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Aid for drilling boreholes into the ground

This article is about fluids used when drilling a well. For fluids used with drill bits during metal working, see cutting fluid.

In geotechnical engineering, drilling fluid, also called drilling mud, is used to aid the drilling of boreholes into the earth. Often 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. One of the functions of drilling mud is to carry cuttings out of the hole.

The three main categories of drilling fluids are: water-based muds (WBs), which can be dispersed and non-dispersed; non-aqueous muds, usually called oil-based muds (OBs); and gaseous drilling fluid, in which a wide range of gases can be used. Along with their formatives, these are used along with appropriate polymer and clay additives for drilling various oil and gas formations.

The main functions of drilling fluids include providing hydrostatic pressure to prevent formation fluids from entering into the well bore, keeping the drill bit cool and clean during drilling, carrying out drill cuttings, and suspending the drill cuttings while drilling is paused and when the drilling assembly is brought in and out of the hole. The drilling fluid used for a particular job is selected to avoid formation damage and to limit corrosion.

Types [edit]

Source: ^[1]

Many types of drilling fluids are used on a day-to-day basis. Some wells require different types to be used at different parts in the hole, or for some types to be used in combination with others. The various types of fluid generally fall into a few broad categories:^[2]

• Air: Compressed air is pumped either down the bore hole's annular space or down the drill string itself.
• Air/water: The same as above, with water added to increase viscosity, flush the hole, provide more cooling, and/or to control dust.
• Air/polymer: A specially formulated chemical, most often referred to as 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 by itself is sometimes used. In offshore drilling, seawater is typically used while drilling the top section of the hole.
• Water-based mud (WBM): Most basic water-based mud systems begin with water, then clays and other chemicals are incorporated into the water to create a homogeneous blend resembling something between chocolate milk and a malt (depending on viscosity). The clay is usually a combination of native clays that are suspended in the fluid while drilling, or specific types of clay that are processed and sold as additives for the WBM system. The most common of these is bentonite, frequently referred to in the oilfield as "gel." Gel likely makes reference to the fact that while the fluid is being pumped, it can be very thin and free-flowing (like chocolate milk), though when pumping is stopped, the static fluid builds a "gel" structure that resists flow. When an adequate pumping force is applied to "break the gel," flow resumes and the fluid returns to its previously free-flowing state. Many other chemicals (e.g. potassium formate) are added to a WBM system to achieve various effects, including: viscosity control, shale stability, enhance drilling rate of penetration, and cooling and lubricating of equipment.
• Oil-based mud (OBM): Oil-based mud is a mud where the base fluid is a petroleum product such as diesel fuel. Oil-based muds are used for many reasons, including 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, including cost, environmental considerations 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 (SBM) (Otherwise known as Low Toxicity Oil Based Mud or LTOBM): 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 than an oil-based fluid. 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 sprays out of nozzles on the drill bit, thus cleaning and cooling the drill bit in the process. The mud then carries the crushed or cut rock ("cuttings") up the annular space ("annulus") between the drill string and the sides of the hole being drilled, up through the surface casing, where it emerges back at the surface. 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 let the drilled "fines" settle; the pits are also where the fluid is treated by adding chemicals and other substances.

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 trained in 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 there are the desired properties that optimize and improve drilling efficiency, borehole stability, and other requirements, as listed below.

Function [edit]

The main functions of a drilling mud can be summarized as follows:^[1]

Remove cuttings from well [edit]

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 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 is another important property, as cuttings will settle to the bottom of the well if the viscosity is too low.

Other properties include:

• Most drilling muds are thixotropic (viscosity increase during static conditions). This characteristic keeps the cuttings suspended when the mud is not flowing during, 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 holes 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 [edit]

Source:^[1]

• Must suspend drill cuttings, weight materials and additives under a wide range of conditions.
• Drill cuttings that settle can cause 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 [edit]

Source:^[1]

• If formation pressure increases, mud density should also be increased to balance pressure and keep the wellbore 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 wellbore 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 wellbore.
• Well control means no uncontrollable flow of formation fluids into the wellbore.
• Hydrostatic pressure also controls the stresses caused by tectonic forces, these may make wellbores 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 wellbore stability. If too great it may fracture the formation.

Seal permeable formations [edit]

Source:^[1]

• 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 wellbore 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 wellbore stability [edit]

Source:^[1]

• Chemical composition and mud properties must combine to provide a stable wellbore. 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).
• Wellbore 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, glycols 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 [edit]

Source:^[1]

• 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 workover and completion fluids, minimize formation damage.

Cool, lubricate, and support the bit and drilling assembly [edit]

Source:^[1]

• 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 [edit]

Source:^[1]

• 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 horsepower
  • Pressure loss inside drillstring
  • Maximum allowable surface pressure
  • Optimum flow rate
  • Drill string pressure loses higher in fluids of 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 [edit]

Source:^[1]

• Chemical and physical mud properties as well as 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 bland mud with minimum of additives).

Control corrosion (in acceptable level) [edit]

Source:^[1]

• 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 failure
  • May be deadly to humans after a short period of time
• Low 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 [edit]

Source:^[1]

• 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 [edit]

Source:^[1]

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.^[3]

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
• Emulsifiers
• Water

Composition of drilling mud [edit]

Source: ^[4]

Water-based drilling mud most commonly consists of bentonite clay (gel) with additives such as barium sulfate (barite), calcium carbonate (chalk) or hematite. Various thickeners are 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 [edit]

Some factors affecting drilling fluid performance are:^[5]

• Fluid Rheology^[6]
• The change of drilling fluid viscosity
• The change of drilling fluid density
• The change of mud pH
• Corrosion or fatigue of the drill string^[7]
• Thermal stability of the drilling fluid^[8]
• Differential sticking

Drilling mud classification [edit]

They are classified based on their fluid phase, alkalinity, dispersion and the type of chemicals used.

Dispersed systems [edit]

• 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 [edit]

• 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 [edit]

"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.^[9] 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.

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 [edit]

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. 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.^[10] The test is controversial for two reasons:

1. These animals are not native to many of the areas regulated by them, including the Gulf of Mexico
2. The test has a very large standard deviation, and samples that fail badly may pass easily upon retesting^[11]

See also [edit]

References [edit]

Further reading [edit]

• ASME Shale Shaker Committee (2005). The Drilling Fluids Processing Handbook. ISBN 0-7506-7775-9.
• Kate Van Dyke (1998). Drilling Fluids, Mud Pumps, and Conditioning Equipment.
• G. V. Chilingarian & P. Vorabutr (1983). Drilling and Drilling Fluids.
• G. R. Gray, H. C. H. Darley, & W. F. Rogers (1980). The Composition and Properties of Oil Well Drilling Fluids.
• DCS Shale Shaker SUPPLIER. The Drilling Fluids cleaning system.

Cricket delivery

Bowling, in cricket, is the action of propelling the ball toward the wicket defended by a batsman. A player skilled at bowling is called a bowler;^[1] a bowler who is also a competent batter is known as an all-rounder. Bowling the ball is distinguished from throwing the ball by a strictly specified biomechanical definition, which restricts the angle of extension of the elbow.^[2] A single act of bowling the ball towards the batsman is called a ball or a delivery. Bowlers bowl deliveries in sets of six, called an over. Once a bowler has bowled an over, a teammate will bowl an over from the other end of the pitch.^[3] The Laws of Cricket govern how a ball must be bowled.^[4] If a ball is bowled illegally, an umpire will rule it a no-ball.^[5] If a ball is bowled too wide of the striker for the batsman to be able to play at it with a proper cricket shot, the bowler's end umpire will rule it a wide.^[6]

There are different types of bowlers, from fast bowlers, whose primary weapon is pace, through swing and seam bowlers who try to make the ball deviate in its course through the air or when it bounces,^[7] to slow bowlers, who will attempt to deceive the batter with a variety of flight and spin. A spin bowler usually delivers the ball quite slowly and puts spin on the ball, causing it to turn at an angle while bouncing off the pitch.^[8]

A team can be said to have elected to "have a bowl" when it wins the coin toss and chooses to field.^[9]

History [edit]

In the early days of cricket, underarm bowling was the only method employed. Many theories exist about the origins of cricket. One suggests that the game began among shepherds hitting a stone or a ball of wool with their crooks and, at the same time, defending the wicket gate into the sheep-fold (from Anglo Saxon 'cricce', a crooked staff). A second theory suggests the name came from a low stool known as a 'cricket' in England, which from the side looked like the long, low wicket used in the early days of the game (originally from the Flemish 'krickstoel', a low stool on which parishioners knelt in church). There is also a reference to 'criquet' in North-East France in 1478 and evidence that the game evolved in South-East England in the Middle Ages.

In 1706 William Goldwyn published the first description of the game. He wrote that two teams were first seen carrying their curving bats to the venue, choosing a pitch and arguing over the rules to be played. They pitched two sets of wickets, each with a "milk-white" bail perched on two stumps; toss a coin for first knock, the umpire called "play" and the "leathern orb" was bowled. They had four-ball overs, the umpires leant on their staves (which the batters had to touch to complete a run), and the scorers sat on a mound making notches.

The first written "Laws of Cricket" were drawn up in 1744. They stated, "the principals shall choose from amongst the gentlemen present two umpires who shall absolutely decide all disputes. The stumps must be 22 inches high and the bail across them six inches. The ball must be between 5 & 6 ounces, and the two sets of stumps 22 yards apart". There were no limits on the shape or size of the bat. It appears that 40 notches was viewed as a very big score, probably due to the bowlers bowling quickly at shins unprotected by pads. The world's first cricket club was formed in Hambledon in the 1760s and the Marylebone Cricket Club (MCC) was founded in 1787.

During the 1760s and 1770s it became common to pitch the ball through the air, rather than roll it along the ground. This innovation gave bowlers the weapons of length, deception through the air, plus increased pace. It also opened new possibilities for spin and swerve. In response, batters had to master timing and shot selection. One immediate consequence was the replacement of the curving bat with the straight one. All of this raised the premium on skill and lessened the influence of rough ground and brute force. It was in the 1770s that the modern game began to take shape. The weight of the ball was limited to between five and a half and five and three-quarter ounces, and the width of the bat to four inches. The latter ruling followed an innings by a batter called Thomas "Daddy" White, who appeared with a bat the width of the wicket. In 1774, the first leg before law was published. Also around this time, a third stump became commonplace. By 1780, the duration of a first-class cricket match was generally three days, and this year also saw the creation of the first six-seam cricket ball. In 1788, the MCC published its first revision of the laws, which prohibited charging down an opponent and also provided for mowing and covering the wicket to standardise conditions. The desire for standardisation reflected the massive increase in the popularity of cricket during the 18th century. Between 1730 and 1740, 150 cricket matches were recorded in the papers of the time. Between 1750 and 1760, this figure rose to 230, and between 1770 and 1790 over 500.

The 19th century saw a series of significant changes. Wide deliveries were outlawed in 1811. The circumference of the ball was specified for the first time in 1838 (its weight had been dictated 60 years earlier). Pads, made of cork, became available for the first time in 1841, and these were further developed following the invention of vulcanised rubber, which was also used to introduce protective gloves in 1848. In the 1870s, boundaries were introduced – previously, all hits had to be run; if the ball went into the crowd, the spectators would clear a way for the fieldsman to fetch it. The biggest change, however, was in how the ball was delivered by the bowler.

At the start of the century, all bowlers were still delivering the ball under-arm. However, so the story goes, John Willes became the first bowler to use a "round-arm" technique after practising with his sister Christina, who had used the technique, as she was unable to bowl underarm due to her wide dress impeding her delivery of the ball.^[11]

The round-arm action came to be employed widely in matches but was quickly determined to be illegal and banned by the MCC, who stated that "the ball must be delivered underhand, not thrown or jerked, with the hand underneath the elbow at the time of delivering the ball".^[12] When it was accepted the rules stated that the arm could not be raised above the shoulder. It was quickly found, however, that a raised arm imparted more accuracy and generated more bounce than the roundarm method. Again, the governing body banned the method. It was not until the method was finally accepted by the MCC in 1835^[13] that it grew rapidly in popularity amongst all players. Underarm bowling hitherto had almost disappeared from the game.

Modern-day underarm bowling [edit]

An infamous "underarm bowling incident" occurred during a match in 1981, in which the Australian bowler, Trevor Chappell, took advantage of the fact that underarm bowling was still legal by rolling the ball along the ground. By doing so he avoided the possibility that the New Zealand batsman, Brian McKechnie, would score a six from the last ball to tie the match, as the bat would not be able to hit the ball high enough to score a six.^[14]

As a result of this incident underarm bowling was subsequently made illegal in all grades of cricket, except by prior agreement of both teams, as it was not considered to be within the spirit of the game.

The bowling action [edit]

Bowling the ball is distinguished from simply throwing the ball by a strictly specified biomechanical definition.

Originally, this definition said that the elbow joint must not straighten out during the bowling action. Bowlers generally hold their elbows fully extended and rotate the arm vertically about the shoulder joint to impart velocity to the ball, releasing it near the top of the arc. Flexion at the elbow is not allowed, but any extension of the elbow was deemed to be a throw and would be liable to be called a no-ball. This was thought to be possible only if the bowler's elbow was originally held in a slightly flexed position.

In 2005, this definition was deemed to be physically impossible by a scientific investigative commission. Biomechanical studies that showed that almost all bowlers extend their elbows somewhat throughout the bowling action, because the stress of swinging the arm around hyperextends the elbow joint. A guideline was introduced to allow extensions or hyperextensions of angles up to 15 degrees before deeming the ball illegally thrown.

Bowling actions are typically divided into side on and front on actions. In the side on action, the back foot lands parallel to the bowling crease and the bowler aims at the wicket by looking over his front shoulder. In the front on action, the back foot lands pointing down the pitch and the bowler aims at the wicket by looking inside the line of his front arm. Many bowlers operate with a mid-way action with the back foot landing at roughly 45 degrees and the upper body aligned somewhere between side on and front on. This differs from a mixed action, which mixes distinct elements of both side on and front on actions, and is generally discouraged amongst young bowlers as it can lead to problems in later life due to the twisting of the back inherent in the action.

Goals of bowling [edit]

In a game of cricket, the ultimate priority of the fielding side is to restrict the total number of runs scored by the batting side, and the actions of the bowlers will be fundamental to achieving this objective. The primary means of achieving this is by dismissing the batting side by getting all ten of the opposition wickets as quickly as possible. A secondary objective will be to keep the batting side's run rate as low as possible. In fact, in most forms of cricket, the twin aims of the fielding side are targeted concurrently, as the achievement of one aim tends to have a positive effect upon the other. Taking regular opposition wickets will remove the better batsmen from the crease, typically leading to a slowing of the scoring rate. Conversely, slowing the scoring rate can put additional pressure on the batsmen and force them into taking extra risks, which will often lead to wickets.

Depending upon the format of the match, these two strategies will be given different weights. In an unlimited, timed or declaration match, the main aim of the bowling attack will be to take wickets, so attacking bowling and fielding strategies will be used. In a limited overs match, this aim will also be supplemented by the secondary need to prevent the batting side from scoring quickly, so more defensive strategies will be used. In general, the shorter the number of overs per side, the more priority will be given to this secondary target of maintaining a low run-rate. It is also highly probable that the need for attacking or defensive strategies can switch frequently as a cricket match progresses. It is the sign of a good cricket captain to be able to tell which strategy is most appropriate in any set of circumstances and the best way of implementing it.

Bowling tactics [edit]

The simultaneous twin objectives of bowling are to take wickets and prevent run scoring opportunities. Both objectives are achieved through the underlying aim of bowling the ball in such a way that the batsman is unable to connect with the ball in the middle of the bat and control its movement after contact. There are three distinct means of achieving this aim: by bowling the ball on a good line and length, by bowling with sufficient pace that the batsman struggles to react to the delivery, or by bowling the ball in such a way that it has lateral movement as it approaches the batsman, either in the air or off the ground. A good bowler may be able to combine two of these skills, a truly great bowler may be able to combine all three.

Line and length [edit]

The fundamental skill of bowling on a good length incorporates the ability to pitch the ball such a distance from the batsman that he is unable to move forward and drive the ball on the half volley, and is also unable to step back and play the ball on the back foot. This removes many of the batsman's attacking options, and also increases the probability of him misjudging a delivery and losing his wicket. A good length delivery is one in which the ball has had sufficient time to move far enough off the pitch to beat the bat but the batsman has not had time to react to the movement and adjust his shot. The faster the bowler and the greater the movement he is able to generate, the larger the area of the pitch that can be designated an effective "good" length.

Other areas of the pitch may also often be used as a variation to a good length delivery. Primarily these are the yorker, in which the ball is bowled directly at the batsman's feet as a surprise delivery intended to dismiss the batsman bowled, and the bouncer in which the ball is bowled on such a short length that it rises towards the batsman's throat or head as a means of physical intimidation. But the height of an attempted yorker or full toss must not be higher than the batsman's waist, or else it will be called a no-ball beamer, which could have bowlers banned from the match.

The line a bowler chooses to bowl will depend on several factors: the movement he is generating on the ball, the shots the batsman is able to play, and the field the captain has set. The two most common tactics are to either bowl directly at the stumps, or to bowl 3 inches to 6 inches outside the line of off stump. Bowling at the stumps is an attacking tactic with the intention of dismissing the batsman bowled or lbw. It can also be used as a defensive tactic, as the batsman will feel less able to play risky shots knowing that he will be dismissed should he miss the ball. Bowling outside off stump is known as the corridor of uncertainty. When done well, this line may confuse the batsman into whether to defend the ball or leave it, and may tempt him to play away from his body with his head not in line with the ball. The main aim of this tactic is to dismiss the batman caught by the wicketkeeper or in the slips. Other bowling variations, such as bowling wide of off stump or bowling at leg stump are generally seen as negative and defensive tactics.

Some different types of bowling tactic:

• Bodyline
• Leg theory
• Off theory

Pace and movement [edit]

Other than the ability to land the ball on a strategically optimum line and length, the main weapons of the bowler are his ability to move the ball sideways as it approaches the batsman and his ability to deliver the ball at a high velocity.

The velocities of cricket bowlers vary between 40 and 100 mph (64 and 161 km/h). In professional cricket, a bowler in the 40–60 mph range would be said to be a slow bowler, in the 60–80 mph range a medium pace bowler, and a bowler 80 mph+ a fast bowler. In the amateur game, these distinctions would be approximately 10 mph slower. Many professional fast bowlers are able to reach speeds of over 85 mph, with a handful of bowlers in the world able to bowl at 95 mph+. The ability to react to a cricket ball travelling at 85 mph is a skill that only professional and high level amateur cricketers possess. The pace of a bowler not only challenges the reaction speed of the batsman, but also his physical courage. Fast bowlers are able to exploit this by bowling bouncers, either regularly or as an occasional surprise delivery.

Bowlers are also able to get the ball to move sideways by using either spin or swing. Adding a spin to a cricket ball will make it deviate due to the Magnus effect in its flight, and then produce sideways movement off the ground. Swing is obtained by using air pressure differences caused by angling the seam of the cricket ball to produce a lateral movement in the air. Fast bowlers will generally only use swing to obtain movement, but medium pace and slow bowlers will often use a combination of the two. The intention is that in creating movement in the delivery, the batsman will misjudge the line of the ball as it arrives, causing him to miss it entirely, in which case he may be dismissed bowled or lbw, or miss-hit it, in which case he may be out caught.

To avoid becoming predictable, a bowler will typically bowl a variety of different deliveries with different combinations of pace and movement. A tactically astute bowler may be able to spot a potential weakness in a batsman that a particular delivery may be able to exploit. Bowlers will often also bowl deliveries in preplanned sets, with the intention of dismissing the batsman with the final delivery in the set. This is known as "setting a trap" for the batsman.^[15] Batsmen and bowlers will often also engage in a game of "cat and mouse", in which the bowler varies his tactics to try and trap and dismiss the batsman, but the batsman also keeps adjusting his tactics in response.

Limited overs [edit]

In limited overs cricket, there is a limitation on the number of overs each bowler can bowl. This number depends on the match length, and is usually 20% of the total overs in the innings. For example, the usual limit for twenty-over cricket is four overs per bowler, for forty-over cricket eight per bowler and for fifty-over cricket ten per bowler. There is, however, no limit on the number of overs each bowler may bowl in first-class cricket matches, except that no two overs can be bowled consecutively thus restricting any one bowler from a maximum of 50% (plus 1 over) of each innings total. The rule also applies in terms of breaks within a Test innings (Drinks, Lunch and Tea breaks, end of day and beginning of next day). The rule can only be broken if one finishes the end of the previous match starts the next match.

See also [edit]

• Glossary of cricket terms
• Throwing
• Bowling machine
• Fielding
• Batting
• Over
• Pitch – throwing a baseball

References [edit]

Further reading [edit]

• https://www.britannica.com/sports/bowling-cricket