Properties Of Drilling Fluid include:
The returning mud can 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 if they ignite, special monitoring sensors and explosion-proof certified equipment is commonly installed, and workers are advised to take safety precautions. The mud is then pumped back down the hole and further re-circulated. After testing, the mud is treated periodically in the mud pits to ensure properties which optimize and improve drilling efficiency, borehole stability, and other requirements listed below.

Mud Pit
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 (annular velocity). These considerations are analogous to the ability of a stream to carry sediments; 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 is another important property, as cuttings will settle to the bottom of the well if the viscosity is too low.

Fly Ash Absorbent for Fluids in Mud Pits
Most drilling muds are thixotropic (viscosity increase during static conditions). This characteristic keeps the cuttings suspended when the mud is not flowing during drilling, for example, maintenance. Fluids that have shear thinning and elevated viscosities are efficient for hole cleaning. Higher annular velocity improves cutting transport. Transport ratio (transport velocity / lowest annular velocity) should be at least 50%.High density fluids may clean hole adequately even with lower annular velocities (by increasing the buoyancy force acting on cuttings). But may have a negative impact if mud weight is in excess of that needed to balance the pressure of surrounding rock (formation pressure), so mud weight is not usually increased for hole cleaning purposes. Higher rotary drill-string speeds introduce a circular component to 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 is the one of the best methods for increasing hole cleaning in high angle and horizontal wells.
Suspend and release cuttings
Must suspend drill cuttings, weight materials and additives under a wide range of conditions. Drill cuttings that settle can causes bridges and fill, which can cause stuck-pipe and lost circulation. Weight material that settles is referred to as sag, this 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 (it causes increased mud weight and viscosity, which in turn increases maintenance costs and increased dilution)Rate of Penetration (ROP) (increases horsepower required to circulate)Mud properties 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. Conduct a test to compare the sand content of mud at flow line and suction pit (to determine whether cuttings are being removed).
Control formation pressures
If formation pressure increases, mud density should also be increased to balance pressure and keep the well bore stable. The most common weighting material is barite. Unbalanced formation pressures will cause an unexpected influx (also known as a kick) of formation fluids in the well bore possibly leading to a blowout from pressured formation fluids. 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 well bore. Well control means no uncontrollable flow of formation fluids into the well bore. Hydrostatic pressure also controls the stresses caused by tectonic forces, these may make well bores unstable even when formation fluid pressure is balanced. If formation pressure is subnormal, air, gas, mist, stiff foam, or low density mud (oil base) can be used. In practice, mud density should be limited to the minimum necessary for well control and well bore stability. If too great it may fracture the formation.
Seal permeable formations
Mud column pressure must exceed formation pressure, in this condition mud filtrate invades the formation, and a filter cake of mud is deposited on the well bore wall. Mud is designed to deposit thin, low permeability filter cake to limit the invasion. Problems occur if a thick filter cake is formed; tight hole conditions, poor log quality, stuck pipe, lost circulation and formation damage. In highly permeable formations with large bore throats, whole mud may invade the formation, depending on mud solids size;Use bridging agents to block large opening, then mud solids can form seal. For effectiveness, bridging agents must be over the half size of pore spaces / fractures. Bridging agents (e.g. calcium carbonate, ground cellulose).Depending on the mud system in use, a number of additives can improve the filter cake (e.g. bentonite, natural & synthetic polymer, asphalt and gilsonite).
Maintain well bore stability
Chemical composition and mud properties must combine to provide a stable well bore. Weight of the mud must be within the necessary range to balance the mechanical forces. Wellbore instability = sloughing formations, which can cause tight hole conditions, bridges and fill on trips (same symptoms indicate hole cleaning problems).Well bore stability = hole maintains size and cylindrical shape. If the hole is enlarged, it becomes weak and difficult to stabilize, resulting in problems such as low annular velocities, poor hole cleaning, solids loading and poor formation evaluation in sand and sandstones formations, hole enlargement can be accomplished by mechanical actions (hydraulic forces & nozzles velocities). Formation damage is reduced by conservative hydraulics system. A good quality filter cake containing bentonite is known to limit bore hole enlargement. In shales, mud weight is usually sufficient to balance formation stress, as these wells are usually stable. With water base mud, chemical differences can cause interactions between mud & shale that lead to softening of the native rock. Highly fractured, dry, brittle shales can be extremely unstable (leading to mechanical problems).Various chemical inhibitors can control mud / shale interactions (calcium, potassium, salt, polymers, asphalt, glycol and oil – best for water sensitive formations)Oil (and synthetic oil) based drilling fluids are used to drill most water sensitive Shales in areas with difficult drilling conditions. To add inhibition, emulsified brine phase (calcium chloride) drilling fluids are used to reduce water activity and creates osmotic forces to prevent adsorption of water by Shales.
Minimizing formation damage
Skin damage or any reduction in natural formation porosity and permeability (washout) constitutes formation damage skin damage is the accumulation of residuals on the perforations and that causes a pressure drop through them .Most common damage;Mud or drill solids invade the formation matrix, reducing porosity and causing skin effect swelling of formation clays within the reservoir, reduced permeability Precipitation of solids due to mixing of mud filtrate and formations fluids resulting in the precipitation of insoluble salts mud filtrate and formation fluids form an emulsion, reducing reservoir porosity specially designed drill-in fluids or work over and completion fluids, minimize formation damage.
Cool, lubricate, and support the bit and drilling assembly
Heat is generated from mechanical and hydraulic forces at the bit and when the drill string rotates and rubs against casing and wellbore.Cool and transfer heat away from source and lower to temperature than bottom hole.If not, the bit, drill string and mud motors would fail more rapidly.Lubrication based on the coefficient of friction.("Coefficient of friction" is how much friction on side of wellbore and collar size or drill pipe size to pull stuck pipe) Oil- and synthetic-based mud generally lubricate better than water-based mud (but the latter can be improved by the addition of lubricants).Amount of lubrication provided by drilling fluid depends on type & quantity of drill solids and weight materials + chemical composition of system.Poor lubrication causes high torque and drag, heat checking of the drill string, but these problems are also caused by key seating, poor hole cleaning and incorrect bottom hole assemblies design.Drilling fluids also support portion of drill-string or casing through buoyancy. Suspend in drilling fluid, buoyed by force equal to weight (or density) of mud, so reducing hook load at derrick.Weight that derrick can support limited by mechanical capacity, increase depth so weight of drill-string and casing increase.When running long, heavy string or casing, buoyancy possible to run casing strings whose weight exceed a rig's hook load capacity.
Transmit hydraulic energy to tools and bit
Hydraulic energy provides power to mud motor for bit rotation and for MWD (measurement while drilling) and LWD (logging while drilling) tools. Hydraulic programs base on bit nozzles sizing for available mud pump horsepower to optimize jet impact at bottom well.Limited to:Pump horsepowerPressure loss inside drillstringMaximum allowable surface pressureOptimum flow rateDrill string pressure loses higher in fluids higher densities, plastic viscosities and solids.Low solids, shear thinning drilling fluids such as polymer fluids, more efficient in transmit hydraulic energy.Depth can be extended by controlling mud properties.Transfer information from MWD & LWD to surface by pressure pulse.
Ensure adequate formation evaluation
Chemical and physical mud properties and wellbore conditions after drilling affect formation evaluation.Mud loggers examine cuttings for mineral composition, visual sign of hydrocarbons and recorded mud logs of lithology, ROP, gas detection or geological parameters.Wireline logging measure – electrical, sonic, nuclear and magnetic resonance.Potential productive zone are isolated and performed formation testing and drill stem testing.Mud helps not to disperse of cuttings and also improve cutting transport for mud loggers determine the depth of the cuttings originated.Oil-based mud, lubricants, asphalts will mask hydrocarbon indications.So mud for drilling core selected base on type of evaluation to be performed (many coring operations specify a blend mud with minimum of additives).
Control corrosion (in acceptable level)
Drill-string and casing in continuous contact with drilling fluid may cause a form of corrosion.Dissolved gases (oxygen, carbon dioxide, hydrogen sulfide) cause serious corrosion problems;Cause rapid, catastrophic failureMay be deadly to humans after a short period of timeLow pH (acidic) aggravates corrosion, so use corrosion coupons[clarification needed] to monitor corrosion type, rates and to tell correct chemical inhibitor is used in correct amount.Mud aeration, foaming and other O2 trapped conditions cause corrosion damage in short period time.When drilling in high H2S, elevated the pH fluids + sulfide scavenging chemical (zinc).
Facilitate cementing and completion
Cementing is critical to effective zone and well completion.During casing run, mud must remain fluid and minimize pressure surges so fracture induced lost circulation does not occur.Temperature of water used for cement must be within tolerance of cementers performing task, usually 70 degrees, most notably in winter conditions.Mud should have thin, slick filter cake, with minimal solids in filter cake, wellbore with minimal cuttings, caving or bridges will prevent a good casing run to bottom. Circulate well bore until clean.To cement and completion operation properly, mud displace by flushes and cement. For effectiveness;Hole near gauges, use proper hole cleaning techniques, pumping sweeps at TD, and perform wiper trip to shoe.Mud low viscosity, mud parameters should be tolerant of formations being drilled, and drilling fluid composition, turbulent flow - low viscosity high pump rate, laminar flow - high viscosity, high pump rate.Mud non progressive gel strength[clarification needed]
Minimize impact on environment
Mud is, in varying degrees, toxic. It is also difficult and expensive to dispose of it in an environmentally friendly manner. A Vanity Fair article described the conditions at Lago Agrio, a large oil field in Ecuador where drillers were effectively unregulated.
Water based drilling fluid has very little toxicity, made from water, bentonite and barite, all clay from mining operations, usually found in Wyoming and in Lunde, Telemark. There are specific chemicals that can be used in water based drilling fluids that alone can be corrosive and toxic, such as hydrochloric acid. However, when mixed into water based drilling fluids, hydrochloric acid only decreases the pH of the water to a more manageable level. Caustic (sodium hydroxide), anhydrous lime, soda ash, bentonite, barite and polymers are the most common chemicals used in water based drilling fluids. Oil Base Mud and synthetic drilling fluids can contain high levels of benzene, and other chemicals
Most common chemicals added to OBM Muds Barite Bentonite Diesel Water Emulsifiers
Composition of drilling mud
Water-based drilling mud most commonly consists of bentonite clay (gel) with additives such as barium sulfate (barite), calcium carbonate (chalk) or hematite. Various thickenersare used to influence the viscosity of the fluid, e.g. xanthan gum, guar gum, glycol, carboxymethylcellulose, polyanionic cellulose (PAC), or starch. In turn, deflocculants are used to reduce viscosity of clay-based muds; anionic polyelectrolytes (e.g. acrylates, polyphosphates, lignosulfonates (Lig) or tannic acid derivates such as Quebracho) 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, then was made obsolete when lignosulfonates became available. Other components are added to provide various specific functional characteristics as listed above. Some other common additives include lubricants, shale inhibitors, fluid loss additives (to control loss of drilling fluids into permeable formations). A weighting agent such as barite is added to increase the overall density of the drilling fluid so that sufficient bottom hole pressure can be maintained thereby preventing an unwanted (and often dangerous) influx of formation fluids.
Factors influencing drilling fluid performance
Four factors affecting drilling fluid performance are:
(1)The change of drilling fluid viscosity(2)The change of drilling fluid density(3)The change of mud pH corrosion or fatigue of the drill string and (4)Thermal stability of the drilling fluid Differential sticking
Drilling mud classification
They are classified based on their fluid phase, alkalinity, dispersion and the type of chemicals used.
Dispersed systems
Freshwater mud – Low pH mud (7.0–9.5) that includes spud, bentonite, natural, phosphate treated muds, organic mud and organic colloid treated mud. high pH mud example alkaline tannate treated muds are above 9.5 in pH.Water based drilling mud that represses hydration and dispersion of clay – There are 4 types: high pH lime muds,low pH gypsum, seawater and saturated salt water muds.
Non-dispersed systems
Low solids mud – These muds contain less than 3–6% solids by volume and weight less than 9.5 lbs/gal. Most muds of this type are water-based with varying quantities of bentonite and a polymer. Emulsions – The two types used are oil in water (oil emulsion muds) and water in oil (invert oil emulsion muds).Oil based mud – Oil based muds contain oil as the continuous phase and water as a contaminant, and not an element in the design of the mud. They typically contain less than 5% (by volume) water. Oil-based muds are usually a mixture of diesel fuel and asphalt, however can be based on produced crude oil and mud
Mud engineer
"Mud engineer" is the name given to an oil field service company individual who is charged with maintaining a drilling fluid or completion fluid system on an oil and/or gas drilling rig. This individual typically works for the company selling the chemicals for the job and is specifically trained with those products, though independent mud engineers are still common. The role of the mud engineer or more properly Drilling Fluids Engineer is very critical to the entire drilling operation because even small problems with mud can stop the whole operations on rig. The internationally accepted shift pattern at off-shore drilling operations is personnel (including mud engineers) work on a 28-day shift pattern, where they work for 28 continuous days and rest the following 28 days. In Europe this is more commonly a 21-day shift pattern.
In offshore drilling, with new technology and high total day costs, wells are being drilled extremely fast. Having two mud engineers makes economic sense to prevent down time due to drilling fluid difficulties. Two mud engineers also reduce insurance costs to oil companies for environmental damage that oil companies are responsible for during drilling and production. A senior mud engineer typically works in the day, and a junior mud engineer at night.
The cost of the drilling fluid is typically about 10% (may vary greatly) of the total cost of drilling a well, and demands competent mud engineers. Large cost savings result when the mud engineer and fluid performs adequately.

Mud Pit with Fly Ash
The mud engineer is not to be confused with mudloggers, service personnel who monitor gas from the mud and collect well bore samples.
Compliance engineer
The compliance engineer is the most common name for a relatively new position in the oil field, emerging around 2002 due to new environmental regulations on synthetic mud in the United States. Previously, synthetic mud was regulated the same as water-based mud and could be disposed of in offshore waters due to low toxicity to marine organisms. New regulations restrict the amount of synthetic oil that can be discharged.
These new regulations created a significant burden in the form of tests needed to determine the "ROC" or retention on cuttings, sampling to determine the percentage of crude oil in the drilling mud, and extensive documentation. It should be noted that no type of oil/synthetic based mud (or drilled cuttings contaminated with OBM/SBM) may be dumped in the North Sea. Contaminated mud must either be shipped back to shore in skips or processed on the rigs.
A new monthly toxicity test is also now performed to determine sediment toxicity, using the amphipod Leptocheirus plumulosus. Various concentrations of the drilling mud are added to the environment of captive L. plumulosus to determine its effect on the animals. The test is controversial for two reasons:
These animals are not native to many of the areas regulated by them, including the Gulf of Mexico the test has a very large standard deviation and samples that fail badly may pass easily upon retesting.
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