Applied Drilling Engineering - Ebook download as PDF File .pdf), Text File .txt) or read book online. This book will be accessible for 6 months from the date of download. An industry and academic standard, Applied Drilling Engineering presents engineering. A Drilling Engineering text book for mechanical, petroleum or professionals operating within the oil and gas, specifically the exploration.

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Applied Drilling Engineering Adam T. Bourgoyne Jr. Professor of Petroleum Engineering, Louisiana State.. g-z.._. ýe,..r, gš'g .. Download. Applied Drilling Engineering Adam T. Bourgoyne Jr. Professor of Petroleum a tooth wear parameter Tj using () Eq. can be expressed by pdf =Ji t h (t. This book provides a very detailed reference source for most aspects of drilling engineering. It covers everything from bit design to hydraulics to derived burst.

Thus, it is important to keep drilling line tension well below the nominal breaking strength and to keep the drilling line in good condition. The nominal breaking strength new for one type of wire rope commonly used fOT drilling line is shown in Table 1.

The correct method for measuring wire rope diameter is illustrated in Fig.. Drilling line does not tend to wear uniformly over its length.

The most severe wear occurs at the pickup points in the sheaves and at the lap points on the drum of the drawworks. The pickup points are the points in the drilling line that are on the top of the crown block sheaves or the bottom of the traveling block sheaves when the weight of the drillstring is lifted from its supports in the rotary table during tripping operations. The rapid acceleration of the heavy drillstring causes the. The lap points are the points in the drilling line where a new layer or lap of wire begins on the drum of the drawworks.

Drilling line Is maintained in good condition by following a scheduled slip-and-cut program. Slipping the drilling line involves loosening the dead line anchor and placing a few feet of new line in service from the storage reel. Cutting the drilling line involves removing the line from the drum of the drawworks and cutting off a section of line from the end. Slipping the line changes the pickup points, and cutting the line changes the lap points.

The line is sometimes slipped several times before it is cut. Care must be taken not to slip the line a multiple of the distance between pickup points. Otherwise, points of maximum wear are just shifted from one sheave to the next.

Likewise, care must be taken when cutting the line not to cut a section equal in length to a multiple of the distance between lap points. APII8 has adopted a slip-and-cut program for drilling lines.

The parameter adopted to evaluate the amount of line service is the ton-mile. A drilling line is said to have rendered one ton-mile of service when the, traveling block has moved J U. Note that for simplicity this parameter is independent of the number of lines strung. Ton-mile records must be maintained in order to employ a satisfactory slip-and-cut program.

Devices that automatically accumulate the ton-miles of service are available. The number of ton-miles between cutoffs will vary with drilling conditions and drilling line diameter and must be determined through field experience. In hard rock drilling, vibrational problems may cause more rapid line wear than when the rock types are relatively soft.

Typical ton-miles between cutoff usually range from about for l-io. Example l. A rig must hoist a load of , lbf. The drawworks can provide an input power to the block and tackle system as high as hp, Eight lines are strung between the crown block and traveling block.

Calculate I the static tension in the fast line when upward motion is impending, 2 the maximum hook horsepower available, 3 the maximum hoisting speed, 4 the actual derrick load.

Assume that the rig floor is arranged as shown in Fig. The tension in the fast line is given by Eq. The drawworks Fig. The principal parts of the drawworks are J the drum, 2 the brakes. The drum transmits the torque required for hoisting or braking. It also stores the drilling line required to move the traveling block the length of the derrick.

The brakes must have the capacity to stop and sustain the great weights imposed when lowering a string of pipe into the hole, Auxiliary brakes are used to help dissipate the large amount of heat generated during braking. Two types of auxiliary brakes commonly used are 1 the hydrodynamic type and 2 the electromagnetic type. For the hydrodynamic type, braking is provided by water being impelled in a direction opposite to the rotation of the drum.

In the electromagnetic type, electrical braking is provided by two opposing magnetic fields. The magnitude of the magnetic fields is dependent on the speed of rotation and the amount of external excitation current supplied.

In hath types, the heat developed must be dissipated by a liquid cooling system. The drawworks transmission provides a means for easily changing the direction and speed of [he traveling block. Power also must be transmitted to catheads attached to both ends of the drawworks. Friction catheads shown in Fig. The number of turns of rope on the drum and the tension provided by the operator controls the force of the pull.

A second type of cathead generally located between the drawworks housing and the friction cathead can be used to provide the torque needed to screw or unscrew sections of pipe.

Hydraulically or airpowered spinning and torquing devices also are available as alternatives to the conventional tongs. One type of power tong is shown in Fig. A major function of the fluid-circulating system is to remove the rock cuttings from the hole as drilling progresses.

A schematic diagram illustrating a typical rig circulating system is shown in Fig. The drilling fluid is most commonly a suspension of clay and other materials in water and is called drilling mud. The principal components of the rig circulating system include 1 mud pumps, 2 mud pits, 3 mudmixing equipment, and 4 contaminant-removal equipment. With the exception of several experimental types, mud pumps always have used reciprocating positive-displacement pistons.

Both two-cylinder duplex and three-cylinder triplex pumps are common. The duplex pumps generally are double-acting pumps that pump on both forward and backward piston strokes.

The triplex pumps generally are single-acting pumps that pump only on forward piston strokes. Triplex pumps are lighter and more compact than duplex pumps, their output pressure pulsations are not as great, and they are cheaper to operate. For these reasons, the majority of new pumps being placed into operation are of the triplex design. The advantages of the reciprocating positivedisplacement pump are the 1 ability to move highsolids-content fluids laden with abrasives.

Example duplex and triplex mudpumps are shown in Fig. The overall efficiency of a mud-circulating pump is the product of the mechanical efficiency and the vol umetric efficiency. Volumetric efficiency of a pump whose.

Most manufacturers' tables rate pumps using a mechanical efficiency, En: For the large hole sizes used on the shallow portion of most wells, both pumps can be operated in parallel to deliver the large flow rates required. On the deeper portions of the well, only one pump is needed, and the second pump serves as a standby for use when pump maintenanoeis required.

A schematic diagram showing the valve arrangement and operation of a double-acting pump is shown in Fig. The theoretical displacement from a double-acting pump is a function of the piston rod diameter d. On the forward stroke of each piston, the volume displaced is given by. Thus, the total volume displaced per complete pump cycle by a pump having two cylinders is given by. TIle pump displacement per cycle, Fp' is commonly called the pump factor. For the single-acting triplex pump, the volume displaced by each piston during one complete pump cycle is given by.

In common field usage, the terms cycle and stroke often are used interchangeably to refer to one complete pump revolution. Pumps are rated for 1 hydraulic power, 2 maximum pressure. If the inlet pressure of the pump is essentially atmospheric pressure, the increase in fluid pressure moving through the pump is approximately equal to the discharge pressure.

The hydraulic power output of the pump is equal to the discharge pressure times the flow rate. For a given hydraulic power level, the maximum discharge pressure and flow rate can be varied by changing the stroke rate and liner size. A smaller liner will allow the operator to obtain a higher pressure, but at a lower rate. Due to equipment maintenance problems, pressures above about 3, psig seldom are used.

[Pdf] - SPE Textbook - Applied Drilling Engineering

The surge chamber see Fig. The surge chamber greatly dampens the pressure surges developed by the positive-displacement pump. The discharge line also contains a pressure relief valve to prevent line rupture in the event the pump is started against a closed valve.

The standpipe and rotary hose provide a flexible connection that permits vertical movement of the drillstring. The swivel contains roller bearings to support the rotating load of the drill string and a rotating pressure seal that allows fluid.

The kelly, which is a pipe rectangular or hexagonal in cross section, allows the drillstring to be rotated. It normally has a. Compute the pump factor in units of barrels per stroke fOT a duplex. Recall that there are in.

Thus, converting to the desired field units yields. Mud pits are required for holding an excess volume of drilling mud at the surface. This surface volume allows time for settling of the finer rock cuttings and for the release of entrained gas bubbles not mechanically separated. Also, in the event some drilling fluid is Iost to underground formations, this fluid loss is replaced by mud from the surface pits.

The settling and suction pits sometimes are dug in the earth with a buUdozer but more commonly are made of steel. A large earthen reserve pit is provided for contaminated or discarded drilling fluid and fOT the rock cuttings.

This pit also is used to contain any formation fluids produced during drilling and welltesting operations. Dry mud additives often are stored in sacks, which are added manually to the suction pit using a mud-. However, on many modern rigs bulk storage is used and mud mixing is largely automated.

Liquid mud additives can be added to the suction pit lrorn a chemical tank. Mud jets or motor-driven agitators often are mounted on the pits for auxiliary mixing. The contaminant-removing equipment includes mechanical devices for removing solids and gases from the mud. The coarse rock cuttings and cavings are removed by the shale shaker.

The shale shaker is composed of one or more vibrating screens over which the mud passes as it returns from the hole. A shale shaker in operation is shown in Fig. Additional separation of solids and gases from the mud occurs in the settling pit. When the amount of finely ground solids in the mud becomes too great, they can be removed by hydrocyclones and decanting centrifuges. A hydrocyclone Fig. The heavier solids in the mud are thrown to the housing of the hydrocyclone and fall through the apex at the bottom.

Most of the liquid and lighter particles exit through the vortex finder at the top. The decanting centrifuge Fig. Rotation of the cone creates a centrifugal force that throws the heavier particles to the outer housing. The screw conveyor moves the separated particles to the discharge.

When [he amount of entrained formation gas leaving the settling pit becomes too great, it can be separated using a degasser.

A vacuum chamber degasser is shown in Fig. A vacuum pump mounted on lap of the chamber removes the gas from the chamber. The mud flows across inclined flat surface' in the chamber in thin layers, which allow the gas bubbles that have been enlarged by the reduced pressure 1. Mud is drawn through the chamber at a reduced pressure of about 5 psia by a mud jet located in the discharge line. A gaseous drilling fluid can be used when the formations encountered by the bit have a high strength and an extremely low permeability.

The use of gas as a drilling fluid when drilling most sedimentary rocks results in a much higher penetration rate than is obtained using drilling mud. An order-of-magnitude difference in penetration rates may be obtained with gas as compared with drilling mud.

This problem sometimes can be solved by injecting a mixture of surfactant and water into the gas to make a foam-type drilling fluid. Drilling rates with foam are generally less than with air but greater than with water or mud.

As the rate of water production increases, the cost of maintaining the foam also increases and eventually offsets the drilling rate improvement. A second procedure that often is used when a water-producing zone is encountered is to seal off the. Of -O",. The water-producing zones can be plugged by use of I low-viscosity plastics or 2 silicon tetrafluoride gas. A catalyst injected with the plastic causes the plastic to begin to solidify when it contacts the hot formation.

Silicon tetrafluoride gas reacts with the formation water and precipitates silica in the pore spaces of the rock. Best results are obtained when the water-producing formation is isolated for fluid injection by use of packers.

Also, sufficient injection pressure must be used to exceed he formation pressure. Since this technique requires expending a considerable amount of rig time, the cost of isolating numerous water zones tends to offset the drilling rate improvement. Both air and natural gas have been used as drilling fluids.

An air compressor Of natural gas pressure regulator allows the gas to be injected into the standpipe at the desired pressure.

An example rig circulating system used for air drilling is shown in Fig. Also shown are small pumps used to inject water and surfactant into the discharge line. The gas returning from the annulus then is vented through a blooey line to the reserve pit. If natural gas is used. Even if air is used, care must be taken to prevent 1I1 explosion. Small amounts nf formation hydrocarbons mixed with compressed air C: Jn be quill! The subsurface equipment used for drilling with air is normally the arne as tbe equipment used for drilling with mud.

A cutaway view of an example percussion device is shown in Fig. Gas flow Lhrough the causes a hammer to strike repeatedly on an anvil above the bit. The tool is similar in operation to the percussion hammer used by construction crews to break concrete.

Penetration rates in extremely hard formations have been irnproved significantly by use of this tool,. The rotary system includes all of the equipment used to achieve bit rotation. A schematic diagram illustrating the arrangement and nomenclature of the rotary system is shown in Fig.

The maio parts of the rotary system are the 1 swivel, 2 kelly, 3 rotary drive, 4 rotary table, 5 drillpipe, and 6 drill collars. The swivel Fig. The bail of the swivel is attached to the hook of the traveling block, and the gooseneck of the swivel provides a downward-pointing connection for the rotary hose.

Swivels are rated according to their load capacities. The kelly is the first section of pipe below the swivel. The outside cross section of the kelly is square or hexagonal to permit it to be gripped easily for turning.

Torque is transmitted to the kelly through kelly bushings, which fit inside the master bushing of the rotary table.. The kelly must be kept as straight as possible. Rotation of a crooked kelly causes a. A view of a kelly and kelly bushings in operation is shown in Fig.

The kelly thread is right-handed 00 the lower end and left -handed on the upper end 10 permit normal right-hand rotation of the drillstring.

A kelly saver sub is used between the kelly and the first joint of drillpipe.. This relatively inexpensive short section of pipe prevents wear on the kelly threads and provides a place for mounting a rubber protector to keep the kelly centralized. An example rotary table is shown in fig. The opening in the rotary table that accepts the kelly bushings must be large enough for passage of the largest bit to be run in the hole.

The lower portion of the opening is contoured to accept slips that grip the driIlstring and prevent it from falling into the hole while a. Power for driving [he rotary table usually is provided by an independent rotary drive. However, in some cases, power is taken from the drawworks. A hydraulic transmission between the rotary table and. B12 9. Inaj ylelCl, ano tet1Sne slrefl,g1. This greatly reduces shock loadings and prevents excessive torque if the drillstring becomes stuck.

Excessive torque often will result in a twist-off - i. Power swivels or power subs installed just below a conventional swivel can be used LO replace the kelly, kelly bushings, and rotary table. Drillstring rotation is achieved through a hydraulic motor incorporated in the power swivel or power sub. These devices are available for a wide range of rotary speed and torque combinations.

One type of power sub is shown in Fig. The major portion of the drillstring is composed of drill pipe. The driIJpipe in common use is hot-rolled, pierced, seamless tubing. API has developed specifications for drillpipe. Drillpipe is specified by its outer diameter, weight per foot, steel grade, and range length.

Drillpipe is furnished in he following API. Rilllge 2 drillpipe is used most commonly. Since each joint of pipe has a unique length, the length of each joint must be measured carefully and recorded 10 allow a determination of total well depth during drilling operations. The female portion of the tool joinr is called the box and the male portion is called the pin.

The portion of the.

Tbis thicker portion of the pipe is called the upset. If the extra thickness is achieved by decreasing the internal diameter, the pipe is said to have an internal upset. A rounded-type thread is used now on drill pipe. The U. Standard V thread was used in early drill pipe designs.. A tungsten carbide hard facing sometimes is manufactured on the outer surface of the tool joint box to reduce the abrasive wear of the joint by the borehole wall when the drillsrrmg is rotated.

The lower section of the rotary drillstring is composed of drill collars. The dri1J collarsare thickwalled heavy steel tubulars used to apply weight to the bit. The buckling tendency of the relatively thinwalled drillpipe is too great to use il for this purpose.

The smaller clearance between [he borehole and the drill collars helps to keep the hole straight. Stabilizer subs Fig.. In many drilling operations, a knowledge or the volume contained in or displaced by the drillstring is required. The term capacity of len is used to refer to the cross-sectional area of the pipe or annulus expressed in units of contained volume per unit length. In t erms 0 tthe pi pe d iamere r, d.

I he capaci ty of pi pc, A,l' is given by. The term displacement often is used to refer to the cross-sectional area of steel in the pipe expressed in units of volume per unit length, The displacement, As, of a section of pipe is given by.

Displacements calculated using Eq, 1. When a mare exact displacement calculation is needed, tables provided by the tool joint or coupling manufacturer. Table 1. A drillstring is composed of 7, ft of 5-in. ID drill collars when drilling a 9. Assuming that the borehole remains in gauge, compute the number of pump cycles required to circulate mud from the surface to the bit and from.

Using Table 1. The well control system pre. When the bit penetrates a permeable formation that bas a fluid pressure in excess of the hydrostatic pressure exerted by the drilling fluid, formation fluids will. The flow of formation fluids into the well in the presence of drilling fluid is called a kick. The well control system permits 1 detecting the kick, 2 closing the well at the surface, 3 circulating the well under pressure to remove the formation fluids and increase the mud density, 4 moving the drillstring under pressure, and 5 diverting flow away from rig.

This is perhaps the worst disaster that can occur during drilling operations. Blowouts can cause loss of life. Thus, the well control system is one of the more important systems on the rig. Kick detection during drilling operations usually is achieved by use of a pit-volume indicator or a flow indicator. The operation of these devices is illustrated in Fig. Both devices can detect an increase in the flow of mud returning from the well over thai which is being circulated by l he pu mp.

Pit volume indicators usually employ floats in each pit that are connected by means of pneumatic or electrical transducers to a recording device on the rig floor.

The recording device indicates the volume of all active pits. High- and low-level alarms can be preset 0 turn on lights and horns when the pit volume increases or decreases signi ficaruly.

A decrease indicates that drilling fluid is being lost to an underground formation. The more commonly used devices are somewhat similar in operation to the pit level indicators. A paddle-type fluid level sensor is used in the flowline. In addition. A panel on the rig floor displays the flow rate into and out of the weU. If the rates are appreciably different, a gain or loss warning will be given. While making a trip, circulation is stopped and a significant olurne of pipe is removed from the hole.

Thus, to keep the hole full, mud mu I be pumped into the hole to replace the Volume of pipe removed. Kick detection during tripping operations is accomplished through use of a hole fill-up indicator. The purpose of the hole fill-up indicator is 10 measure accurately the mud volume required to fiJI the hole.

If the volume required to fill the hole is less than the volume of pipe removed, a kick mav be in progress. Sma11 trip tanks provide the best means of monitoring bole fill-up volume. Trip tanks usually hold 10 to 15 bbl and have l-bbl gauge markers. Two alternative trip-tank arrangements are illustrated in Fig. With either arrangement, the hole is maintained full as pipe is withdrawn from the well. Periodically, the trip tank is refilled using the mud pump.

The top of a gravity-feed type trip tank must be slightly lower than the bell nipple to prevent mud from being lost to the flowline. The required fill-up volume is determined by periodically checking the fluid level in the trip tank.

When a trip tank is not installed on the rig, hole fill-up volume should be determined by counting pump strokes each time the hole is filled. The level in one of the active pits should Dot be used since the active pits are normally too large to provide sufficient accuracy. The flow of fluid from the well caused by a kick is stopped by use of special pack-off devices called blowout preuenters BOP's.

The BOP must be capable of terminating flow from the well under all drilling conditions. When the drillstring is in the hole. In addition, the BOP stack should allow fluid circulation through the well annulus under pressure. These objectives usually are accomplished by using several ram preventers and one annular preventer. Ram preventers have two packing elements on opposite sides that close by moving toward each other.

Pipe rams have semicircular openings which match the diameter of pipe sizes for which they are designed. Thus the pipe ram must match the size of pipe currently in use. If more than one size of drillpipe is in the hole, additional ram preventers must be used in the BOP stack. Rams designed to close when no pipe is in the hole are called blind rams. Blind rams will flatten drillpipe if inadvertently closed with the drillstring in the hole but will not stop the flow from the well.

Shear rams are blind rams designed to shear the drillstring when closed. This will cause the drillstring to drop in the hole and will stop flow from the well.

Shear rams are closed on pipe only wben all pipe rams and annular preventers have failed. Ram preventers are available for working pressures of 2,, 5,, 10,, and 15, psig,.

Annular preuenters, sometimes called bag-type preventers, stop flow from the well using a ring of synthetic rubber that contracts in the fluid passage. The rubber packing conforms to the shape of the pipe in the hole. Most annular preventers also will. A cross section of one tyne of annular preventer is shown in Fig.

Both the ram and annular BOP's are closed hydraulically. In addition, the ram preventers have a screw-type locking device that can be used to close the preventer if the hydraulic system fails. The annular preventers are designed so that once the rubber element contacts the drillstring, the well pressure helps hold the preventer closed.

Modern hydraulic systems used for closing BOP's are high-pressure fluid accumulators similar to those developed for aircraft fluid control systems. An example vertical accumulator is shown in Fig. The accumulator is capable of supplying sufficient high-pressure fluid to close all of the units in the BOP stack at least once and still have a reserve.

Accumulators with fluid capacities of 40, 80, or gal and maximum operating pressures of J , or 3, psig are common. The accumulator is maintained by a small pump at all times, so the operator has the ability to close the well immediately, independent of normal rig power. For safety. The accumulator fluid usually is a noncorrosive hydraulic oil with a low freezing point.

The hydraulic oil also should have good lubricating characteristics and must be compatible with synthetic rubber part of the well-control system. The accumulator is equipped with a pressureregulating system. The ability to vary the closing pressure on the preventers is important when it is necessary to strip pipe lower pipe with the preventer closed into the hole. If a kick is taken during a trip, it is best to strip back to bottom to allow efficient circulation of the formation fluids from the welL The.

The usual procedure is to reduce the hydraulic closing pressure during stripping operations until there is a slight leakage of well fluid. Stripping is accomplished most easily using the annular preventer. However, when the surface well pressure is too great, stripping must be done using two pipe ram preventers placed far enough apart for external upset tool joints to fit between them. The upper and lower rams must be closed and opened alternately as the tool joints are lowered through.

Space between ram preventers used for stripping operations is provided by a drilling spool. Drilling spools also are used to permit attachment of highpressure flowlines to a given point in the stack. These high-pressure flowlines make it possible to pump into the annulus or release fluid from the annulus with the BOP closed.

A conduit used to pump into the annulus is called a kill line. Conduits used to release fluid from the annulus may include a choke line, a diuerter line, or simply a flowline.

All drilling spools must have a large enough bore to permit the next string of casing to be put in place without removing the BOP stack. The BOP stack is attached to the casing using a casing head. The casing head, sometimes called the braden head. It must provide a pressure seal for subsequent casing strings placed in the well. Also, outlets are provided on the casing head to release any pressure that might accumulate between casing strings. The control panel for operating the BOP stack usually is placed on the derrick floor for easy access by the driller.

The controls should be marked clearly and identifiably with the BOP stack arrangement used. One kind of panel used for this purpose is shown in Fig.

The arrangement of the BOP stack varies considerably. The arrangement used depends on the magnitude of formation pressures in the area and on the type of well control procedures used by the operator. L47 shows typical arrangements for 10, and 15,ODG-psi working pressure service. Note that the arrangement nomenclature uses the letter "A" to denote an annular pre venter, the letter "R" to denote a ram preventer , and the letter "S" to denote a drilling spool.

The arrangement is defined starting at the casing head and proceeding up to the bell nipple. Thus, Arrangement RSRRA denotes the use of a BOP stack with a ram preventer attached to the casing head, a drilling spool above the ram preventer, two ram preventers in eries above the drilling spool.

A rotating head, which seals around the kelly at the top of the BOP stack, must be used when this is done. A rotating-type BOP is shown in Fig. Rotating heads most commonly are employed when air or gas is used as a drilling fluid. They also can be used when formation fluids are entering the well very slowly from low-permeability formations. However, this practice is dangerous unless the formation being drilled has a very low permeability.

This must be established from experience gained in drilling in the local area. For example, this practice i known to be safe in the Ellenberger formation in some areas of west Texas. When the drillstrine is in the hole, the BOP stuc , can be used tn stop only the flow from the annulus Several additional valves can be u ed to prevent flow from inside the drillsiring.

Shown in Fig. Two kelly cocks are required because the lower position might nol be accessible in an emergency if the drillstring is stuck in the hole with the kelly down.

An internal BOP is a valve rhar can be placed in the drillstring if the well begins Ilowing during I ripping, operations. Ball valves similar 10 the valve shown in Fig.

In addition, dan-type check-valve internal BOP's Fig. A high-pressure circulating system used for well control operations is shown in Fig. The kick normally is circulated from the well through an adjustable choke.

The adjustable choke is controlled from a remote panel on the rig floor. An example choke and a control panel are shown in figs.

Su fficient pressure must be held against the well by the choke so that the bottomhole pressure in the well is maintained slightly above the formation pressure. Mechanical stresses on the emergency highpressure flow system can be quite severe when handling a kick. The rapid pressure release of large volumes of fluid through the surface piping frequently is accompanied by extreme vibrational stresses.

Thus, care should be taken to use the strongest available pipe and to anchor all lines. Also, some flexibility in the piping to and from the wellhead is required.

The weight of all valves and fittings should be supported on structural members so that bending stresses are net created in the piping. Because of fluid abrasion, the number of bends should be minimized. The bends required should be sweep-turn bends rather than sharp "L' turns, or have an abrasionresistant target at the point of fluid impingement in the bend. In addition to these recommendations, well operators have developed many other, optional designs. The arrangement selected must be based on the magnitude of the formation pressures in the area and the well control procedures used by the operator.

In this arrangement, a hydraulically controlled valve separates the BOP stack from tbe choke manifold. This valve normally is dosed during drilling operations to prevent drilling mud solids from settling in the choke system.

Two adjustable chokes would allow kick circulation to continue in the event one of the adjustable chokes fails. A mud gas separator permits any produced formation gases to be vented. Also, valves are arranged so that the well fluids can be diverted easily to the reserve pit 10 prevent exces ive pressure from fracturing shallow formations below a short casing suing.

The kill line permits drilling fluid to be pumped down the annulus from the surface. This procedure is used only under special circumstances and is not part of a normal well control operation. The kill line most frequently is needed when subsurface pressure during a kick causes an exposed formation to fracture and to. Safety and efficiency considerat ions require constant monitoring of the well [0 detect drilling problems quickly. An example of a driller's corur ol station is shown in Fig.

In addition to assisting the driller in detecting drilling problems, good historical records of various aspects of the drilling operation also can aid geological, engineering, and supervisory personnel. In some cases, a centralized well-monitoring system housed in a trailer is used Fig. This unit provides detailed information about the formation being drilled and fluids being circulated to the surface in the mud as well as centralizing the record keeping of drilling parameters.

The mud logger carefully inspects rock cuttings taken from the shale shaker at regular intervals and maintains a log describing their appearance. Additional cuttings are labeled according to their depth and are saved for further study by the paleontologist.

The iden-. Gas samples removed from the mud are analyzed by the mud logger using a gas chromatograph. The presence of a hydrocarbon reservoir often can be detected by this type of. Recently, there have been significant advances in subsurface well-monitoring and data-telemetry systems. These systems are especially useful in monitoring hole direction in nonvertical wells. One of the most promising techniques for data telemetry from subsurface instrumentation in the drillstring to the surface involves the use of a mud pulser that sends information to the surface by means of coded pressure pulses in the drilling fluid contained in the drillstring, One system, illustrated in Fig.

Special equipment and procedures are required when drilling from a floating vessel. The special equipment is required to 1 hold the vessel on location over the borehole and 2 compensate for the vertical, lateral, and tilting movements caused by wave action against the vessel. Vessel motion problems are more severe for a drillship than for a semisubmersible, However, drills hips usually are less expensive and can be moved rapidly from one location to the next.

A special derrick design must be used for drillships because of the tilting motion caused by wave action. The derrick of a drillship often is designed to withstand as much as a tilt with a full load of drillpipe standing in the derrick. Also, special pipehandling equipment is necessary to permit tripping operations to be made safely during rough weather. This equipment permits drillpipe to be laid down quickly on a pipe rack in doubles or thrihbles rather than supported in the derrick.

A block guide track also is used to prevent the traveling block from swinging in rough weather. Most floating vessels are held on location by anchors. When the ocean bottom is too hard for conventional anchors, anchor piles are driven or cemented in boreholes in the ocean floor. The vessel is moored facing the direction from which the most severe weather is anticipated.

A drillship has been designed that can be moored from a central turret containing the drilling rig. The ship is rotated about the turret using thrusters mounted in the bow and stern so that it always faces incoming waves. As many as 10 anchors are used in a mooring system. Several common anchor patterns are shown in Fig.

A few vessels have large thrust units capable of holding the drilling vessel on location without ancbors. This placement technique is called dynamic positioning.

The large fuel consumption required for. Dynamic positioning generally is not used in water depths of less than 3, ft. The position of the vessel with reference to the borehole must be monitored at all times. Excessive wear on the subsea equipment will result if the vessel is oat aligned continuously over the hole. Two types of alignment indicators in common use are I toe. The mechanical type system uses a dual-axis inclinometer attached to a cable running from the wellhead to the ship.

It is assumed that sufficient tension is maintained in the line to keep it straight. In addition, an inclinometer may be attached to the flow conduit that conducts the drilling fluid from the ocean floor to the drilling vessel. The acoustic-type position indicator uses beacon transmitters on the ocean floor and hydrophones on the ship.

Doppler sonar may be used also. This system is more accurate than the tautline system in deep water and does not depend on a mechanical link with the vessel. Part of the equipment used to compensate for the horizontal and vertical movement of the vessel during normal drilling operations is shown in Fig.

A marine riser conducts the drilling fluid from the ocean floor to the drilling vessel. A flex joint at the bottom of the marine riser allows lateral movement of the vessel. The vertical movement of the vessel is allowed by a slip joint placed at the top of the marine riser.

The riser is secured to the vessel by a pneumatic tensioning system. The tension requirements can be reduced by adding buoyant sections to the riser system. The vertical movement of the drillstring can be absorbed by a bumper sub between the drillpipe and drill collars. However, many problems result from this arrangement, since vertical vessel movement causes the entire length of drillpipe to reciprocate relative to the casing and hole. Also, it is not possible to vary bit weight when bumper subs are used.

Surface motion-compensating equipment called heave compensators have been developed in order to eliminate this problem. A constant hook load is maintained through use of a pneumatic tensioning device on the traveling block as shown in Fig.

The BOP stack for a floating drilling operation is placed on the ocean floor below the marine riser. This ensures that the well can be closed even in severe weather, such as a hurricane, when it may become necessary to disconnect the marine riser. Also, it. Identical hydraulically operated connectors often are used above and below the BOP stack.

Thi make it possible to add on an additional BOP stack above the existing one in an emergency. The kill line and choke line to the BOP stack are attached to the marine riser. The hydraulic lines required to operate the BOP stack, side valves. They are stored and. A direct hydraulic sy tern can be used for water depths less than about ft. The direct system is similar to the system used on land rigs and bas individual power oil lines 0 each control. An indirect system must be used for deep water.

The indirect system has one source of power oil to the subsea BOP 'lack. Accumulator bottles are mounted on the subsea stack to re an adequate olurne of pressurized hydraulic oil at the seafloor. Flow of the pres urized power oil is distributed [0 I he various function by pilot valves on the ocean floor. Smaller hydraulic lines, which allow much faster response lime, are used to actuate the pilot valves. Electric and acoustic actuators also are available.

A cross section of a control hose bundle for all indirect system is shown in Fig. The large hose in the center i the power-oil host'. Various schemes have been developed for installing subsea equipment. The diagram shown in Fig. A guide base assembly is the initial piece of equipment lowered to the ocean floor. Four cables surrounding the central hole in the guide base extend back to the ship where a constant tension is maintained in the cables.

Equipment then can be lowered into position over the hole using a guide assembly that rides on the guide lines.

Two extra guide lines attached to one side of the guide base allow a television camera to be lowered to the ocean floor when desired. The first sections of hole are drilled without a BOP stack on the ocean floor. When a marine riser is used, a rotating head at the surface allows formation fluids to be diverted away from the rig in an emergency. The conductor casing is lowered into the hole with the subsea wellhead attached to the top. The casing is cemented in place with returns back to the ocean floor.

The wellhead assembly is designed so that all future casing and tubing strings are landed in the wellhead. The BOP stack is lowered and latched into the top of the wellhead. The marine riser then can be deployed and latched into the BOP.

Pneumatic tensioning devices have had wide application in floating drilling operations. They largely have replaced the use of counterweights for cable tensioning. The desired tension is obtained by regulating the air pressure exerted on a piston. Hydraulic fluid on the opposite side of. A block-and-tackle system allows the use of a shorter piston stroke. Pneumatic tensioning devices often are used on the marine riser, the various guide lines to the subsea wellhead.

The main function of the drilling engineer i 0 recommend drilling procedures that will result in the successful completion of the well as safely and inexpensively as possible. The drilling engineer must make recommendations concerning routine rig operations such as drilling f1uid treatment, pump operation, bit selection.

In many cases, the use of a drilling cost equation can be useful in making these recommendations. The usual procedure is to break the drilling costs into l variable drilling costs and 2 fixed operating expenses that are independent 0 f al ternat i ves bei ngevaluated.

The torat time required to drill a given depth, aD, can be expressed as the sum of the total rotating time during the bit run, b the noruotating lime during the bit run, it" and trip time, II' The drilling cost formula is. Reducing the cost of a bit run will not necessarily result in lower well costs if the risk of encountering drilling problems such as stuck pipe, hole deviation, hole washout, etc.

A recommended bit program is being prepared for a new well using bit performance records from nearby wells. Assume that each of the bits was operated at near the minimum cost per foot attainable for that bit.

The cost per foot drilled for each bit type can be computed using Eq. For Bit A, the cost per foot is. The drilling engineer frequently is called upon to predict the cost of a well at a given location. These predictions are required so that sound economic: In some cases, such as the evaluation of a given tract of land available for lease, only an approximate cost estimate is required.

In other cases, such as in a proposal for drilling a new well. Drilling cost depends primarily on well location and well depth. The location of the weU will govern the cost of preparing the wellsite, moving the rig 1.

For example. Included in this daily operating cost are such things as rig rentals. Crew housing, routine maintenance of drilling equipment, drilling fluid treatment, rig supervision ere.

The depth of the well will govern the lithology that must be penetrated and, thus, the time required to complete the well. An excellent source of historical drilling-cost data presented by area and well depth is the annual joint association survey on drilling. Shown in Table 1. Approximate drilling cost estimates can be based on historical data of this type. Drilling costs tend to increase exponentially with depth, Thus. For these data, 0 has a value of about I x dollars and b has a.

L65b is a more conventional cartesian representation of this same correlation. When a more accurate drilling cost prediction is needed, a cost analysis based on a detailed well plan must be made.

The cost of tangible well equipment such as casing and the cost of preparing the surface location usually can be predicted accurately. The cost per day of the drilling operations can be estimated from considerations of rig rental costs, other equipment rentals, transportation costs, rig supervision costs, and others, The time required to drill and complete the well is estimated on the basis or rig-up time, drilling time, trip time, casing.

Major tirneexpenditures always are required for drilling and tripping operations. An estimate of drilling time can be based on historical penetration rate data from the urea of interest. The penetration rate in a given formation. When major unconformities are not present in the subsurface lithology, the penetration rate usually decreases exponentially with depth.

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Under these conditions. Separating variables gives. As experience is gained in an area, more accurate predictions of drilling time can be obtained by plotting depth vs, drilling time from past drilling operations. Plots of this type also are used in evaluating new drilling procedures designed to reduce drilling time to a given depth.

The bit records for a. Also, evaluate the use of Sq.. Solution, The plots obtained using the bit records are shown in Fig, 1. The value of 2. The value of K is equal 0 the value of penetration rate at the surface. From depth VS, penetration rate plot. Substitution of these values of ll2 and Kin Eq. The line represented by this equation also has been plotted on Fig. Note that the line gives good agreement with the bit record data over the entire depth range.

A second major component of the time required to drill a well is the trip time. The time required for tripping operations depends primarily on the depth of the well, the rig being used, and the drilling practices followed. The time required to change a bit and resume drilling operations can be approximated using the relation.

The time required to handle the drill collars is greater than for the rest of the drillstring, but this difference.

The previous analysis shows that the time required per trip increases linearly with depth. In addition, the footage drilled by a single bit ends to decrease with depth, causing the number of trips required to drill a given depth increment also to increase with depth. The footage drilled between trips can be estimated if the approximate bit life is known.

Integrating Eq, 1. The total bit rotating rime. As experience is gained in an area using a particular rig, more accurate predictions of trip time can be obtained by plotting depth vs. Construct an approximate depth vs. Assume an average bit life of Use the values of Q2 and K obtained in Example 1.

Also, the casing program calls for casing set at , 2,, and 7, ft. The planned well depth is 9, ft. The approximate depth of each trip can be obtained from the casing program and Eq. The use of Eq.

The first bit will drill to the first casing depth. Thus, the first trip will occur at ft. Subsequent trips are predicted as shown in Table 1. The results of Table 1. O The time required per round trip is relatively constant over a l,OOO-ft interval. Thus the total trip time required per 1, fl is approximately equal to the time per round trip times the number of trips per 1, ft.

B Compute the trip time requirements for the South China Sea area between 8, and 9, fl. Use the conditions stated in Example 1. Tills compares favorably with the trip lime required between 7, and 8. In addition to predicting the time requirements for drilling and tripping operations, time requirements for other planned drilling operations also must be estimated, These additional drilling operations usually can be broken into the general categories of 0 wellsite preparation, 2 rig movement and rigging UP.

Bourgoyne A.T.Jr. et al. Applied Drilling Engineering

The cost of formation evaluation depends on the number and cost of the logs and tests scheduled, plus rig time required to condition the drilling fluid and run the logs and tests. The lime required to run, cement, and test the casing depends primarily on the number of casing strings, casing depths, diameters, and weights per root.

These COSts also must include the rig time required for running and cementing the casing strings. The cost of completing the well depends on the type of completion used, and this cost estimate is often made by the production engineer.

On many wells, a large fraction of he weU cost may be because of unexpected drilling problems such as mud contamination, Iost circulation, stuck drillstring, broken drillstring, ruptured casing, etc. These unforeseen costs cannot be predicted with any. Requests [or additional funds then must be submitted whenever a significant problem is encountered. Onlyabout of the time required drill and complete this well was spent drilling and tripping LO change bits.

Manufactured in the United States of America. The work is directed by the Society'S Books Committee, one of more than 40 Society-wide standing committees. Members of the Books Committee provide technical evaluation of the book. Below is a listing of those who have been most closely involved in the final prepar ation of this book. Book Editors Jack F. Evers, U. Pye, Union Geothermal Div. Kent Thomas, Phillips Petroleum Co. Fred H. Hoyer, Exxon Production Research Co.

Steve Neuse, Hudson Consultants Inc. Without the unselfish help of so many, this book would not have been possible. Special thanks are due numerous individual s who have served on the SPE Textbook Committee during the past decade for their help and understanding.

In particular. Bourgoyne J r. When I accepted t h e challenge of writing part of this textbook. I had no idea of how much of my free time would be consumed. There were many evenings. I thank Valerie, my wife , for the understanding and patience in letting me complete this monumental task. I would like to extend my gratitude to A l len Sinor for his dedicated effort in helping me with our part of the textbook. If it were not for Al len. I doubt I could have completed it. Millheim It is impossible for me to list the many people to whom I am indebted for their assistance in the preparation of my part of this book.

The many meetings , discussions. For their assistance I am thankful. I would also particularly like to thank the U. Bourgoyne also holds a PhD degree in petroleum engineering from the U.

Before joining the U. Farrile S. Previously, Young worked for Exxon Co. He has also worked for Baroid Div. Young currently is the president of Woodway Energy Co.

[Pdf] - SPE Textbook - Applied Drilling Engineering

Young served as a member of the 1 Investments Committee and as the chairman of that committee in 1 97 8. He has written numerous publications in the field of drilling and rock mechanics. Young is a registered professional engineer in the State of Texas.

The level of engineering science g radually advances as one proceeds through the boo k. It is suitable for use as a text in a freshman- or sophomore-level introductory petroleum engineering course. Because the text was designed for use in more than one course, each chapter is largely independent of previous chapters, enabling an instructor to select topic s for use in a single course.

These principles and examples should allow anyone with a general background in engineering or the physical sciences to gain a basic u nderstanding of a wide range of dril ling engineering problems and solutions.

Contents 1. Rotary Drilling 1. Investments in expensive offshore and non-U. Drilling costs have become so great in many areas that several maj or oil companies often will form groups to share the financial risk. Many specialized talents are required to drill a well safely and economically. Specialized groups within the maj or oil companies also have evolved.

A staff of drilling engineers is generally identifiable as one of these groups. A well i s classified a s a wildcat well i f its purpose is to discover a new petroleum reservoir. In contrast, the purpose of a development well is to explo it a known reservoir. The drilling engineering group makes the preliminary well designs and cost estimates for the proposed well.The steps involved in coming out of the hole are shown in Fig.

A drilling line is said to have rendered one ton-hille of service when the traveling block has moved l U. He has also served as both a member and chairman of the Engineering Manpower Com mittee and was a member of the Education and Accreditation Committee. The function of the derrick is to provide the Vertical height required to raise sections of pipe from or lower them into the hole. Rotary Drilling 1. Disclaimer This book was prepared by members of the Society of Petroleum Engineers and their well-qualified colleagues from material published in the recognized technical literature and from their own individual experience and expertise.

Large platforms allow the use of a self-contained rig-i. Mel on location in the Eugene Island area, Offshore Louisiana. In some oil field areas, large landfills are operated to dispose of oil field wastes from multiple wells.

A s an industry and academic standard, Applied Drilling Engineering presents engineering science fundamentals as well as examples of engineering applications involving those fundamentals.