Oil well control

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Oil well control is the management of harmful effects caused by the release of unexpected formation fluids, such as natural gas and/or crude oil, on surface equipment of oil or gas drilling rigs and escaping into the atmosphere. Technically, oil well control involves preventing fluid formation, commonly referred to as a kick, from entering the borehole during drilling.

Formation fluids may enter the wellbore if the pressure provided by the drilling fluid column is not sufficiently large to overcome the pressure provided by the liquid in the drilled formation. Well oil controls also include well monitoring for signs of entry of formation fluid into drill holes during drilling and procedures, to stop the well flowing when it occurs by taking appropriate corrective action.

Failure to regulate and control the effects of this pressure may cause equipment damage and serious injury, or loss of life. Improperly managed control situations can cause explosions, ie the expulsion of unregulated and explosive formation fluids from wells, potentially leading to fires.

Video Oil well control

Importance of oil well control

Control of oil wells is one of the most important aspects of drilling operations. Improper handling of kicks in the control of an oil well can lead to an explosion with very serious consequences, including the loss of valuable resources. Although the cost of the explosion (as a result of bad control/no oil) can easily reach several million US dollars, monetary losses are not as serious as other damages that could occur: irreparable damage to the environment, valuable resource waste, damaged, and most importantly, the safety and life of personnel in drilling rigs.

To avoid the consequences of the explosion, attention should be paid to the control of oil wells. That is why an oil well control procedure must exist before the start of the abnormal situation seen in the wellbore, and ideally when the new rig position is laid. In other words, this includes the time a new location is taken, all drilling, completion, workover, snubbing and any other drilling related operations to be carried out with good oil well control in mind. This type of preparation involves the training of widespread personnel, the development of rigorous operational guidelines and the design of drill programs - maximizing the likelihood of successfully regaining hydrostatic control of the wells after significant influx of formation fluid has occurred.

Maps Oil well control

Basic concepts and terminology

Pressure is a very important concept in the oil and gas industry. Pressure can be defined as: a given force per unit area. The SI unit is newton per square meter or pascal. Another unit, bar, is also widely used as a measure of pressure, with 1 bar equal to 100 kilopascals. Typically pressure is measured in the US oil industry in units of pounds per square inches wide, or psi. 1000 psi equals 6894.76 kilo-pascal.

Hydrostatic pressure

Hydrostatic pressure (HSP), as stated, is defined as pressure due to a column of immobile fluid. That is, static fluid columns, or at rest, exert pressure due to localized gravitational force on the fluid column.

The formula for calculating the hydrostatic pressure in SI units (N/m²) is:

Hydrostatic pressure = Height (m) ≤ "Density (kg/mÃ,³) ÃÆ'â €" Gravity (m/sÃ,²).

All liquids in hydrostatic pressure use a drill hole, which is a density function and vertical height of the liquid column. In US oilfield units, hydrostatic pressure may be expressed as:

HSP = 0,052 ÃÆ'â € " MW TVD ' TVD is the true vertical depth of the foot and < b> HSP is the hydrostatic pressure in psi.

0.052 is required as a conversion factor to the HSP psi unit.

To convert this unit into an SI unit, one can use:

• 1 ppg =? 119.826 4273 kg/m ³
• 1Ã, ft = 0.3048 meters
• 1 psi = 0.0689475729 slats
• 1 bar = 10 ⁵ pascal
• 1bar = 15 psi

Gradient pressure

The pressure gradient is described as the pressure per unit length. Often in the control of oil wells, the pressure given by the fluid is expressed in the pressure gradient. SI unit is pascal/meter. The hydrostatic pressure gradient can be written as:

Gradient pressure (psi/ft) = HSP/TVD = 0.052 ÃÆ'â € "MW (ppg).

Pressure formation

The formation pressure is the pressure given by the formation fluid, which is the liquid and gas contained in the geological formations encountered during drilling for oil or gas. This can also be said to be the pressure contained in the pores of the drilled formation or reservoir. The formation pressure is the result of the hydrostatic pressure of the formation fluid, above the depth of the flower, together with the pressure trapped in the formation. Under formation pressure, there are 3 levels: normally pressed formations, abnormal formation pressure, or under normal formation pressure.

Usually pressing formation

The normally pressed formation has the same formation pressure as the hydrostatic pressure of the liquid above it. Since the liquid above the formation is usually water, this pressure can be defined as the pressure given by the water column from the depth of the formation to the sea surface.

The normal hydrostatic pressure gradient for fresh water is 0.433 pounds per square inch per foot (psi/ft), or 9,792 kilopascals per meter (kPa/m), and 0.465 psi/ft for water with dissolved solids such as in Gulf Coast waters, or 10,516 kPa/m. Formal water densities in the saline or marine environment, such as along the Gulf Coast, are approximately 9.0 ppg or 1078.43 kg/mÃ,³. Since this is the highest for Bay water and fresh water, the formations normally suppressed can be controlled by pG 9.0 slurries.

Sometimes overburden weight, which refers to rocks and liquids above the formation, will tend to solidify the formation, so pressure is built up inside the formation if the fluid is trapped in place. The formation in this case will maintain normal pressure only if there is communication with the surface. Otherwise, pressure abnormal formation will occur.

Abnormal forming pressure

As discussed above, once the liquid is trapped in the formation and it is not possible to escape there is pressure leading to an abnormally high formation pressure. This generally requires a mud weight greater than 9.0 ppg to be controlled. Excess pressure, called "overpressure" or "geopressure", can cause the well to explode or become out of control during drilling.

Normal formation pressure

The abnormal formation pressure is a formation pressure that is less than normal pressure for the given depth. It is common in formations that have undergone the production of hydrocarbons or native formation liquids in them.

Overburden pressure

overburden pressure is the pressure given by the weight of the stone and contains the liquid over the flower zone. Overburden pressure varies in different regions and formations. It is a force that tends to compact the formation vertically. The density of this ordinary rock range is about 18 to 22 ppg (2,157 to 2,636 kg/m ³ ). This density range will produce an overburden pressure gradient of about 1 psi/ft (22.7 kPa/m). Typically, 1 psi/ft does not apply to shallow marine sediments or massive salt. But offshore, there are lighter seawater columns, and underwater rock columns do not reach the surface. Therefore, lower overburden pressure is usually produced at offshore depths, rather than those found at the same depth on land.

Mathematically, overburden pressure can be reduced as:

S =? _b ÃÆ'â € "D ÃÆ'â €" g

Where

g = acceleration due to gravity

S = overburden load

? _b = average bulk density formation

D = vertical sediment thickness above it

Bulk density of sediments is a function of rock matrix density, porosity within pore space boundaries, and porefluid density. This can be expressed as

? _b = ?? _f (1 -?)? _m

Where

? = rock porosity

? _f = formation fluid density

? _m = rock matrix density

Fractures Pressure

Fractures Pressure can be defined as the pressure required to cause the formation to fail or split. As the name suggests, it is the pressure that causes the crack formation and the circulating fluid to be lost. Fracture stress is usually expressed as a gradient, with the general unit being psi/ft (kPa/m) or ppg (kg/m ³ ).

To break formation, three things are generally required:

1. Pumps into the formation. This will require the pressure in the wellbore larger than the formation pressure.
2. The pressure in the drill hole must also exceed the strength of the rock matrix.
3. And finally the wellbore pressure must be greater than one of the three main pressures in the formation.

Pump pressure (loss of system pressure)

The pump pressure , also referred to as loss of system pressure , is the sum total of all pressure losses from oil well surface equipment, drill pipe, drill collar, drill, and annular friction loss around drill collars and drill pipes. It measures the loss of system pressure at the beginning of the circulatory system and measures total friction pressure.

Slow pump pressure (SPP)

Slow pumping pressure is the circulation pressure (the pressure used to pump fluid through all active fluid systems, including drill holes and all surface tanks that are the main systems during drilling) at reduced levels. SPP is particularly important during good killing operations in which the circulation (a process in which the drilling fluid is circulated out of the suction hole, down the drill pipe and drill bit, bit out, up the annulus, and back to the pit while drilling the results) is carried out at a level reduced to allow better control of circulating pressure and to allow the properties of the sludge (density and viscosity) to be stored at the desired value. Slow pump pressure can also be referred to as "level of killing pressure" or "slow circulation pressure" or "speed killing pressure" and so on.

Shut-in drill pipe pressure

Shut-in drill pipe pressure (SIDPP), recorded when a well is closed in the kick, is a measure of the difference between the pressure at the bottom of the hole and the hydrostatic pressure (HSP) inside the wind pipe. As the well is closed, the pressure from the wellbore is stable, and the formation pressure is equal to the pressure at the bottom of the hole. The current drillpipe should be full of known density liquids. Therefore, formation pressure can be easily calculated using SIDPP. This means that SIDPP provides direct formation pressure during a kick.

Shut-in casing pressure (SICP)

The closed casing pressure (SICP) is a measure of the difference between the formation pressure and the HSP in the annulus when the kick occurs.

The pressure encountered in the annulus can be estimated using the following mathematical equations:

FP = HSP _mud HSP _entry SICP

where

FP = formation pressure (psi)

HSP _mud = Hydrostatic pressure from the mud at the annulus (psi)

HSP _entry = Hydrostatic pressure from the inlet (psi)

SICP = closed casing pressure (psi)

Lower bottom pressure (BHP)

Lower bottom pressure (BHP) is pressure on the bottom of the well. Pressure is usually measured at the bottom of the hole. This pressure can be calculated in a fluid-filled drilled well with the equation:

BHP = D ÃÆ'â € "? ÃÆ'â € "C,

where

BHP = bottom hole pressure

D = deep vertical depth

? = density

C = conversion factor units

(or, in the English system, BHP = D ÃÆ'â € "MWD ÃÆ'â €" 0.052).

In Canada the formula is depth in meters x density in kg x of constant gravity factor (0.00981), which will provide hydrostatic pressure from wellbore or hp = bhp with a dead pump. The pressure of the bottom hole depends on the following:

• Hydrostatic pressure (HSP)
• Dead surface pressure (SIP)
• Frictional pressure
• Tidal pressure (occurs when transient pressure increases the pressure of the bottom hole)
• Swaying pressure (occurs when transient pressure reduces bottom hole pressure)

Therefore, BHP can be said to be the sum of all the pressure at the bottom of the wellbore, which is equal to:

BHP = HSP SIP Friction Surge - swab

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Basic calculation in oil well control

There are some basic calculations that need to be done during the control of the oil well. Some of these important calculations will be discussed below. Most units here are US oil field units, but these units can be converted to their equivalent SI units using the Conversions link of this unit.

Capacity

The capacity of the drill bit is an important issue in the control of oil wells. The capacity of drillpipe, drill collars or holes is the volume of fluid that can be contained in it.

The capacity formula as shown below:

Capacity = ID ² /1029.4

where

Capacity = Volume in barrel per foot (bbl/ft)

ID = In-inch diameter

1029.4 = Unit conversion factor

Also the volume of pipe or total hole is provided by:

Volume in barrel (bbls) = Capacity (bbl/ft) ÃÆ'â € "long (ft)

The pipe feet occupied by the given volume are provided by:

Pipe foot (ft) = Sludge volume (bbls)/ Capacity (bbls/ft)

An important capacity calculation in the control of oil wells is due to the following:

• Drillpipe and drill collar volumes must be pumped to kill heavy muds to bits during killing operations.
• This is used to view pills and plugs at various depths in the wellbore.

Annular Capacity

This is the volume that exists between the inner diameter of the hole and the outer diameter of the pipe. Annular capacity is given by:

Annular Capacity (bbl/ft) = (ID _hole ² - OD _pipe < soup> 2 )/1029.4

where

ID _holes ² = Inside of the case or hole open in inches

OD _pipes ² = Outside diameter of the pipe

Similarly

Annular volume (bbls) = Annular capacity (bbl/ft) ÃÆ'â € "long (ft)

and

Legs are occupied by sludge volume at annulus = Solid Volume (bbls)/ Annular Capacity (bbls/ft).

Decreased fluid level

Decreasing fluid level is the distance that will be dropped by the mud level when the dry rope (slightly unplugged) is pulled from the well hole and is given by:

Decrease level of fluid = Bbl disp/(CSG cap Pipe disp)

or

Decrease in liquid level = Bbl disp/(close Ann Close pipe)

and the loss of HSP resulting from:

Missing HSP = 0,052 ÃÆ'â € "MW ÃÆ'â €" Decreased liquid

where

Fluid decreases = drop fluid distance (ft)

Bbl disp = pulled pulled pipes (bbl)

CSG cap = casing capacity (bbl/ft)

Pipa disp = pipeline transfer (bbl/ft)

Annot Capacity between casing and pipe (bbl/ft)

Close pipe = pipe capacity

Missing HSP = Missing hydrostatic pressure (psi)

MW = mud weight (ppg)

When pulling the wet straps (bits plugged) and the liquid from the nasal pipe is not returned to the hole. The fluid decrease is then changed to the following:

Decrease in liquid level = Bbl disp / Ann cap

Kill Mud Load (KMW)

Kill Mud weight is the mud density required to balance the formation pressure during the killing operation. The Kill Weight Mud can be calculated by:

KWM = SIDPP/(0,052 ÃÆ'â € "TVD) OWM

where

KWM = kill heavy mud (ppg)

SIDPP = closed drillpipe pressure (psi)

TVD Ã, = true vertical depth (ft)

OWM Ã, = original weight mud (ppg)

But when formation pressure can be determined from data sources such as down hole pressure, then KWM can be calculated as follows:

KWM = FP /0,052 ÃÆ'â € " TVD

di mana FP = Tekanan formasi.

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Kicks

Kick is the entry of formation fluid into the wellbore during drilling operation. This occurs because the pressure provided by the drilling fluid column is not large enough to overcome the pressure provided by the liquid in the drilled formation. The whole essence of oil well control is to prevent kicking and if it happens to prevent it from developing into an explosion. Uncontrolled kicks usually result from not deploying the right equipment, using poor practice, or lack of training from the crew of the rig. The loss of oil well control can lead to an explosion, which is one of the most serious threats associated with exploring petroleum resources involving life risks and environmental and economic consequences.

Cause of kick

The kick will occur when the bottom hole pressure (BHP) of a well falls below formation pressure and the forming fluid flows into the wellbore. Usually there are causes of kicks that some of them are:

• Failure to keep a full hole during the trip
• Swabbing while stumbling
• Circulation is missing
• Insufficient liquid
• Abnormal pressures
• Drill to adjacent well
• Loss of control during drill test
• Incorrect filling on trip

Failure to keep the full hole during the trip

Tripping is a complete operation to remove the drillstring from the wellbore and run it back into the hole. This operation is usually performed when the bit (which is a tool used to destroy or cut stones during drilling) becomes dull or damaged, and no longer drills the rock efficiently. Typical drilling operations of deep or gas wells may require up to 8 or more trips of drill strings to replace the dulled rotary bits for one well.

Stumbling out of the hole means that the entire volume of steel (borstring) is being removed, or has been removed, from the well. The displacement of this drill string will leave the volume of space to be replaced by the same mud volumes. If replacement is not made, the level of fluid in the wellbore will decrease, resulting in loss of hydrostatic pressure (HSP) and lower hole pressure (BHP). If this downward pressure drop occurs under formation pressure, a kick will definitely happen.

Swabbing while tripping

Swabbing occurs when the down hole pressure is reduced due to the effect of pulling the drill strap up in a boring hole. During the journey out of the hole, the space formed by pipes, collar collars, or tubes (which are being removed) must be replaced with something, usually mud. If the trip rate out is greater than the rate of sludge pumped into the empty space (created by the drill string deletion), then the cotton will occur. If the downward pressure reduction of the hole is caused by swabbing under formation pressure, then a kick will occur.

Loss of circulation

Loss of circulation usually occurs when hydrostatic pressure breaks open formation. When this happens, there is a loss in the circulation, and the fluid column height decreases, causing the HSP to be low in the wellbore. Kicks can occur if steps are not taken to keep the hole full. The lost circulation can be caused by:

• excess mud weight
• excessive annular friction loss
• excessive spike pressure during trip, or "spudding" bit
• excessive closing pressure.

Insufficient fluid density

If the drilling fluid density or mud in the well is not sufficient to keep the formation pressure in check, then a kick may occur. Drilling fluid density is not sufficient as a result of the following:

• is trying to drill using an unbalanced weight solution
• excessive dilution of mud
• heavy rain in the pit
• barite settled in the pit
• find a pill with low density in the well.

Abnormal pressure

Another cause of the kick is the accidental drilling into the normally pressed permeable zone. Increased formation pressure may be greater than down hole pressure, resulting in a kick.

Drill to adjacent well

Drilling to adjacent wells is a potential problem, especially in offshore drilling where a large number of directional wells are drilled from the same platform. If a wellbore penetrates the string of production from a well that has been completed before, the formation fluid from the completed well will enter the wellbore well, causing the kick. If this happens at shallow depths, it is a very dangerous situation and can easily produce an uncontrollable explosion with little or no warning of the event.

Loss of control during drill test

The drill-bar test is performed by arranging the packers above the formation to be tested, and allowing the formation to flow. During testing, the borehole or casing is under the packaging, and at least a portion of the drill pipe or tube, filled with formation fluid. At the end of the test, this fluid should be removed with appropriate control techniques to return the well to a safe condition. Failure to follow the correct procedure to kill the well can cause an explosion.

Incorrect charging on trip

Incorrect filling of the journey occurs when the volume of the drilling fluid to keep the full hole on the Journey (complete operation to remove the drillstring from the wellbore and run it back into the hole) is less than calculated or less than the Trip Book Record. This condition is usually caused by formation fluid entering the wellbore due to the wiretapping action of the drill string, and, if the action is not done immediately, the well will enter the kick state.

Kicking a warning sign

In the control of the oil wells, the kick must be detectable immediately, and if a kick is detected, proper kick count prevention operations should be carried out immediately to avoid explosions. There are some signs that mark the crew warning that the kick will start. Knowing these signs will make the oil kick well under control, and avoid explosions:

Sudden increase in drilling rate

A sudden increase in the penetration rate (break drilling) is usually caused by changes in the type of drilled formation. However, this also indicates an increase in pore pressure formation, which may indicate a possible kick.

Annulus flow rate increase

If the rate at which the pump is running remains constant, then the flow of the annulus must be constant. If the annulus flow increases without corresponding change in the pumping rate, this additional flow is caused by formation fluid (s) entering the wellbore or gas expansion. It will show you the upcoming kicks.

Get in hole volume

If there is an unexplained increase in the surface sludge volume in the pit (a large tank holding the drilling fluid on the rig), it could indicate an upcoming kick. This is because when the formation fluid gets into the wellbore, it causes more drilling fluid to flow from the annulus than to pump down the drill string, so that the volume of fluid in the hole (s) increases.

Change pump speed/pressure

Decrease in pump pressure or increase in pump speed may occur as a result of decreasing hydrostatic pressure from the annulus when formation fluid enters the wellbore. When the lighter formation fluid flows into the wellbore, the hydrostatic pressure provided by the annular column of the liquid decreases, and the drilling fluid in the drill pipe tends to the U-tube to the annulus. When this happens, the pump pressure will drop, and the pump speed will increase. Lower pump pressure and increased symptoms of pump speed can also be an indication of holes in drill strings, commonly referred to as washout. Until confirmation can be made whether a washing or a healthy kick has occurred, the kick must be assumed.

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Oil well control category

There are basically three types of oil well controls: primary oil well control, secondary oil well control, and tertiary oil well control. The types are described below.

Control of the Main Well

The control of the primary oil well is a process that maintains hydrostatic pressure in the wellbore larger than the fluid pressure in the drilled formation, but less than the pressure of fracture formation. This uses the weight of the sludge to provide sufficient pressure to prevent the entry of formation fluid into the wellbore. If the hydrostatic pressure is less than the formation pressure, then the formation fluid will enter the wellbore. If the hydrostatic pressure of the fluid in the wellbore exceeds the pressure of the formation fracture, the fluid inside the well may be lost. In extreme cases of circulatory loss, formation pressure may exceed hydrostatic pressures, allowing formation fluid to enter the well.

Secondary Oil Well Control

Control of secondary oil wells after the control of Primary oil wells failed to prevent formation fluid from entering the wellbore. This process is stopped using "blowout preventer", a BOP, to prevent the discharge of wellbore well from the well. Because the rams and BOP stung remain closed, the pressure test is built and the weight of the killer slurry is calculated and pumped inside the well to kill the kick and pass it out.

Tertiary Well Control (or shaving) oil

The control of the tertiary oil well describes the third line of defense, in which the formation can not be controlled by primary or secondary well controls (hydrostatic and equipment). This happens in an underground explosion situation. The following are examples of control of tertiary wells:

• Drill an aid well to hit a nearby well that flows and kills a well with heavy mud
• Rapid pumping of heavy sludge to control wells with equivalent circulation density
• Barit pump or heavy weighting agent to clog the wellbore to stop flowing
• Cement pump for installing wellbore

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Shut-in Procedure

Using a shut-in procedure is one of the oil control measures to reduce the kick and prevent the explosion from happening. The Shut-in procedure is a special procedure for closing the well in case of a kick. When there are positive indications of the observed kick, such as a sudden increase in flow, or an increase in the pit level, the well should be closed immediately. If the closure of the well is not done immediately, an explosion is likely to occur.

Closing procedures are usually developed and practiced for each rig activity, such as drilling, tripping, logging, tubular run, drill truck testing, and so on. The main purpose of a special closing procedure is to minimize the volume of kicks that enter the wellbore when a kick occurs, regardless of what phase of rig activity takes place. However, closing procedures are company-specific procedures, and company policies will determine how wells should be closed.

They are generally two types of Shut-in procedures that are: soft shut-in, or shut-in hard.

Of the two methods, hard shut-in is the fastest method to close the well; therefore, will minimize the volume of kicks allowed into the wellbore.

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Yah kill procedure

Suicide procedure is a method of control of oil wells. Once the well has been closed on the kick, the proper killing procedure should be done immediately. The general idea in a well-killing procedure is to circulate any formation of fluid already in a wellbore during a kick, and then circulate the weight of a suitable killer slurry called Kill Weight Mud (KWM) into the well without allows further. fluid into the hole. If this can be done, then after the slurry mud has completely circulated around the well, it is possible to open the well and restart normal operations. Generally, a heavy killing mud mix (KWM), which provides only hydrostatic balance for formation pressure, is circulated. This allows around constant pressure of the lower hole, which is slightly larger than the formation pressure to be maintained, since the killing circulation takes place due to the additional small circulating frictional pressure. After circulation, the well opens again.

The main well killer procedures used in the control of oil wells are listed below:

• Wait and Weight
• Drilling method
• Outstanding and Weight
• Concurrent Methods
• Inverted Circulation
• Dynamic Murder Procedure
• Undo
• Volumetric Method
• Lubricate and Bleed

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Incident control of oil wells - root cause

There will always be potential problems of control of oil wells, as long as there are drilling operations anywhere in the world. Most of these good control issues are the result of some errors and can be eliminated, although some are inevitable. Because we know the consequences of a good control failure, efforts must be made to prevent some human error that is the root cause of this incident. These causes include:

• Lack of knowledge and skills of rig personnel
• Incorrect work practices
• Lack of understanding of oil well control training
• Lack of implementation of policies, procedures, and standards
• Inadequate risk management

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Organization to build a good control culture

An effective oil-control culture can be established within the company by requiring good control training of all rig workers, by assessing the competence of good controls in the rigsite, and by supporting qualified personnel in carrying out safe well control practices during the drilling process. Such a culture also requires personnel involved in the control of oil wells to commit to following appropriate procedures at the right time. Clearly communicated policies and procedures, credible training, competency guarantees, and management support can minimize and reduce good control incidents. An effective control culture is also built on technically competent personnel who are also trained and skilled in crew resource management (discipline in human factors), which consists of situational awareness, decision making (problem-solving), communication, teamwork, and leadership. Training programs are developed and accredited by organizations such as the International Drilling Contractors Association (IADC) and the International Control Forum (IWCF).

The IADC, headquartered in Houston, TX, is a nonprofit industry association that accredits good control training through a program called WellSharp, which aims to provide the necessary knowledge and practical skills necessary to control it well. The training consists of drilling activities and health services, as well as the level of courses applicable to everyone involved in supporting or conducting drilling operations - from office support staff to floorhands and drillers and to the most experienced supervisors. The training as included in the WellSharp program and the courses offered by IWCF contribute to the competence of the personnel, but actual competencies can only be assessed at the work site during the operation. Therefore, IADC also accredits the industry's competency assurance program to help ensure the quality and consistency of the competency assurance process for drilling operations. IADC has regional offices worldwide and accredits companies worldwide. IWCF is an NGO, headquartered in Europe, whose primary objective is to develop and manage good control certification programs for personnel employed in oil well drilling and for workover operations and good intervention operations.

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See also

• Explosion (drilling wells)
• Oil well fire
• Formation fluid
• Oil well

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References

Source of the article : Wikipedia