The Drilling Rig Components

The drilling rig components.

A mud tank is an open-top container, typically made of steel, to store drilling fluid on a drilling rig. They are also called mud pits, because they used to be nothing more than pits dug out of the earth. The tanks are generally open-top and have walkways on top to allow a worker to traverse and inspect the level of fluid in the tanks. The walkways also allow access to other equipment mounted on top. Recently, offshore drilling rigs have closed-in tanks for

safety. The mud tank plays a critical role in mechanically removing destructive solids and sediment from costly land and offshore drilling systems.[1] A drilling rig normally has two tanks. A tank is sectioned off into compartments. A compartment may include a settling tank, sometimes called a sand trap, to allow sand and other solids in the drilling fluid to precipitate before it flows into the next compartment. Other compartments may have agitators, which are large fan blades stirring the fluid to prevent its contents from precipitating. The pipe work linking the mud tanks/pits with the mud pumps is called the suction line. This may be gravity fed or charged by centrifugal pumps to provide additional volumetric efficiency to the mud pumps. Shale shakers are devices that remove drill cuttings from the drilling fluid that is used for boring holes into the earth. Controlling the solids in drilling fluid is an important component of the cost of drilling, so research into improved shaker design is ongoing.

Contents [hide]    

1 Shale shaker design 2 Shaker Screen Panels 3 Causes of screen failure 4 Screen Panel Designation

[edit] Shale shaker design Shale shakers typically consist of large, flat sheets of wire mesh screens or sieves of various mesh sizes that shake or vibrate the drill cuttings, commonly shale, across and off of the screens as the drilling fluid (mud) flows through them and back into the drilling fluid system. This separates the solid drill cuttings from the fluid so that it can be recirculated back down the wellbore. In oilfield industry, linear motion shale shakers are widely used.

[edit] Shaker Screen Panels

Shaker Screen Panel Screen panels play a major role by removing particles larger than the mesh size. Screen selection is critical since shaking is the primary stage in the removal of solids. Improper screen selection can lead to de-blinding[clarification needed], loss of drilling fluids, premature pump part failures, overloading of other solids removal equipment within the mud systems, decreased service life, reduced flow rate capacity, and serious problems in the wellbore.

[edit] Causes of screen failure The causes of premature screen failure are:[citation needed]            

Personnel improperly trained on handling, storage, maintenance and installation of deck rubbers and screens Careless storage of screen panels prior to use Screens damaged before use from improper handling during installation Shaker screen not match very well to shale shaker Deck rubbers improperly installed Deck rubbers dirty, worn or missing Dried cuttings or drilling fluid left on screen during shutdown of shaker Personnel walking on screens or using the shaker as a work table Tools being dropped on screens Extremely high mud weights or heavy solids loading Defective or improperly manufactured screens Use of high pressure wash guns to clean plugged screens

A mud tank is an open-top container, typically made of steel, to store drilling fluid on a drilling rig. They are also called mud pits, because they used to be nothing more than pits dug out of the earth. The tanks are generally open-top and have walkways on top to allow a worker to traverse and inspect the level of fluid in the tanks. The walkways also allow access to other equipment mounted on top. Recently, offshore drilling rigs have closed-in tanks for safety. The mud tank plays a critical role in mechanically removing destructive solids and sediment from costly land and offshore drilling systems.[1] A drilling rig normally has two tanks. A tank is sectioned off into compartments. A compartment may include a settling tank, sometimes called a sand trap, to allow sand and other solids in the drilling fluid to precipitate before it flows into the next compartment. Other compartments may have agitators, which are large fan blades stirring the fluid to prevent its contents from precipitating. The pipe work linking the mud tanks/pits with the mud pumps is called the suction line. This may be gravity fed or charged by centrifugal pumps to provide additional volumetric efficiency to the mud pumps.

[edit] Mud tanks for solids control Mud tanks are the base of solids control equipment. Mud tanks for solids control systems are divided into Square tanks and Cone-shaped tanks according to the shape of the tank bottom. The body of the tank is made by welding the steel plate and section, using the smooth cone-shape structure or the corrugated structure. The mud tank surface and passages are made of slip resistant steel plate and expanded steel plate.The mud tanks are made of the side steel pipe, all of the structure can be folded without barrier and pegged reliably. The surface of the tank is equipped with a water pipeline for cleaning the surface and equipment on the tank, it uses soaked zinc processing for the expanded steel plate. The ladder is made of channel steel to take responsibility the body, the foot board is made of expanded steel plate. The two-sided guard rail are installed the safe suspension hook. The mud tank is designed the standard shanty to prevent the sand and the rain. The pipeline is installed in the tank to preserve the warm air heat. Mud tank quantity depends on mud process capacity requirements. Especially for mud storage, suitable for mud pump, drilling rig, etc.

A mud pump is a reciprocating piston/plunger device designed to circulate drilling fluid under high pressure (up to 7,500 psi (52,000 kPa) ) down the drill string and back up the annulus. Mud pumps come in a variety of sizes and configurations but for the typical petroleum drilling rig, the triplex (three piston/plunger) mud pump is the pump of choice. Duplex mud pumps (two piston/plungers) have generally been replaced by the triplex pump, but are still common in developing countries. Two later developments are the hex pump with six vertical pistons/plungers, and various quintuplex's with five horizontal piston/plungers. The advantages that these new pumps have over convention triplex pumps is a lower mud noise which assists with better MWD and LWD retrieval. The "normal" mud pump consist of two main sub-assemblies, the fluid end and the power end. The fluid end produces the pumping process with valves, pistons, and liners. Because these components are high-wear items, modern pumps are designed to allow quick replacement of these parts. To reduce severe vibration caused by the pumping process, these pumps incorporate both a suction and discharge pulsation dampener. These are connected to the inlet and outlet of the fluid end. The power end converts the rotation of the drive shaft to the reciprocating motion of the pistons. In most cases a crosshead crank gear is used for this. Parts of mud pump: 1.housing itself. 2.liner with packing. 3.cover plus packing. 4.piston and piston rod. 5.suction valve and discharge valve with their seats. 6.stuffing box (only in double-acting pumps). 7.gland (only in double-acting pumps). An electric motor is an electromechanical device that converts electrical energy into mechanical energy. Most electric motors operate through the interaction of magnetic fields and currentcarrying conductors to generate force. The reverse process, producing electrical energy from mechanical energy, is done by generators such as an alternator or a dynamo; some electric motors can also be used as generators, for example, a traction motor on a vehicle may perform both tasks. Electric motors and generators are commonly referred to as electric machines. Electric motors are found in applications as diverse as industrial fans, blowers and pumps, machine tools, household appliances, power tools, and disk drives. They may be powered by direct current, e.g., a battery powered portable device or motor vehicle, or by alternating current from a central electrical distribution grid or inverter. The smallest motors may be found in electric wristwatches. Medium-size motors of highly standardized dimensions and characteristics provide convenient mechanical power for

industrial uses. The very largest electric motors are used for propulsion of ships, pipeline compressors, and water pumps with ratings in the millions of watts. Electric motors may be classified by the source of electric power, by their internal construction, by their application, or by the type of motion they give. The physical principle behind production of mechanical force by the interactions of an electric current and a magnetic field, Faraday's law of induction, was discovered by Michael Faraday in 1831. Electric motors of increasing efficiency were constructed from 1821 through the end of the 19th century, but commercial exploitation of electric motors on a large scale required efficient electrical generators and electrical distribution networks. The first commercially successful motors were made around 1873. Some devices convert electricity into motion but do not generate usable mechanical power as a primary objective, and so are not generally referred to as electric motors. For example, magnetic solenoids and loudspeakers are usually described as actuators and transducers,[1] respectively, instead of motors. Some electric motors are used to produce torque or force.[2] This article provides insufficient context for those unfamiliar with the subject. Please help improve the article with a good introductory style. (November 2009)

Vibrating hose

A draw-works is the primary hoisting machinery that is a component of a rotary drilling rig. Its main function is to provide a means of raising and lowering the traveling blocks. The wire-rope drilling line winds on the drawworks drum and extends to the crown block and traveling blocks, allowing the drill string to be moved up and down as the drum turns. The segment of drilling line from the draw-works to the crown block is called the "fast line". The drilling line then enters the sheaves of the crown block and is makes several passes between the crown block and traveling block pulleys for mechanical advantage. The line then exits the last sheave on the crown block and is fastened to a derrick leg on the other side of the rig floor. This section of drilling line is called the "dead line". A modern draw-works consists of five main parts: the drum, the motor(s), the reduction gear, the brake, and the auxiliary brake. The motors can be AC or DC-motors, or the draw-works may be connected directly to diesel engines using metal chain-like belts. The number of gears could be one, two or three speed combinations. The main brake, usually operated manually by a long handle, may be friction band brake, a disc brake or a modified clutch. It serves as a parking brake when no motion is desired. The auxiliary brake is connected to the drum, and absorbs the energy released as heavy loads are lowered. This brake may use eddy current rotors or water-turbine-like apparatus to convert to heat the kinetic energy of a downward-moving load being stopped.

Power catheads (winches) located on each side provide the means of actuating the tongs used to couple and uncouple threaded pipe members. Outboard catheads can be used manually with ropes for various small hoisting jobs around the rig. The drawworks often has a pulley drive arrangement on the front side to provide turning power to the rotary table, although on many rigs the rotary table is independently powered. A rig standpipe is a solid metal pipe attached to the side of a drilling rig's derrick that is a part of its drilling mud system. It is used to conduct drilling fluid from the mud pumps to the kelly hose. Bull plugs, pressure transducers and valves are found on the rig standpipe. A Kelly hose (also known as a mud hose or rotary hose) is a flexible, steel reinforced, high pressure hose that connects the standpipe to the kelly (or more specifically to the goose-neck on the swivel above the kelly) and allows free vertical movement of the kelly while facilitating the flow of drilling fluid through the system and down the drill string.[1] Goose neck : the last part of the kelly hose that is linked to the swivel.

A traveling block is the freely moving section of a block and tackle that contains a set of pulleys or sheaves through which the drill line (wire rope) is threaded or reeved and is opposite (and under) the crown block (the stationary section). The combination of the traveling block, crown block and wire rope drill line gives the ability to lift weights in the hundreds of thousands of pounds. On larger drilling rigs, when raising and lowering the derrick, line tensions over a million pounds are not unusual. In a drilling rig, the drill line is a multi-thread, twisted wire rope that is threaded or reeved through the traveling block and crown block to facilitate the lowering and lifting of the drill string into and out of the wellbore. On larger diameter lines, tension strengths over a million pounds are possible. To make a connection is to add another segment of drill pipe onto the top the drill string. A segment is added by pulling the kelly above the rotary table, stopping the mud pump, hanging off the drill string in the rotary table, unscrewing the kelly from the drill pipe below, swinging the kelly over to permit connecting it to the top of the new segment (which had been placed in the mousehole), and then screwing this assembly into the top of the existing drill string. Mud circulation is resumed, and the drill string is lowered into the hole until the bit takes weight at the bottom of the hole. Drilling then resumes.

A crown block is the stationary section of a block and tackle that contains a set of pulleys or sheaves through which the drill line (wire rope) is threaded or reeved and is opposite and above the traveling block. The combination of the traveling block, crown block and wire rope drill line gives the ability to lift weights in the hundreds of thousands of pounds. On larger drilling rigs, when raising and lowering the derrick, line tensions over a million pounds are not unusual.

A derrick is a lifting device composed of one tower, or guyed mast such as a pole which is hinged freely at the bottom. It is controlled by lines (usually four of them) powered by some means such as man-hauling or motors, so that the pole can move in all four directions. A line runs up it and over its top with a hook on the end, like with a crane. It is commonly used in docks and onboard ships. Some large derricks are mounted on dedicated vessels, and are often known as "floating derricks". The device was named for its resemblance to a type of gallows from which a hangman's noose hangs. The derrick type of gallows in turn got its name from Thomas Derrick, an English executioner from the Elizabethan era.

Monkey Board

A Stand (of drill pipe) is two or three joints of drill pipe connected and stood in the derrick vertically, usually while tripping pipe. A stand of collars is similar, only made up of collars and a collar head. The collar head is screwed into the collar to allow it to be picked up by the elevators. Stands are emplaced inside of the "board" of the drilling rig. They are usually kept between "fingers". Most boards will allow stands to go ten stands deep and as much as fifty stands wide on land based rigs. The stands are further held in place using ropes in the board which are tied in a shoe knot by the derrickman. Stands are emplaced on the floor of the drilling rig by the chain hand. When stands are being put onto the floor the chainhand is said to be "racking stands". After the bottom of the stand is placed on the floor, the derrickman will unlatch the elevators and pull the stand in either with a rope or with just his arms. When stands are being put back into the hole, the derickman will slam the stand into the elevators to force them to latch. The chainhand will brace against the stand to control it when the driller picks it up. This is referred to as "tailing the pipe" as the chain hand will hold the pipe and allow it to semidrag them back to the hole. The chain hand then passes it off to the tong hand, who then "stabs" the stand into the pipe already in the hole. Rigs are generally sized by how many stands they can hold in their derrick. Most land based rigs are referred to as "triples" because they hold three joints per stand in their derrick. "Singles" generally do not hold any pipe in the derrick and instead require pipe to be laid down during a pipe trip. A Swivel (Top Drive Section TDS) is a mechanical device used on a drilling rig that hangs directly under the traveling block and directly above the kelly drive, that provides the ability for the kelly (and subsequently the drill string) to rotate while allowing the traveling block to remain in a stationary rotational position (yet allow vertical movement up and down the derrick) while simultaneously allowing the introduction of drilling fluid into the drill string.

A kelly drive refers to a type of well drilling device on an oil or gas drilling rig that employs a section of pipe with a polygonal (three-, four-, six-, or eight-sided) or splined outer surface, which passes through the matching polygonal or splined kelly (mating) bushing and rotary table. This bushing is rotated via the rotary table and thus the pipe and the attached drill string turn while the polygonal pipe is free to slide vertically in the bushing as the bit digs the well deeper. When drilling, the drill bit is attached at the end of the drill string and thus the kelly drive provides the means to turn the bit (assuming that a downhole motor is not being used). The kelly is the polygonal tubing and the kelly bushing is the mechanical device that turns the kelly when rotated by the rotary table. Together they are referred to as a kelly drive. The upper end of the kelly is screwed into the swivel, using a left-hand thread to preclude loosening from the right-hand torque applied below. The kelly typically is about 10 ft (3 m) longer than the drill pipe segments, thus leaving a portion of newly drilled hole open below the bit after a new length of pipe has been added ("making a connection"), and the drill string has been lowered until the kelly bushing engages again in the rotary table. The kelly hose is the flexible, high-pressure hose connected from the standpipe to a gooseneck pipe on a swivel above the kelly and allows the free vertical movement of the kelly while facilitating the flow of the drilling fluid down the drill string. A rotary table is a mechanical device on a drilling rig that provides clockwise (as viewed from above) rotational force to the drill string to facilitate the process of drilling a borehole.

In the diagram, #20 (in blue) is the rotary table. The kelly drive #19, is inserted through the center of the rotary table and kelly bushings, and has free vertical (up & down) movement to allow downward force to be applied to the drill string, while the rotary table rotates it. (Note: Force is not actually applied from the top (as to push) but rather the weight is at the bottom of the drill string like a pendulum on a string.)

Components [edit] Chain Drive

Most rotary tables are chain driven. These chains resemble very large bicycle chains. The chains require constant oiling to prevent burning and seizing. [edit] Rotary Locks

Virtually all rotary tables are equipped with a rotary lock. Engaging the lock can either prevent the rotary from turning in one particular direction, or from turning at all. This is commonly used by crews in lieu of using a second pair of tongs to makeup or break out pipe. [edit] Bushings

The rotary bushings are located at the center of the rotary table. These can generally be removed in two separate pieces to facilitate large items, i.e. drill bits, to pass through the rotary table. The large gap in the center of the rotary bushings is referred to as the "bowl" due to its appearance. The bowl is where the slips are set to hold up the drill string during connections and pipe trips as well as the point the drill string passes through the floor into the wellbore. The rotary bushings connect to the kelly bushings to actually induce the spin required for drilling.

[edit] Alternatives Most recently manufactured rigs no longer feature rotary drives. These newer rigs have opted for top drive technology. In top drive, the drill string is turned by mechanisms located in the top drive that is attached to the blocks. There is no need for the swivel because the top drive does all the necessary actions. The top drive does not eliminates the kelly bar and the kelly bushings.

[edit] Terminology Rotary speed is the number of times the rotary table makes one full revolution in one minute (rpm). The Drill Floor is the heart of any drilling rig and is also known as the pad. This is the area where the drill string begins its trip into the earth. It is traditionally where joints of

pipe are assembled, as well as the BHA (bottom hole assembly), drilling bit, and various other tools. This is the primary work location for roughnecks and the driller. The drill floor is located directly under the derrick. A Bell nipple is a section of large diameter pipe fitted to the top of the blowout preventers that the flow line attaches to via a side outlet, to allow the drilling fluid to flow back over the shale shakers to the mud tanks. A blowout preventer is a large, specialized valve used to seal, control and monitor oil and gas wells. Blowout preventers were developed to cope with extreme erratic pressures and uncontrolled flow (formation kick) emanating from a well reservoir during drilling. Kicks can lead to a potentially catastrophic event known as a blowout. In addition to controlling the downhole (occurring in the drilled hole) pressure and the flow of oil and gas, blowout preventers are intended to prevent tubing (e.g. drill pipe and well casing), tools and drilling fluid from being blown out of the wellbore (also known as bore hole, the hole leading to the reservoir) when a blowout threatens. Blowout preventers are critical to the safety of crew, rig (the equipment system used to drill a wellbore) and environment, and to the monitoring and maintenance of well integrity; thus blowout preventers are intended to be fail-safe devices. The term BOP (pronounced B-O-P, not "bop") is used in oilfield vernacular to refer to blowout preventers. The abbreviated term preventer, usually prefaced by a type (e.g. ram preventer), is used to refer to a single blowout preventer unit. A blowout preventer may also simply be referred to by its type (e.g. ram). The terms blowout preventer, blowout preventer stack and blowout preventer system are commonly used interchangeably and in a general manner to describe an assembly of several stacked blowout preventers of varying type and function, as well as auxiliary components. A typical subsea deepwater blowout preventer system includes components such as electrical and hydraulic lines, control pods, hydraulic accumulators, test valve, kill and choke lines and valves, riser joint, hydraulic connectors, and a support frame. Two categories of blowout preventer are most prevalent: ram and annular. BOP stacks frequently utilize both types, typically with at least one annular BOP stacked above several ram BOPs. (A related valve, called an inside blowout preventer, internal blowout preventer, or IBOP, is positioned within, and restricts flow up, the drillpipe. This article does not address inside blowout preventer use.) Blowout preventers are used at land and offshore rigs, and subsea. Land and subsea BOPs are secured to the top of the wellbore, known as the wellhead. BOPs on offshore rigs are mounted below the rig deck. Subsea BOPs are connected to the offshore rig above by a

drilling riser that provides a continuous pathway for the drill string and fluids emanating from the wellbore. In effect, a riser extends the wellbore to the rig.

Use The invention of blowout preventers was instrumental in reducing the incidence of oil gushers, blowouts, indicating that substantial improvement is needed.[1] Blowout preventers come in a variety of styles, sizes and pressure ratings. Several individual units serving various functions are combined to compose a blowout preventer stack. Multiple blowout preventers of the same type are frequently provided for redundancy, an important factor in the effectiveness of fail-safe devices. The primary functions of a blowout preventer system are to:   

Confine well fluid to the wellbore; Provide means to add fluid to the wellbore; Allow controlled volumes of fluid to be withdrawn from the wellbore.

Additionally, and in performing those primary functions, blowout preventer systems are used to:      

Regulate and monitor wellbore pressure; Center and hang off the drill string in the wellbore; Shut in the well (e.g. seal the void, annulus, between drillpipe and casing); “Kill” the well (prevent the flow of formation fluid, influx, from the reservoir into the wellbore) ; Seal the wellhead (close off the wellbore); Sever the casing or drill pipe (in case of emergencies).

In drilling a typical high-pressure well, drill strings are routed through a blowout preventer stack toward the reservoir of oil and gas. As the well is drilled, drilling fluid, "mud", is fed through the drill string down to the drill bit, "blade", and returns up the wellbore in the ring-shaped void, annulus, between the outside of the drill pipe and the casing (piping that lines the wellbore). The column of drilling mud exerts downward hydrostatic pressure to counter opposing pressure from the formation being drilled, allowing drilling to proceed. When a kick (influx of formation fluid) occurs, rig operators or automatic systems close the blowout preventer units, sealing the annulus to stop the flow of fluids out of the wellbore. Denser mud is then circulated into the wellbore down the drill string, up the annulus and out through the choke line at the base of the BOP stack through chokes (flow restrictors) until downhole pressure is overcome. Once “kill weight” mud extends from the bottom of the well to the top, the well has been “killed”. If the integrity of the well is intact drilling may be resumed. Alternatively, if circulation is not feasible it may be possible to kill the well by "bullheading", forcibly pumping, in the heavier mud from the

top through the kill line connection at the base of the stack. This is less desirable because of the higher surface pressures likely needed and the fact that much of the mud originally in the annulus must be forced into receptive formations in the open hole section beneath the deepest casing shoe. If the blowout preventers and mud do not restrict the upward pressures of a kick, a blowout results, potentially shooting tubing, oil and gas up the wellbore, damaging the rig, and leaving well integrity in question. Since BOPs are important for the safety of the crew and natural environment, as well as the drilling rig and the wellbore itself, authorities recommend, and regulations require, that BOPs be regularly inspected, tested and refurbished. Tests vary from daily test of functions on critical wells to monthly or less frequent testing on wells with low likelihood of control problems.[2] Exploitable reservoirs of oil and gas are increasingly rare and remote, leading to increased subsea deepwater well exploration and requiring BOPs to remain submerged for as long as a year in extreme conditions. As a result, BOP assemblies have grown larger and heavier (e.g. a single ram-type BOP unit can weigh in excess of 30,000 pounds), while the space allotted for BOP stacks on existing offshore rigs has not grown commensurately. Thus a key focus in the technological development of BOPs over the last two decades has been limiting their footprint and weight while simultaneously increasing safe operating capacity.

[edit] Types BOPs come in two basic types, ram and annular. Both are often used together in drilling rig BOP stacks, typically with at least one annular BOP capping a stack of several ram BOPs. [edit] Ram blowout preventer

A Patent Drawing of the Original Ram-type Blowout Preventer, by Cameron Iron Works (1922).

Blowout Preventer diagram showing different types of rams. (a) blind ram (b) pipe ram and (c) shear ram.

The ram BOP was invented by James Smither Abercrombie and Harry S. Cameron in 1922, and was brought to market in 1924 by Cameron Iron Works.[3] A ram-type BOP is similar in operation to a gate valve, but uses a pair of opposing steel plungers, rams. The rams extend toward the center of the wellbore to restrict flow or retract open in order to permit flow. The inner and top faces of the rams are fitted with packers (elastomeric seals) that press against each other, against the wellbore, and around tubing running through the wellbore. Outlets at the sides of the BOP housing (body) are used for connection to choke and kill lines or valves. Rams, or ram blocks, are of four common types: pipe, blind, shear, and blind shear. Pipe rams close around a drill pipe, restricting flow in the annulus (ring-shaped space between concentric objects) between the outside of the drill pipe and the wellbore, but do not obstruct flow within the drill pipe. Variable-bore pipe rams can accommodate tubing in a wider range of outside diameters than standard pipe rams, but typically with some loss of pressure capacity and longevity. Blind rams (also known as sealing rams), which have no openings for tubing, can close off the well when the well does not contain a drill string or other tubing, and seal it.

Patent Drawing of a Varco Shaffer Ram BOP Stack. A shear ram BOP has cut the drillstring and a pipe ram has hung it off.

Schematic view of closing shear blades

Shear rams cut through the drill string or casing with hardened steel shears. Blind shear rams (also known as shear seal rams, or sealing shear rams) are intended to seal a wellbore, even when the bore is occupied by a drill string, by cutting through the drill string as the rams close off the well. The upper portion of the severed drill string is freed from the ram, while the lower portion may be crimped and the “fish tail” captured to hang the drill string off the BOP.

In addition to the standard ram functions, variable-bore pipe rams are frequently used as test rams in a modified blowout preventer device known as a stack test valve. Stack test valves are positioned at the bottom of a BOP stack and resist downward pressure (unlike BOPs, which resist upward pressures). By closing the test ram and a BOP ram about the drillstring and pressurizing the annulus, the BOP is pressure-tested for proper function. The original ram BOPs of the 1920s were simple and rugged manual devices with minimal parts. The BOP housing (body) had a vertical well bore and horizontal ram cavity (ram guide chamber). Opposing rams (plungers) in the ram cavity translated horizontally, actuated by threaded ram shafts (piston rods) in the manner of a screw jack. Torque from turning the ram shafts by wrench or hand wheel was converted to linear motion and the rams, coupled to the inner ends of the ram shafts, opened and closed the well bore. Such screw jack type operation provided enough mechanical advantage for rams to overcome downhole pressures and seal the wellbore annulus. Hydraulic rams BOPs were in use by the 1940s. Hydraulically actuated blowout preventers had many potential advantages. The pressure could be equalized in the opposing hydraulic cylinders causing the rams to operate in unison. Relatively rapid actuation and remote control were facilitated, and hydraulic rams were well-suited to high pressure wells. Because BOPs are fail-safe devices, efforts to minimize the complexity of the devices are still employed to ensure ram BOP reliability and longevity. As a result, despite the everincreasing demands placed on them, state of the art ram BOPs are conceptually the same as the first effective models, and resemble those units in many ways.

Hydril Company's Compact BOP Ram Actuator Assembly Patent Drawing

Ram BOPs for use in deepwater applications universally employ hydraulic actuation. Threaded shafts are often still incorporated into hydraulic ram BOPs as lock rods that hold the ram in position after hydraulic actuation. By using a mechanical ram locking mechanism, constant hydraulic pressure need not be maintained. Lock rods may be coupled to ram shafts or not, depending on manufacturer. Other types of ram locks, such as wedge locks, are also used.

Typical ram actuator assemblies (operator systems) are secured to the BOP housing by removable bonnets. Unbolting the bonnets from the housing allows BOP maintenance and facilitates the substitution of rams. In that way, for example, a pipe ram BOP can be converted to a blind shear ram BOP. Shear-type ram BOPs require the greatest closing force in order to cut through tubing occupying the wellbore. Boosters (auxiliary hydraulic actuators) are frequently mounted to the outer ends of a BOP’s hydraulic actuators to provide additional shearing force for shear rams. Ram BOPs are typically designed so that well pressure will help maintain the rams in their closed, sealing position. That is achieved by allowing fluid to pass through a channel in the ram and exert pressure at the ram’s rear and toward the center of the wellbore. Providing a channel in the ram also limits the thrust required to overcome well bore pressure. Single ram and double ram BOPs are commonly available. The names refer to the quantity of ram cavities (equivalent to the effective quantity of valves) contained in the unit. A double ram BOP is more compact and lighter than a stack of two single ram BOPs while providing the same functionality, and is thus desirable in many applications. Triple ram BOPs are also manufactured, but not as common. Technological development of ram BOPs has been directed towards deeper and higher pressure wells, greater reliability, reduced maintenance, facilitated replacement of components, facilitated ROV intervention, reduced hydraulic fluid consumption, and improved connectors, packers, seals, locks and rams. In addition, limiting BOP weight and footprint are significant concerns to account for the limitations of existing rigs. The highest-capacity large-bore ram blowout preventer on the market, as of July 2010, Cameron’s EVO 20K BOP, has a hold-pressure rating of 20,000 psi, ram force in excess of 1,000,000 pounds, and a well bore diameter of 18.75 inches.

[edit] Annular blowout preventer

Patent Drawing of Original Shaffer Spherical-type Blowout Preventer (1972)

Diagram of an Annular blowout preventer in open and fully closed configurations. The flexible annulus (donut) in blue is forced into the drillpipe cavity by the hydraulic pistons.

The annular blowout preventer was invented by Granville Sloan Knox in 1946; a U.S. patent for it was awarded in 1952.[4] Often around the rig it is called the "Hydril", after the name of one of the manufacturers of such devices. An annular-type blowout preventer can close around the drill string, casing or a noncylindrical object, such as the kelly. Drill pipe including the larger-diameter tool joints (threaded connectors) can be "stripped" (i.e., moved vertically while pressure is contained below) through an annular preventer by careful control of the hydraulic closing pressure. Annular blowout preventers are also effective at maintaining a seal around the drillpipe

even as it rotates during drilling. Regulations typically require that an annular preventer be able to completely close a wellbore, but annular preventers are generally not as effective as ram preventers in maintaining a seal on an open hole. Annular BOPs are typically located at the top of a BOP stack, with one or two annular preventers positioned above a series of several ram preventers. An annular blowout preventer uses the principle of a wedge to shut in the wellbore. It has a donut-like rubber seal, known as an elastomeric packing unit, reinforced with steel ribs. The packing unit is situated in the BOP housing between the head and hydraulic piston. When the piston is actuated, its upward thrust forces the packing unit to constrict, like a sphincter, sealing the annulus or openhole. Annular preventers have only two moving parts, piston and packing unit, making them simple and easy to maintain relative to ram preventers. The original type of annular blowout preventer uses a “wedge-faced” (conical-faced) piston. As the piston rises, vertical movement of the packing unit is restricted by the head and the sloped face of the piston squeezes the packing unit inward, toward the center of the wellbore. In 1972, Ado N. Vujasinovic was awarded a patent for a variation on the annular preventer known as a spherical blowout preventer, so-named because of its sphericalfaced head.[5] As the piston rises the packing unit is thust upward against the curved head, which constricts the packing unit inward. Both types of annular preventer are in common use.

[edit] Control methods When rigs are drilled on land or in very shallow water where the wellhead is above the water line, BOPs are activated by hydraulic pressure from a remote accumulator. Several control stations will be mounted around the rig. They also can be closed manually by turning large wheel-like handles. In deeper offshore operations with the wellhead just above the mudline on the sea floor, there are four primary ways by which a BOP can be controlled. The possible means are:[citation needed]    

Electrical Control Signal: sent from the surface through a control cable; Acoustical Control Signal: sent from the surface based on a modulated/encoded pulse of sound transmitted by an underwater transducer; ROV Intervention: remotely operated vehicles (ROVs) mechanically control valves and provide hydraulic pressure to the stack (via “hot stab” panels); Deadman Switch / Auto Shear: fail-safe activation of selected BOPs during an emergency, and if the control, power and hydraulic lines have been severed.

Two control pods are provided on the BOP for redundancy. Electrical signal control of the pods is primary. Acoustical, ROV intervention and dead-man controls are secondary.

An emergency disconnect system, or EDS, disconnects the rig from the well in case of an emergency. The EDS is also intended to automatically trigger the deadman switch, which closes the BOP, kill and choke valves. The EDS may be a subsystem of the BOP stack’s control pods or separate.[citation needed] Pumps on the rig normally deliver pressure to the blowout preventer stack through hydraulic lines. Hydraulic accumulators are on the BOP stack enable closure of blowout preventers even if the BOP stack is disconnected from the rig. It is also possible to trigger the closing of BOPs automatically based on too high pressure or excessive flow.[citation needed]

Individual wells along the U.S. coastline may also be required to have BOPs with backup acoustic control.[citation needed] General requirements of other nations, including Brazil, were drawn to require this method.[citation needed] BOPs featuring this method may cost as much as US$500,000 more than those that omit the feature.[citation needed]

[edit] Deepwater Horizon blowout Main article: Deepwater Horizon oil spill

A robotic arm of a Remotely Operated Vehicle (ROV) attempts to activate the "Deepwater Horizon" Blowout Preventer (BOP), Thursday, April 22, 2010.

During the Deepwater Horizon drilling rig explosion incident on April 20, 2010, the blowout preventer should have been activated automatically, cutting the drillstring and sealing the well to preclude a blowout and subsequent oil spill in the Gulf of Mexico, but it failed to fully engage. Underwater robots (ROVs) later were used to manually trigger the blind shear ram preventer, to no avail. As of May 2010 it was unknown why the blowout preventer failed.[6] Chief surveyor John David Forsyth of the American Bureau of Shipping testified in hearings before the Joint Investigation[7] of the Minerals Management Service and the U.S. Coast Guard investigating the causes of the explosion that his agency last inspected the rig's blowout preventer in 2005.[8] BP representatives suggested that the preventer could have suffered

a hydraulic leak.[9] Gamma-ray imaging of the preventer conducted on May 12 and May 13, 2010 showed that the preventer's internal valves were partially closed and were restricting the flow of oil. Whether the valves closed automatically during the explosion or were shut manually by remotely operated vehicle work is unknown.[9] A statement released by Congressman Bart Stupak revealed that, among other issues, the emergency disconnect system (EDS) did not function as intended and may have malfunctioned due to the explosion on the Deepwater Horizon.[10] The permit for the Macondo Prospect by the Minerals Management Service in 2009 did not require redundant acoustic control means.[11] Inasmuch as the BOPs could not be closed successfully by underwater manipulation (ROV Intervention), pending results of a complete investigation, it is uncertain whether this omission was a factor in the blowout. Documents discussed during congressional hearings June 17, 2010, suggested that a battery in the device's control pod was flat and that the rig's owner, Transocean, may have "modified" Cameron's equipment for the Macondo site (including incorrectly routing hydraulic pressure to a stack test valve instead of a pipe ram BOP) which increased the risk of BOP failure, in spite of warnings from their contractor to that effect. Another hypothesis is that a junction in the drilling pipe may have been positioned in the BOP stack in such way that its shear rams had an insurmountable thickness of material to cut through.[12] It was later discovered that a second piece of tubing got into the BOP stack at some point during the Macondo incident, potentially explaining the failure of the BOP shearing mechanism.[13] As of July 2010 it is unknown whether the tubing might be casing that shot up through the well or perhaps broken drill pipe that dropped into the well. On July 10, 2010 BP began operations to install a sealing cap, also known as a capping stack, atop the failed blowout preventer stack. Based on BP's video feeds of the operation the sealing cap assembly, called Top Hat 10, includes a stack of three blind shear ram BOPs manufactured by Hydril (a GE Oil & Gas company), one of Cameron's chief competitors. By July 15 the 3 ram capping stack had sealed the Macondo well, if only temporarily, for the first time in 87 days. The U.S. government wants the failed blowout preventer to be replaced in case of any pressure that occurs when the relief well intersects with the well.[14] On September 3 at 1:20 p.m. CDT the 300 ton failed blowout preventer was removed from the well and began being slowly lifted to the surface.[14] Later that day a replacement blowout preventer was placed on the well.[15] On September 4 at 6:54 p.m. CDT the failed blowout preventer reached the surface of the water and at 9:16 p.m. CDT it was placed in a special container on board the vessel Helix Q4000.[15] The failed blowout preventer was taken to a NASA facility in Louisiana for examination[15] by Det Norske Veritas (DNV). On 20 March 2011, DNV presented their report to the US Department of Energy[16]. Their primary conclusion was that the rams failed to shear through the oil pipe and seal it

because it has buckled out of the line of action of the rams. They did not suggest any failure of actuation as would be caused by faulty batteries. A drill string on a drilling rig is a column, or string, of drill pipe that transmits drilling fluid (via the mud pumps) and torque (via the kelly drive or top drive) to the drill bit. The term is loosely applied as the assembled collection of the drill pipe, drill collars, tools and drill bit. The drill string is hollow so that drilling fluid can be pumped down through it and circulated back up the annulus (the void between the drill string and the casing/open hole).

Drill string components The drill string is typically made up of three sections:   

Bottom hole assembly (BHA) Transition pipe, which is often heavyweight drill pipe (HWDP) Drill pipe

[edit] Bottom hole assembly (BHA)

The BHA is made up of: a drill bit, which is used to break up the rock formations; drill collars, which are heavy, thick-walled tubes used to apply weight to the drill bit; and drilling stabilizers, which keep the assembly centered in the hole. The BHA may also contain other components such as a downhole motor and Rotary steerable system, measurement while drilling (MWD), and logging while drilling (LWD) tools. The components are joined together using rugged threaded connections. Short "subs" are used to connect items with dissimilar threads. [edit] Transition pipe

Heavyweight drill pipe (HWDP) may be used to make the transition between the drill collars and drill pipe. The function of the HWDP is to provide a flexible transition between the drill collars and the drill pipe. This helps to reduce the number of fatigue failures seen directly above the BHA. A secondary use of HWDP is to add additional weight to the drill bit. [edit] Drill pipe

Drill pipe makes up the majority of the drill string back up to the surface. Each segment has a larger-diameter portion on each end containing a male ("pin") or female ("box") thread.

[edit] Running a drill string

Most components in a drill string are manufactured in 31 foot lengths (range 2) although they can also be manufactured in 46 foot lengths (range 3). Each 31 foot component is referred to as a joint. Typically 2, 3 or 4 joints are joined together to make a stand. Modern onshore rigs are capable of handling ~90 ft stands (often referred to as a triple). Pulling the drill string out of or running the drill string into the hole is referred to as tripping. Drill pipe, HWDP and collars are typically stood back in stands in the derrick if they are to be run back into the hole again after, say, changing the bit. The disconnect point ("break") is varied each subsequent round trip so that after three trips every connection has been broken apart and later made up again with fresh pipe dope applied.

[edit] Stuck drill string A stuck drill string can be caused by many situations.    

Packing-off due to cuttings settling back into the wellbore when circulation is stopped. Differentially when the formation pressure is too low, the wellbore pressure is too high or both, essentially pushing the pipe onto the wall of the wellbore. Keyhole sticking occurs mechanically as a result of pulling up into doglegs when tripping. Adhesion due to not moving it for a significant amount of time.

Once the tubular member is stuck, there are many techniques used to extract the pipe. The tools and expertise are normally supplied by an oilfield service company. Two popular tools and techniques are the oilfield jar and the surface resonant vibrator. Below is a history of these tools along with how they operate. [edit] History of Jars

The mechanical success of cable tool drilling has greatly depended on a device called jars, invented by a spring pole driller, William Morris, in the salt well days of the 1830s. Little is known about Morris except for his invention and that he listed Kanawha County (now in West Virginia) as his address. Morris received US 2243 for this unique tool in 1841 for artesian well drilling. Later, using jars, the cable tool system was able to efficiently meet the demands of drilling wells for oil. The jars were improved over time, especially at the hands of the oil drillers, and reached the most useful and workable design by the 1870s, due to another US 78958 received in 1868 by Edward Guillod of Titusville, Pennsylvania, which addressed the use of steel on the jars' surfaces that were subject to the greatest wear. Many years later, in the 1930s, very strong steel alloy jars were made. A set of jars consisted of two interlocking links which could telescope. In 1880 they had a play of about 13 inches such that the upper link could be lifted 13 inches before the lower link was engaged. This engagement occurred when the cross-heads came together.Today, there are two primary types, hydraulic and mechanical jars. While their respective designs are quite different, their operation is similar. Energy is stored in the

drillstring and suddenly released by the jar when it fires. Jars can be designed to strike up, down, or both. In the case of jarring up above a stuck bottomhole assembly, the driller slowly pulls up on the drillstring but the BHA does not move. Since the top of the drillstring is moving up, this means that the drillstring itself is stretching and storing energy. When the jars reach their firing point, they suddenly allow one section of the jar to move axially relative to a second, being pulled up rapidly in much the same way that one end of a stretched spring moves when released. After a few inches of movement, this moving section slams into a steel shoulder, imparting an impact load. In addition to the mechanical and hydraulic versions, jars are classified as drilling jars or fishing jars. The operation of the two types is similar, and both deliver approximately the same impact blow, but the drilling jar is built such that it can better withstand the rotary and vibrational loading associated with drilling. Jars are designed to be reset by simple string manipulation and are capable of repeated operation or firing before being recovered from the well. Jarring effectiveness is determined by how rapidly you can impact weight into the jars. When jarring without a compounder or accelerator you rely only on pipe stretch to lift the drill collars upwards after the jar releases to create the upwards impact in the jar. This accelerated upward movement will often be reduced by the friction of the working string along the sides of the well bore, reducing the speed of upwards movement of the drill collars which impact into the jar. At shallow depths jar impact is not achieved because of lack of pipe stretch in the working string. When pipe stretch alone cannot provide enough energy to free a fish, compounders or accelerators are used. Compounders or accelerators are energized when you over pull on the working string and compress a compressible fluid through a few feet of stroke distance and at the same time activate the fishing jar. When the fishing jar releases the stored energy in the compounder/acclerator lifts the drill collars upwards at a high rate of speed creating a high impact in the jar. [edit] System Dynamics of Jars

Jars rely on the principle of stretching a pipe to build elastic potential energy such that when the jar trips it relies on the masses of the drill pipe and collars to gain velocity and subsequently strike the anvil section of jar. This impact results in a force, or blow, which is converted into energy. [edit] History of Surface Resonant Vibrators

The concept of using vibration to free stuck objects from a wellbore originated in the 1940s, and probably stemmed from the 1930s use of vibration to drive piling in the Soviet Union. The early use of vibration for driving and extracting piles was confined to low frequency operation; that is, frequencies less than the fundamental resonant frequency of the system and consequently, although effective, the process was only an improvement on conventional hammer equipment. Early patents and teaching attempted to explain the process and mechanism involved, but lacked a certain degree of sophistication. In 1961, A. G. Bodine obtained US 2972380[1] that was to become the

"mother patent" for oil field tubular extraction using sonic techniques. Mr. Bodine introduced the concept of resonant vibration that effectively eliminated the reactance portion of mechanical impedance, thus leading to the means of efficient sonic power transmission. Subsequently, Mr. Bodine obtained additional patents directed to more focused applications of the technology. The first published work on this technique was outlined in a 1987 Society of Petroleum Engineers (SPE) paper presented at the International Association of Drilling Contractors in Dallas, Texas [2] detailing the nature of the work and the operational results that were achieved. The cited work involving liner, tubing, and drill pipe extraction and was very successful. Reference Two[3] presented at the Society of Petroleum Engineers Annual Technical Conference and Exhibition in Aneheim, Ca, November, 2007 explains the resonant vibration theory in more detail as well as its use in extracting long lengths of mud stuck tubulars. The Figure 1 below shows the components of a typical surface resonant vibrator.

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Oilfield Surface Resonant Vibrator [edit] System Dynamics of Surface Resonant Vibrators

Surface Resonant Vibrators rely on the principle of counter rotating eccentric weights to impart a sinusoidal harmonic motion from the surface into the work string at the surface. Reference Three (above) provides a full explanation of this technology. The frequency of rotation, and hence vibration of the pipe string, is tuned to the resonant frequency of the system. The system is defined as the surface resonant vibrator, pipe string, fish and retaining media. The resultant forces imparted to the fish is based on the following logic:  





The delivery forces from the surface are a result of the static overpull force from the rig, plus the dynamic force component of the rotating eccentric weights Depending on the static overpull force component, the resultant force at the fish can be either tension or compression due to the sinusoidal force wave component from the oscillator Initially during startup of a vibrator, some force is necessary to lift and lower the entire load mass of the system. When the vibrator tunes to the resonant frequency of the system, the reactive load impedance cancels out to zero by virtue of the inductance reactance (mass of the system) equalling the compliance or stiffness reactance (elasticity of the tubular). The remaining impedance of the system, known as the resistive load impedance, is what is retaining the stuck pipe. During resonant vibration, a longitudinal sine wave travels down the pipe to the fish with an attendant pipe mass that is equal to a quarter wavelength of the resonant vibrating frequency.

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A phenomenon known as fluidization of soil grains takes place during resonant vibration whereby the granular material constraining the stuck pipe is transformed into a fluidic state that offers little resistance to movement of bodies through the media. In effect, it takes on the characteristics and properties of a liquid. During pipe vibration, Dilation and Contraction of the pipe body, known as Poisson's ratio, takes place such that that when the stuck pipe is subjected to axial strain due to stretching, its diameter will contract. Similarly, when the length of pipe is compressed, its diameter will expand. Since a length of pipe undergoing vibration experiences alternate tensile and compressive forces as waves along its longitudinal axis (and therefore longitudinal strains), its diameter will expand and contract in unison with the applied tensile and compressive waves. This means that for alternate moments during a vibration cycle the pipe may actually be physically free of its bond.

A Drill bit, is a device attached to the end of the drill string that breaks apart, cuts or crushes the rock formations when drilling a wellbore, such as those drilled to extract water, gas, or oil. The drill bit is hollow and has jets to allow for the expulsion of the drilling fluid, or "mud", at high velocity and high pressure to help clean the bit and, for softer formations, help to break apart the rock. A tricone bit comprises three conical rollers with teeth made of a hard material, such as tungsten carbide. The teeth break rock by crushing as the rollers move around the bottom of the borehole. A polycrystalline diamond compact (PDC) bit has no moving parts and works by scraping the rock surface with disk-shaped teeth made of a slug of synthetic diamond attached to a tungsten carbide cylinder. The tricone bit is an improvement on the original bit patented in 1909 by Howard R. Hughes, Sr. of Houston, Texas,[1] father of the famed billionaire Howard R. Hughes, Jr.. PDC bits, first came into widespread use in 1976, used for gas and oil exploration the North Sea. They are effective at drilling shale formations, especially when used in combination with oil-base drilling muds

In oil drilling, a casing head[1] is a simple metal flange welded or screwed on to the top of the conductor pipe (also known as drive-pipe) or the casing and forms part of the wellhead system for the well. It is the primary interface for the surface pressure control equipment, such as the blowout preventers (for well drilling) or the Christmas tree (for well production). The casing head, when installed, is typically tested to very strict pressure and leak-off parameters to insure viability under blowout conditions, before any surface equipment is installed.

A wellhead is a general term used to describe the component at the surface of an oil or gas well that provides the structural and pressure-containing interface for the drilling and production equipment.

Wellhead gas storage, Etzel Germany The primary purpose of a wellhead is to provide the suspension point and pressure seals for the casing strings that run from the bottom of the hole sections to the surface pressure control equipment. While drilling the oil well, surface pressure control is provided by a blowout preventer (BOP). If the pressure is not contained during drilling operations by the column of drilling fluid, casings, wellhead, and BOP, a well blowout could occur. Once the well has been drilled, it is completed to provide an interface with the reservoir rock and a tubular conduit for the well fluids. The surface pressure control is provided by a Christmas tree, which is installed on top of the wellhead, with isolation valves and choke equipment to control the flow of well fluids during production. Wellheads are typically welded onto the first string of casing, which has been cemented in place during drilling operations, to form an integral structure of the well. In exploration wells that are later abandoned, the wellhead may be recovered for refurbishment and reuse. Offshore, where a wellhead is located on the production platform it is called a surface wellhead, and if located beneath the water then it is referred to as a subsea wellhead or mudline wellhead.

Functions A wellhead serves numerous functions, some of which are: 1. Provide a means of casing suspension. (Casing is the permanently installed pipe used to line the well hole for pressure containment and collapse prevention during the drilling phase).

2. Provides a means of tubing suspension. (Tubing is removable pipe installed in the well through which well fluids pass). 3. Provides a means of pressure sealing and isolation between casing at surface when many casing strings are used. 4. Provides pressure monitoring and pumping access to annuli between the different casing/tubing strings. 5. Provides a means of attaching a blowout preventer during drilling. 6. Provides a means of attaching a Christmas tree for production operations. 7. Provides a reliable means of well access. 8. Provides a means of attaching a well pump,

[edit] Components The primary components of a wellhead system are:          

casing head casing spools casing hangers packoffs (isolation) seals bowl protectors / wear bushings test plugs mudline suspension systems tubing heads tubing hangers tubing head adapters

A flow line, used on a drilling rig, is a large diameter pipe (typically a section of casing) that is connected to the bell nipple (under the drill floor) and extends to the possum belly (on the mud tanks) and acts as a return line, (for the drilling fluid as it comes out of the hole), to the mud tanks.

Flow Line Components

The flow line will typically have equipment attached to it, such as a flow show, possum belly and the sample box [edit] Flow Show

The flow show shows whether drilling fluid is flowing down the flow line or not and any changes in that flow. High-pressure jets are typically attached along its length to dislodge any obstructions (such as drill cuttings collecting in one spot) that may occur. [edit] Possum Belly

The possum belly is used to slow the flow of returning drilling fluid before it hits the shale shakers. This enables the shale shaker to clean the cuttings out of the drilling fluid before it is returned to the pits for circulation. [edit] Sample Box

Another common add on is the sample box. This is a heavy duty rubber hose that is inserted at the end of the flow line and at the other end emplaced into the sample box itself. The sample box is used to capture samples of drill cuttings for geological logging. The box is typically equipped with a raising door that allows the water and cuttings to escape after a sample is collected.

[edit] Stinger Line A stinger line is similar to a flow line, but unlike a flow line is not used to maintain circulation. The stinger line is attached to the blowout preventer to allow for the pressure from a blowout to be released. The stinger line usually will run parallel to the flow line.