increased to balance pressure and keep the wellbore stable. The most common weighting material is baryte. Unbalanced formation pressure will cause an unexpected influx of formation fluids into the wellbore possibly leading to a blowout from pressurized formation fluid.
  • Hydrostatic pressure = density of drilling fluid * true vertical depth * acceleration of gravity. If hydrostatic pressure is greater than or equal to formation pressure, formation fluid will not flow into the wellbore.
  • Well being under control means no uncontrollable flow of formation fluids into the wellbore.
  • Hydrostatic pressure also controls the stress from tectonic forces, which can render wellbores unstable even when formation fluid pressure is balanced.
  • If formation pressures exposed in the open borehole are subnormal, air, gas, mist, stiff foam, or low-density mud can be used.
  • In practice, mud density should be limited to the minimum necessary for well control and wellbore stability. If too great it may fracture the formation.