sonatrach drilling equipments

Development Phase

September – October 2005©abalt solutions limited - 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION

Abalt Solutions

Introduction to Hydrocarbon Exploitation

©2005 Abalt Solutions Limited. All rights reserved

Drilling Engineering

Drilling EquipmentBy Pratap Thimaiah

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Introduction-Drilling Rig

Device to drill, case andcement Oil and gaswells.

Correct procedure for rigselection :

1. Design of the well.2. Establish the various loads

to be expected duringdrilling & testingoperations.

3. Compare ratings ofexisting rigs and designloads.

4. Selection appropriate rigand its components

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Drilling Rigs

Types

– MarineBottom Supported

– Platform» Self contained» tendered

– Barge– Jack up

Floating– Semi submersible– Drill ship

– LandConventionalMobile

– Jacknife– Portable mast

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Drilling Rigs

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The Drilling Rig

Components

HoistingRotating SystemCirculating systemTubularsPressure controlDerrick capacity & substructureTotal power requirements

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Drilling Rig

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Hoisting Equipment

Main Components

Hoisting tower structure The draw works and its accessories Drilling line Control panel

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Hosting Tower

There are 3 main types of structures:– Derrick,– Mast– Trailerized guyed mast.

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The Derrick

Dynamic derrick(ships, semisubmersibles)

Standard derrick(jackups)

Examples of derricks

A = Vertical distance between the rig floor &crown block beamsB= Distance between adjacent feetC = V-door opening

D = Smallest width of the derrickE = Distance between the crown block floorand the pulley block

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Function is to provide verticalheight required to raise sections ofpipe from or lower them into hole.

Designed to withstand wind andcompressive loads.

Shape of a pointed pyramid withone foot in each corner resting onsquare angles

Metal structure can be eitherwelded or bolted.

Mobile rigs offshore generally usethis construction

The Derrick

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The Mast

Crown

Catline Sheave

Racking board

Coreline unit

Ladder

Mast

Tong counter weight

“A” frame

15'-10" 3'-1"

• The mast

Drill line

Hookblock

Wireline spoolDrum

Drawworks“A” frame

Fastline

FastlineBreakover

tod

raw

wo r

ks

Slingline Tofastlinesheave

Equalizer

• Schematic diagram showing how a mast is erected

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Shaped like a pointed and can berotated for easy mantle ordismantle.

Pulled in upright position using thedraw works and special hoistingcable.

Suited mainly for onshore drillingoperations that require goodmobility.

Racking board is in a cantileverposition and lengths of piperacked on floor called set back.

Technical specifications such asresistance to wind loads, width ofbase, free height available etc aresimilar to derrick.

The Mast

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Drilling lineTop section

Middle section

Hydraulic ram

Erection linkDeadline anchor

Traveling Block

Folding mast

Bottomsection

Trailerized Mast

The Guyed Trailerized Mast

12'-7"

6'-8"7'-2 1/2"

40'-0"

2'-6"1'-6"

30'-0"

2'-6"3'-0"

14'-0"13'-9"

5'-0" 9'-6" 20'-9" 9'-6"44'-6"

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Type of mast mainlyused with light weightrigs and workover rigs.

It telescopes in two orthree sections andworking position isforward slant.

Require specific guywires for each rigs.

Most of these are truckmounted.

Exceptional to exceed adepth of 3000mbecause ofunavailability of freeheight.

The Guyed Trailerized Mast

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D E

A

C

Truck-mounted drilling rig

B

Guy wire layout

A A

B

DCD

C A

B

BAC

A

A

Guyed Trailerized Mast

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Substructures

These serve to raise therig floor to leave roomfor wellhead assembliesand BOP stacks.

Can be separate fromhoisting system.

Hoist mast sits directlyon the box structure

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Hoisting Mechanisms

This figure give us idea of how the drilling line is strung up and thecomponents part of the system.

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Hoisting Mechanisms

Deadline:– The drilling line is secured to a specific deadline anchor, which measures

the tension on that end of the line.– It allows new lengths of lines to be run into the system in order to

relieve the worn parts of the line

Crown Block:– It is the set of pulleys (sheaves) on which the drilling line passes

through.– It is supported by the top platform of the drilling mast of derrick.– Provides a means of taking drilling line from hoisting drum to travelling

block.– Crown block is stationary

The Travelling Block and Hook:– They are normally manufactured in a solid block and diamond shaped

containing number of sheaves (less than crown block).– Drilling line is wound continuously on the crown and travelling blocks.– The hook has a shock absorber to lessen stresses when the load is

picked up and make screwing connections easier.

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Hoisting Mechanisms

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Hoisting Mechanisms

Drilling Line:

– Has a metal core with six steel wirestrands braided, or cabled, around it.

– Diameter vary widely depending onthe type of rig, but generally do notexceed 1.5 inches.

– The total line service is expressed intons per kilometre or per mile, andwill be used as a reference points toinitiate maintenance operations suchas slipping and cutting off drilling line.

Fast Line:– This is the end of the drilling line that is

reeled up on the drawworks drum.

Drum

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Hoisting Mechanisms

The Drawworks:– It is the heart of the drilling rig and provides hoisting & braking power

required to raise or lower pipes– Principle parts are

Drum– Transmits torque required for hoisting or braking.– Stores drilling line required to move travelling block.

Brakes– Stop and sustain weights imposed when lowering pipe

Transmission– Provides a means of changing direction and speed of travelling blocks

Catheads– Attached to both ends of draw works– Used for lifting and moving equipment on rig floor

– In fact, it is the capacity of the drawworks that characterizes a rig andindicates the depth rating for the borehole that can be drilled.

Auxiliary Brakes: The braking capacity of the band system is notdynamically adequate when heavier loads are lowered into the well. Twotypes of mechanism are used:

The Hydrodynamic Brake. The Eddy-Current Brake.

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Rig Floor and Equipment

There are 2 types of tools and equipment in the drilling rig: Hoisting : Elevator, Slips. Screwing, making up and breaking out the drill string:

Manual make up tongs.

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Rotating System

Equipments used to achieve bitrotation.

Main parts are– Swivel– Kelly– Rotary drive– Rotary Table– Drill Pipe– Drill collars

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Rotary Table:– This mechanical apparatus is very simple and requires

only little maintenance.

– Opening in the rotary table accepts the Kelly bushing.

– Allows the largest bit to run in hole.

– Lower portion is contoured to accept slips that grip thedrill string and prevents it from falling while a new joint isbeing added.

– A lock prevents the table from turning when pipe isunscrewed.

– Power is provided by independent rotary drive.

Rotating System

Development Phase



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Rotating System

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Kelly: The first section of pipe below the swivel. It can be square, hexagonal or triangular cross-section.

It is rotated by the table and by means of the Kelly drivebushing that it fits into.

Kelly bushing is equipped with 4 horizontal axis rollers totransmit torque to Kelly and fits into rotary table master bushing.

Kelly threads are right handed on lower end and left handed onupper end to permit normal right hand motion of drill string.

Kelly saver sub is used between Kelly and first joint of drill pipe.It contains a rubber protector to keep the Kelly centralised.

Usually the total assembly length is of 40 to 54 ft.

Rotating System

Development Phase



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KellyKelly drivebrushing

Drive pins

Drive holesRotary table

Master bushing

Taper ortapered bowl

• Kelly drive bushing

Swivel

Swivel sub

Kelly cock

Upper upset

Kelly

Lower upset

Kelly saver subRubber protector

• Kelly terminology

Rotating System

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Kelly Valves: To control incipient blowouts that might occur inside the

drill string. Lower Kelly valves have smaller diameters to enable

being run downhole during drilling.

Kelly valves

Rotating System

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Swivel: Supports weight of drill string and permits rotation.

Hangs from the lifting hook by its bail.

The gooseneck of swivel provides the downwardconnection for the rotary hose.

Power swivel– fulfil the same function as conventional ones

but also provides mechanical transmission tothe rotary string.

– Drill string can be easily pulled out whilerotating.

– No need for kelly and connected to the drillstring at any mast height.

– More static torque can be applied

Rotating System

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Circulating System

Heart of the circulating system are the mud pumps.

The major function of the circulation system is to remove cuttingsfrom hole.

Principle components of the circulating system are:– Mud pumps– Mud pits– Mud mixing equipment– Contaminants removal equipment

Circulating Cycle– Steel tanks to mud pumps– Pump through high pressure surface connections to drill string– Drill string to the bit– Through the nozzles of bit into annulus of drill string and borehole

to the surface.– Through the contaminants removal systems back to suction tanks.

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Mud pumps are of positivedisplacement type reciprocatingpistons.

The flow rate is counted in Strokes perminutes

Types– Duplex Pumps that are double

acting on both forward andbackward strokes

– Triplex Pumps that are singleacting on only forward strokes.They are lighter and more compactand easier to operate.

Wide ranges of pressures and flowrates of the pumps can be achievedby changing diameter of pump liners(compression cylinders)

Generally two circulating pumps areinstalled in a rig

Circulating System

TRIPLEX MUD PUMP

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Power and Power Transmission

The installed capacity on a drilling rig has constantlyincreased to meet the needs of modern drillingtechniques.

Modern rigs are powered by internal combustionengines

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Diesel Engines provide maximum distributionflexibility for both heavy and lightweight rigs.

Power Transmission Systems: Mechanical:

Several diesel engines are parallel operatedtrough interconnection by a chain and clutchsystem called a compound.

Easy maintenances and use, but lacksflexibility in utilization and location.

Used in light weight truck mounted rigs thatrequire no dismantling and reassembling.

Electric: Direct Current (D/C) generators driven by

diesel engines are connected in a loop with thedirect-current drawworks and pump motors.

Hydrostatic: It is found only on lightweight slim-hole rigs or

used to power independent components, e.g.power swivel, rotary table.

The mechanical energy is conveyed by highpressure hose to hydraulic motors on thedrawworks, rotary table, swivels or pumps.

Power and Power Transmission

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The Control Panel All measurement indicators are grouped together on a

pressurise explosion-proof panel. We can have information about: Hook load

Rate of penetration (ROP) Rotational speed Rotary table torque Pump stroke per minutes Pump discharge pressure.

Development Phase



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Monkeyboard

The derrick man's working platform.Double board, tribble board, fourableboard; a monkey board locatedat a height in the derrick or mast equal totwo, three, or four lengths of piperespectively.

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Top Drive

•The top drive rotates the drill stringend bit without the use of a Kelly androtary table.•The top drive is operated from acontrol console on the rig floor.

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Drill Pipe

The heavy seamless tubing used to rotatethe bit and circulate the drilling fluid.Joints of pipe 30 feet long are coupledtogether with tool joints.

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Doghouse

A small enclosure on the rig floor used as anoffice for the driller or as a storehouse forsmall objects.Also, any small building used as an office orfor storage.

Development Phase



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Blowout Preventer

A large valve, usually installed above the rampreventers, that forms a seal in the annularspace between the pipe and well bore or, ifno pipe is present, on the well bore itself

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Water Tank

Is used to store water that is used formud mixing, cementing, and rigcleaning

Development Phase



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Electric Cable Tray

Supports the heavy electrical cables that feedthe power from the control panel to the rigmotors.

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Fuel Tank

Fuel storage tanks for the powergenerating system.

Development Phase



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Electrical Control House

On diesel electric rigs, powerful dieselengines drive large electric generators.The generators produce electricity that flows

through cables to electric switches and controlequipment enclosed in a control cabinet orpanel.Electricity is fed to electric motors via thepanel.

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Bulk Mud Component Tanks

Hopper type tanks for storage of drillingfluid components

Development Phase



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Mud Tanks (Pits)

•A series of open tanks, usually made ofsteel plates, through which the drillingmud is cycled to allow sand andsediments to settle out.•Additives are mixed with the mud in thepit, and the fluid is temporarily storedthere before being pumped back into thewell.•Mud pit compartments are also calledshaker pits, settling pits, and suction pits,depending on their main purpose.

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Reserve Pit

A mud pit in which a supply ofdrilling fluid has been stored. Also,a waste pit, usually an excavated,earthen-walled pit. It may be linedwith plastic to prevent soilcontamination.

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Mud-Gas Separator

A device that removes gas fromthe mud coming out of a wellwhen a kick is being circulatedout.

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Shale Shakers

•A series of trays with sieves orscreens that vibrate to removecuttings from circulating fluid inrotary drilling operations.•The size of the openings in the sieveis selected to match the size of thesolids in the drilling fluid and theanticipated size of cuttings.

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Choke Manifold

•The arrangement of piping andspecial valves, called chokes, throughwhich drilling mud is circulated whenthe blow-out preventers are closed tocontrol the pressures encounteredduring a kick.

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Pipe Ramp

An angled ramp for dragging drillpipe up to the drilling platform orbringing pipe down off the drillplatform.

Development Phase



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Pipe Racks

A horizontal support for tubular goods

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Accumulator

The storage device for nitrogenpressurized hydraulic fluid, which isused in operating the blow-outpreventers.

Development Phase



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Annulus

•The space around a pipe in a well bore,the outer wall of which may be the wall ofeither the bore hole or the casing;•Also termed as annular space

RockPipe

Annulus

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Brake

The braking device on the draw works tostop a load being lifted

Development Phase



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Casing Head

•A heavy, flanged steel fitting connected tothe first string of casing.•It provides a housing for slips and packingassemblies, allows suspension ofintermediate and production strings ofcasing, and supplies the means for theannulus to be sealed off.• Also called a spool.

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Cathead

A spool-shaped attachment on a wincharound which rope for hoisting and pullingis wound

Development Phase



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Catwalk

The ramp at the side of the drilling rig wherepipe is laid to be lifted to the derrick floor by theCatline or by an air hoist.

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Cellar

•A pit in the ground to provide additionalheight between the rig floor and the well headto accommodate the installation of blow-outpreventers, rat holes, mouse holes, and so forth.•It also collects drainage water and other fluidsfor disposal.

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Conductor Pipe

•The largest diameter casing and the topmostlength of casing.•It is relatively short and encases the topmoststring of casing

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Degasser

The equipment used to removeunwanted gas from a liquid, especiallyfrom drilling fluid

Development Phase



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Desander

•A centrifugal device forremoving sand fromdrilling fluid to preventabrasion of the pumps.• It may be operatedmechanically or by a fast-moving stream of fluidinside a special cone-shaped vessel, in whichcase it is sometimes calleda hydro cyclone

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Desilter

A centrifugal device, similar to aDesander, used to remove very fineparticles, or silt, from drilling fluid.This keeps the amount of solids in thefluid to the lowest possible level.

Development Phase



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Drill Bit

The cutting or boring element used indrilling oil and gas wells. Most bitsused in rotary drilling are roller-cone bits.The bit consists of the cuttingelements and the circulatingelement.The circulating element permits thepassage of drilling fluid and usesthe hydraulic force of the fluidstream to improve drilling rates.

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Drill Collars

A heavy, thick-walled tube,usually steel, used betweenthe drill pipe and the bit inthe drill stem. It is used toput weight on the bit sothat the bit can drill.

Development Phase



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Driller's Console

The control panel, located on theplatform, where the drillercontrols drilling operations

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Elevators

A set of clamps that grips astand, or column, of casing,tubing, drill pipe, or suckerrods, so the stand can beraised or lowered into thehole.

Development Phase



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Hoisting Line

A wire rope used in hoisting operations.Must conform to the API standards forits intended uses.

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Hook

A large, hook-shaped devicefrom which the elevator bailsor the swivel is suspended. It isdesigned to carry maximumloads ranging from 100 to650 tons and turns on bearingsin its supporting housing.

Development Phase



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Kelly

The heavy square or hexagonalsteel member suspended from theswivel through the rotary table. Itis connected to the topmost jointof drill pipe to turn the drill stemas the rotary table turns

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Kelly

Kelly Saver Sub

Master Bushing

Kelly

Kelly Drive Bushing

Turntable

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Kelly Bushing

A device fitted to the rotary tablethrough which the Kelly passes.

It is the means by which the torque ofthe rotary table is transmitted to the Kellyand to the drill stem.

Also called the drive bushing

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Kelly Spinner

A device for spinningthe drill pipe.Replaces the spinningchain.

Development Phase



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Mouse hole

Shallow bores under therig floor, usually linedwith pipe, in which jointsof drill pipe aretemporarily suspendedfor later connection tothe drill string.

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Mud Return Line

A trough or pipe, placedbetween the surfaceconnections at the well boreand the shale shaker.Drilling mud flows through itupon its return to thesurface from the hole.

Development Phase



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Ram BOP

•A blow-out Preventer that usesrams to seal off pressure on ahole that is with or without pipe.

•Ram-type preventers haveinterchangeable ram blocks toaccommodate different O.D. drillpipe, casing, or tubing

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Rat hole

A hole in the rig floor 30 to 35 feetdeep, lined with casing that projectsabove the floor. The Kelly is placed inthe rat hole when hoisting operations arein progress.

Development Phase



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Rotary Hose

The hose on a rotary drilling rig thatconducts the drilling fluid from the mudpump and standpipe to the swivel andKelly; also called the mud hose or theKelly hose.

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Rotary Table

•The principal component of a rotary, orrotary machine, used to turn the drill stemand support the drilling assembly.

•It has a bevelled gear arrangement tocreate the rotational motion and anopening into which bushings are fitted todrive and support the drilling assembly.

Development Phase



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Slips

Wedge-shaped pieces of metalwith teeth or other grippingelements that are used to preventpipe from slipping down into thehole or to hold pipe in place.

Rotary slips fit around the drillpipe and wedge against themaster bushing to support the pipe.

Power slips are pneumatically orhydraulically actuated devices thatallow the crew to dispense with themanual handling of slips whenmaking a connection.

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Spinning chain

A relatively short length of chain attached tothe tong pull chain on the manual tongs used tomake up drill pipe.

The spinning chain is attached to the pullchain so that a crew member can wrap thespinning chain several times around the tooljoint box of a joint of drill pipe suspended inthe rotary table.

After crew members stab the pin of anothertool joint into the box end, one of them thengrasps the end of the spinning chain and with arapid upward motion of the wrist "throws thespinning chain"—that is, causes it to unwrapfrom the box and coil upward onto the body ofthe joint stabbed into the box.

Development Phase



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Stairways

Stairs leading from one level to another.Protected with handrails

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Standpipe

A vertical pipe rising along theside of the derrick or mast. Itjoins the discharge line leadingfrom the mud pump to therotary hose and through whichmud is pumped going into thehole.

Development Phase



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Surface Casing

Usually the first casing tobe run in a well. This isdone after spudding -inso a blow-out Preventercan be installed beforedrilling is started

Intermediate casing

Conductor/stovepipe

Surface casing

Production casing

Production liner

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Substructure

The foundation on which thederrick or mast and usually thedraw works sit; contains space forstorage and well controlequipment

Development Phase



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Swivel

•A rotary tool that is hung fromthe rotary hook and travellingblock to suspend and permit freerotation of the drill stem.•It also provides a connection forthe rotary hose and apassageway for the flow ofdrilling fluid into the drill stem.

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Tongs

•The large wrenches used for turningwhen making up or breaking out drillpipe, casing, tubing, or other pipe;variously called casing tongs, rotarytongs, and so forth according to thespecific use.•Power tongs are pneumatically orhydraulically operated tools that spinthe pipe up and, in some instances,apply the final makeup torque.

Development Phase



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Walkways

An area cleared for movingthrough by personnel andprotected with a handrail.

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Weight Indicator

A device for measuring the weightof the drill string. Monthlycalibration to calculated drill stringweight is required by API

Development Phase



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Drilling Systems

Whether Onshore or Offshore Drilling is carried out, the basic drillingsystem employed in both cases will be rotary rig.

Three basic functions are carried out during rotary drilling operations:

Torque is transmitted from a power source at the surface through adrill string to the drill bit.

A drilling fluid is pumped from a storage unit down the drill string andup through the annulus. This fluid bring the cuttings created by the bitaction to the surface , clean the hole, cool the bit and lubricate the drillstring.

The subsurface pressures above and within the hydrocarbon bearingstrata are controlled by the weight of the drilling fluid and by largevalve assemblies at the surface.

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Drillstring Basics

The drillstring is the mechanical linkage connecting thedrill bit at the bottom of the hole to the rotary drivesystem on the surface. It serves the following functions:

– Transmits rotation to the drill bit– Exerts weight on the bit; the compressive force

necessary to break the rock– Guides and controls the trajectory of the bit– Allows fluid circulation which is required for cooling

the bit and for cleaning the hole

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Drillstring Components

1. Drill pipe2. Drill collars3. Accessories:

Heavy-walled drill pipe (HWDP) Stabilisers Reamers Directional control equipment

Drillstring Basics

Kelly

Drill Pipe

Heavy weight drillpipe

Crossover SubConnector

Pressuredisconnect

LWD/MWD tools

Adjustable benthousing

Mud motor

Orienting tool

Drill Collars

Check valveassembly

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Drill Pipe Properties

Drill Pipe Grade: Each joint includes the tube bodyand the tool joint.

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Drill Pipe Class: to account for the degree of wear.– New: no wear, has never been used.– Premium: Uniform wear and a minimum wall

thickness of 80% of new pipe.– Class 2: Drill pipe with a minimum wall thickness of

65% with all the wear on one side so long as thecross sectional area is the same as the premiumclass.

– Class 3: Drill pipe with a minimum wall thickness of55% with all the wear on one side.

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Tool joints: Screw type connectors that join individualjoints of drill pipe. Most tool joints are made of 120,000 psiyield strength material.

– IEU (internal-external upset): tool joint is larger than thepipe such that the tool joint ID is less than the drill pipe.The tool joint OD is larger than the drill pipe. GenerallyIEU connections are the strongest available couplings.

– IF (internal flush): Tool joint ID is approximately thesame as the pipe. The OD is upset.

– IU (internal upset) Tool joint ID is less than the pipe.Tool joint OD is approximately the same as the pipe. Thistype is often termed “slim-hole” pipe because of thereduced outer clearance.

Tool joints are designed to be run in tension.

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Thread Form:– Below are the most common thread styles and forms used in the oil

industry.– The most common is the Numbered Connection (NC). The thread has a

V shape form and is identified by the pitch diameter, measured at apoint 5/8” from the shoulder, the gauge point multiplied by 10.

– Thus NC 50 has a gauge point pitch diameter of 5.0417”.

0.038”

0.057”

0.025”0.025”

0.015”

NC

REG

FH

SST

IF XH PAC

OH SHDSL

NC

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Washouts in Drill Strings

Tool joint failure is due entirely to the threads not holding or not beingmade properly. The make up torque puts the pin in tension and the boxin compression.

If the pin and box are not properly torqued, then the seals may separateunder downhole conditions allowing a leak mud for the mud.

For a length of 1,000 ft of drill string there are 66 separate pin andboxes. Leek paths within the tool joints develop if the seal is broken or ifimproper torque is applied. The leak path will lead to erosion.

Developed leak path are usually detected by a decrease in the standpipepressure, between 100 - 300 psi over 5 - 15 minutes.

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Drill Collar Properties

Proper selection of drill collars (and BHA ) can prevent many drillingproblems. Some of its functions are as follows:

– Provide weight for the bit– Provide strength needed to run in compression– Minimize bit stability problems from vibrations, wobbling, and

jumping– Minimize directional control problems by providing stiffness to the

BHA

The most common types are round (slick) and spiral grooved.

Spiral-grooved collars reduce the surface contact area between the pipeand well bore. The lower contact area reduces the probability ofdifferential pressure sticking.

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Drill Collar – Size Criteria

Selection of drill collar diameter fora slick or pendulum assembly isbased on the required effectiveminimum hole diameter.

That is, the size of the bottom drillcollar would be the limiting factorfor lateral movement of the bit.

_ _Minimum effetive hole dia.

2Bit size Drillcollar dia

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More commonly drill collar size is selected based onstresses.

Components subject to bending have both tensile andcompressive forces induced in them. When rotatedunder bending, individual metal fibers are subject torapidly alternating tension and compression, which mayinduce fatigue failure.

BHA are subject to both bending and rotation. Fatiguefailures commonly occur at connections and changes inpipe size

The bending resistance of a BHA component isdependent upon its section modulus, which is defined asfollows:

4 42 ( )32

I OD IDZ

OD OD

Z : Section modulus, in3

I : second moment of area, in4

OD : Outside diameter, inID: Inside diameter, in

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Generally, the change in bending resistance is expressedin terms of a bending resistance ratio (BRR), whichmay be calculated with the equation below.

The bending resistance ratio should be checked atchanges in pipe size. BRRs are calculated using the pipebody dimensions and should generally be below 5.5

4 41 1 1 2

4 42 2 2 1

( )( )

Z OD ID ODBRR

Z OD ID OD

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Drill Collar Selection

Typical sizes of drill collars to be run in each hole section:

Drill Collar Profiles

Slick Drill Collar- Same nominal diameter over total length of joint

Spiral Drill Collar- Reduces risk of differential sticking. Reducesweight of collar and contact area.

Square Drill Collar- In special operations to reduce deviation incrooked formations and provide good rigidity.

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Buoyancy Factor Method

Drill collars have a significantly greater stiffness whencompared to drill pipe and as such can be run incompression. Drill collars are used to provide weight foruse at the bit and at the same time keep the drill pipe intension.

In order to avoid buckling, weight on bit should notexceed 85% of the buoyed weight on the collars.

l _

165.5

(0.85)lenght DC

ength verticallenght

MWBF

WOB DC Weight BF

DCDC

Cos

BF : Buoyancy factorMW : Mud weight, ppgDC lenght : Drill collars length, ftWOB : Desired weight on bit, lb (x1000)WeightDC : Drill collar weight in air, lb/ft: well inclination

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Neutral Point of Bending

Buckling occurs only below the neutral point of bending,which is defined as the point where the average of theradial and tangential stress in the string equal the axialstress.

The neutral point of bending occurs where the effectivehydrostatic force equals the compressive force in thedrillstring.

_ string

WOBH

Buoyed WT

H: Height of neutral point, ftWOB: Weight on bit, lbBuoyed_WTstring: Buoyed weight of drill string, lb/ftIf the hole is inclined, the buoyed weight must be reducedby a factor equal to the cosine of the well inclination

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Weight on Bit

For vertical holes, the maximum weight on bit availablecan be calculated as follows:

max 0.85 DC DCWOB L Wt BF

WOBmax: Available weight on bit, lbLDC : Length of drill collars, ftWTDC: Air weight of drill collars, lb/ftBF: Buoyancy Factor

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Weight on Bit

For inclined holes, the maximum weight on bit available can becalculated as follows:1. Calculate the available weight on bit provided by the drill collars

2. Calculate the maximum available WOB provided by the HWDP

3. Calculate the critical force to buckle the HWDP

4. Calculate the critical force to buckle the drill pipe

4 4 2 2

_max_ _

1617 HWDP HWDP HWDP HWDPHWDP critc

hole of HWDP

OD ID BF OD ID SinF

D OD

DC DC DCWOB L Wt BFCos

HWDP HWDP HWDPWOB L Wt BFCos

4 4 2 2

_max_ _

1617 pipe pipe pipe pipeDP crit

hole of pipe

OD ID BF OD ID SinF

D OD

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Weight on Bit

For inclined holes, the maximum weight on bitavailable can be calculated as follows:5. If WOBHWDP+FDP crit>FHWDP crit Then the maximum

allowable weight on bit is given by the following:

6. If WOBHWDP+FDP crit<FHWDP crit Then the maximumallowable weight on bit is given by the following:

7. The maximum WOB calculated above should bereduced by a safety factor. Generally, a safetyfactor of 85% is adequate.

max _DC HWDP CritWOB WOB F

max _DC HWDP DP critWOB WOB WOB F

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Weight of BHA Required

Weight of drill collars required is estimated from the bitspecifications and formation classification.

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Tension

The design of the drill string for static tension loadsrequires sufficient strength in the topmost joint of eachsize, weight, grade and classification of drill pipe tosupport the submerged weight of all the drill pipe plusthe submerged weight of the collars, stabilizers, andbit.

This load may be calculated as follows:

TEN DP DP DC DCF L Wt L Wt BF

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Tension – Design Criteria

The difference between the calculated load FTEN and themaximum allowable tension load represents the Margin ofOver Pull (M.O.P.)

Normally the designer will desire to determine themaximum length of a specific size, grade, and inspectionclass of drill pipe which can be used to drill a certain well.By combining the above equations the following equationresults:

design TENMOP F F

0.9design yieldF F

0.9 yield DC DCDP

DP DP

F MOP L WtLWt BF Wt

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Burst

The drill pipe internal yield pressure can be calculatedas follows:

2 mi

Y WtP

D

Pi : burst pressure, psiYm : specified minimum yield strength, psiWt: pipe wall thickness, inD: outside pipe diameter, in

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Collapse

Drill stem testing (DST) causes the most severe collapseloading on the drill pipe.

API specifications for collapse resistance of drill pipe iscalculated assuming either transition, or plastic failurebased on the pipes D/t (diameter / wall thickness ratio).

The collapse resistance of drill pipe corrected for theeffect of tension loading may be calculated with thefollowing equation:

24 32_ _

* _ avg

Z ZR

Total Tensile loadZA Yield Strength

Effective Collapse Resistance under tension = R * Nominal plastic collapse resistance

A : Cross section area, sq. in

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Slip Crushing

The maximum allowable tension load must bedetermined to prevent slip crushing.

12 2

12 2

H

T S S

S DK DKS L L

HS L

T

ST T

S

SH : hoop stress, psiST : tensile stress, psiD : outside diameter of pipe, inK : lateral load factor on slipsLS : Length of slips, inTS : tension from slip crushingTL : tensile load in string

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Pipe Torsion

Torsion only– Drill pipe torsional yield strength when subject to pure

torsion is given by the following:

Torsion and Tension– When drill pipe is subject to both torsion and tension,

as is the case during drilling operations, the minimumtorsional yield strength under tension is given asfollows

0.096167 mJYQ

D

4 4

32J D d

Q : minimum torsional yield strength, ft-lbJ : polar moment of inertiaD: Pipe OD, ind: Pipe ID, inYm : minimum unit yield strength, psi

22

2

0.096167t m

J PQ YD A

Qt : minimum torsional yield strength under tension, ft – lbP : total load in tension, lbsA : cross-sectional area, sq. in

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Fatigue

The most common type of drill pipe failure is fatigue wear. Itgenerally occurs in dog legs where the pipe goes throughcyclic bending stresses.

These stresses occur because the outer wall of the pipe in adog leg is stretched and creates a greater tension load.

Fatigue damage from rotation in dog legs is a significantproblem if the angle is greater than some critical value.

The maximum permissible dogleg severity for fatiguedamage consideration can be calculate with the followingequations:

432,000 tanhb KLC

EDKL

TK

EI

C : maximum permissible dogleg severity, °/ 100 ftE : Young’s modulus, psi (30*106 psi for steel and 10.5*106 psi foraluminiumD : drill pipe outer diameter, inL : half the distance between tool joints, 180 in for Range 2 pipe, inT : tension below the dog leg, lb

b : maximum permissible bending stress, psiI : drill pipe moment of inertia 4 4

64D d

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Critical Rotary Speeds

Transverse Vibration– The approximate critical rotary speeds which induce

nodal (transverse) vibration can be calculated using thefollowing shown below.

Axial Vibration– The approximate critical rotary speeds which induce

pendulum or spring (axial) vibration can be calculatedusing the following shown below.

2 22

476000_Critical RPM D d

L

258000_Critical RPM

L L : total length of string, ft

L : total length of one pipe, ft

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Drill String Design Process

Development Phase



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Heavy Walled Drill Pipe

Same OD as standard drill pipe but reducedinner diameter

Has an extra Tool joint.Used between DP and DC to provide a smooth

transition between the section moduli of drillstring.

Centre wear pad acts as stabiliser increasingoverall stiffness

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Stabilisers

Tools placed above Bits and along BHA to control: Dogleg severity Hole Deviation Differential sticking

Provides extra stiffness to the BHA . -centralization and improved Bit performance.

Types Rotating Stabilisers-include integral blade, sleeve and

welded blade stabilisers. Non-Rotating Stabilisers-

– Comprise of Rubber Sleeve and Mandrel.– Used to prevent reaming of hole walls during drilling

operations– Protect Drill collars from wall contact wear.

Development Phase



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Reamers

Used where High torque ,swelling or abrasiveformations are encountered.

To replace near bit and first string stabiliserswith a roller reamer with either 3 or 6 cuttersets.

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Drilling Jars

Jars are a mandrel within a sleeve that provide upward or downwardpower blows to a stuck drill string

Types Mechanical Jars

-Preset Load causing jar to trip-Sensitive to load and not time-Free end of mandrel is in a hammer form striking an anvil.

Hydraulic Jars– -Hydraulic fluid to control firing of the jar.– -Sensitive to load and time.

Bumper Jars– -Free travel to assist in engaging a fish

Development Phase



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Drill Bits

What is a bit ?Cutting or boring element used in drilling wells that comprises of

circulating and cutting elements

Objective Deliver lowest cost/ft

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Bit Types

Rotary drilling bits usually are classified accordingto their design

Drag or Fixed cutter– Natural Diamond/TSP– PDC– Impregnated

Roller Cone– Milled tooth– Insert Fixed cutter

Rotarydrill ing bits

Roller cone

Earl yroll ing

cutter

Earl y

fishtail

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Drag or Fixed cutter bits consist of fixed cutterblades that are integral with the body of the bitand rotate as a unit with the drillstring.

Rolling cutter bits have two or more conescontaining the cuttings elements, which rotateabout the axis of the cone as the bit is rotatedat the bottom of the hole.

Bit Types

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Bit Selection Considerations

Formation characteristics should be studied in detail to assess the typeof cutting structure required to successfully drill the formation.

The existence of abrasive and hard minerals such as chert or pyritenodules should be identified.

Gauge protection (which determines the final hole size) is particularlycritical in abrasive formations

Drilling fluid details and well bore profile

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Bit Selection Considerations

When drilling directional wells the Directional Contractor should be askedto provide an assessment of the required BHA changes.

In addition bit characteristics in terms of walk, build and drop tendencieswill need to be assessed for their impact on the well path.

When drilling soft shale sections where the major limitations on ROP isbottom hole and cutter cleaning, the use of centre jet, extended jets orlateral jet bits should be considered.

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Roller Cone Bits

Made up of (usually) three equal -sized conesand three identical legs which are attachedtogether with a pin connection. Each cone ismounted on bearings which run on a pin thatforms an integral part of the bit leg.

The three legs are welded together and formthe cylindrical section which is threaded tomake a pin connection. The pin connectionprovides a means of attachment to the drillstring.

Each leg is provided with an opening for fluidcirculation. The size of this opening can bereduced by adding nozzles of different sizes.

Nozzles are used to provide constriction inorder to obtain high jetting velocitiesnecessary for efficient bit and hole cleaning.

Mud pumped through the drillstring passesthrough the bit pin bore and through thenozzles.

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Roller Cone Bits

Types

Milled tooth bits: The cuttingstructure is milled from the steelmaking up the cone

Insert bits: The cutting structureis a series of inserts pressed intothe cones.

Steel-tooth bits

Insert bits

Formation hardnessSoft Hard

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Roller Cone Bits

Development Phase



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Roller Cone bits-Cutting Action

Soft Formation :Gouging-Scrapping– Most aggressive

cutting action– Typically high ROP

Applications

Hard Formations:Chipping-Crushing– Most durable cutting

action– Low ROP applications

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Design Factors

Directly influence the type of cutting action– Journal angle– Offset between cones– Cone profile angle

Development Phase



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Skew angle, or offset, and cone shapecause cones to periodically stop rotatingas the bit turns. As a result, cuttingstructures slide on the bottom of a holeand scrape the formation.

Offset angles vary from 5° for softformations to zero in hard formations.Bits for soft formations use longercutting structures with cone-offsetangles that reduce true rolling motion.

Short cutters on cones that roll moregenerate crushing action in hardformations.

Crushing Gouging and scraping

Low skew (0°) High skew (5°)

Directionof rotation

Gauge

Truerolling atall points

Gauge

Conecontourdeparts

from truerollingmotion

Journal

angle

Design Factors

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Milled tooth bits

Milled tooth bit design depends on the geometry of the cones and the bitbody and geometry and composition of the cutting elements (teeth).

The geometry of the cones and of the bit body depend on:– Journal Angle– Cone Profile– Offset Angle

The geometry and composition of the teeth depend on:– Journal Angle– Angle of Teeth– Length of Teeth– Number of Teeth– Spacing of Teeth– Shape of Teeth– Tooth Hard facing

Development Phase



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Journal Angles The bit journal is the bearing load-

carrying surface. The journal angle is defined as

the angle formed by a lineperpendicular to the axis of thejournal and the axis of the bit

The magnitude of the journalangle directly affects the size ofthe cone; the size of the conedecreases as the journal angleincreases.

The journal angle also determineshow much WOB the drill bit cansustain; the larger the angle thegreater the WOB. The smaller thejournal angle the greater is thegouging and scraping actionsproduced by the three cones.

The optimum journal angles forsoft and hard roller cone bits are33 degrees and 36 degrees,respectively.

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Cone Profile

The cone profile determines the durability of the drill bit. Cones with flatter profile are more durable but give lower

ROP, whilst a rounded profile delivers a faster ROP but isless durable

Development Phase



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Cone Offset

The degree of cone offset (or skew angle) isdefined as the horizontal distance between theaxis of the bit and a vertical plane through theaxis of the journal.

A drill bit with zero offset has the centre lines ofthe three cones meeting at the centre of the drillbit. Skew angle is an angular measure of coneoffset.

A cone with zero offset has a true rolling action asthe cone moves in a circle centered at the coneapex and bit centre.

The amount of offset is directly related to thestrength of rock being drilled.

Soft rocks require a higher offset to producegreater scraping and gouging actions.

Hard rocks require less offset as rock breakage isdependent on crushing and chipping actionsrather than gouging.

Cone offset increases ROP but also increasestooth wear, especially in the gauge area, andincreases the risk of tooth breakage.

Low skew (0°) High skew (5°)

Directionof rotation

Gauge

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Tooth angle and length

As shown, drill bits can haveslender and long teeth or shortand stubby teeth.

The long teeth are designed todrill soft formations with lowcompressive strength where therock is more yielding and easilypenetrated. Soft

formations

Soft-to-mediumformations

Medium-to-hardformations

Hardformations

43A

53

63

73

51

53A

83

51A

61

52A

62 62A

Cemented-carbide microstructure

10

Development Phase



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Tooth angle and length

Penetration is achieved by applying weight on bit (WOB) which forces theteeth into the rock by overcoming the rock compressive strength.Rotation of the bit helps to remove the broken chips.

Harder rocks have high compressive strength and can not be easilypenetrated using typical field WOB values.

Hard rock bits therefore have much shorter (and more) teeth with alarger bearing area., therefore the short teeth will be less likely to breakwhen they are subjected to drilling loadings.

The teeth apply load over a much larger area and break the rock by acombination of crushing, creation of fractures and chipping. The teeth arenot intended to penetrate the rock, but simply to fracture it by theapplication of high compressive loads.

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Bearings

Major Bearing Types

– Roller BearingTypically used in larger bit sizesReferred to as ‘Anti-friction bearings’

– Friction BearingTypically for smaller bit sizesReferred to as ‘Journal’ Bearings

Development Phase



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There are two bearing types, roller and friction (or journal).

Roller bearings may be sealed or unsealed whilst friction bearings arealways sealed.

In roller bearings, the loads applied to the cutting structure istransmitted to the journal through a series of rollers.

There may be one, two or three of these roller races depending uponthe size of the bit.

Bearing life is affected by:– heavy reaming which reduces bearing life– directional effects which produce high side loadings– severe Drillstring and bit vibrations

Bearings

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Bearings

Functions:

•Support Radial Loads

•Support thrust or axial loads

•Secure cones on legs

Development Phase



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Antifriction bearings

Roller bearings carry most of the loads, and ballbearings inserted through a hole in the journal holdcones in place. A thrust face and friction pin carrynose loads and stabilize the bearings.

Seals keep grease inside bearings, and prevent mudand solids from entering.

Grease reservoirs in the lugs ensure lubrication. Thereis no pressure differential across the seals, andhydrostatic pressure is transferred through adiaphragm to equalize pressure between the bearingsand borehole.

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Antifriction bearings

Development Phase



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Friction Bearings

Bearings without antifriction rollers are durable andhandle high weights because loads are distributed over alarger bearing area.

Floating beryllium-copper bushings dissipate heat andreduce relative velocities between journals and cones.

Silver plating acts as a solid lubricant to further reducefriction and wear.

Radial elastomer seals are used because they require lesscompression than round seals and do not generate asmuch heat.

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Friction Bearings

Development Phase



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Insert Bits

The design factors relating to cone offset, bit profile and cone profileapply equally to insert bits.

The cutting structure of insert bit relies on using tungsten carbideinserts which are pressed into pre-drilled holes in the cones of the bit.The following relates to the various design features of inserts which aredesigned to suit various rock types.

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Insert Number, Diameter, and Spacing

Soft insert bits have fewer and longer inserts to provide aggressivepenetration of the rock. Durable, hard formation bits have many, smalldiameter inserts with limited protrusion.

Development Phase



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Insert Shape

For soft formation bits, the inserts have chisel shapes to provideaggressive drilling action.

In soft, poorly consolidated formations the chisel shape is more efficientat penetrating the formation than a more rounded conical shape.

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IADC Bit Classification for Roller ConeBits

Three code system for roller cone bits

The first code or digit defines the series classification relating to thecutting structure. The first code carries the numbers 1 to 8.

For milled tooth bits, the first code carries the numbers 1 to 3, whichdescribes soft, medium and hard (and semi-abrasive or abrasive)rocks respectively. This number actually signifies the compressivestrength of rock.

For insert bits, the first code carries the numbers 4-8.

The second code relates to the formation hardness subdivision withineach group and carries the numbers I to 4. These numbers signifyformation hardness, from softest to hardest within each series. Thesecond code is a subdivision of the first code (1 to 8)

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IADC Bit Classification for Roller ConeBits

The third code defines the mechanical features of the bit such asnon-sealed or sealed bearing. Currently there are sevensubdivisions within the third code:

1. Non-sealed roller bearing2. Roller bearing air cooled3. Sealed roller bearing4. Sealed roller bearing with gauge protection5. Sealed friction bearing6. Sealed friction bearing with gauge protection7. Special features - category now obsolete.

As an example, a code of 1-2-1 indicates:– Code 1: long, slim and widely spaced milled tooth bit– Code 2: medium soft formations (if this number was 4, then it

is hard soft formation)– Code 3: non-sealed bearings

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IADC Bit Classification

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Fixed Cutter Bits

Styles– PDC– Natural Diamonds– Impregnated

Terminology– PDC-Polycrystalline Diamond Compact– TSP-Thermally Stable Polycrystalline

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Fixed Cutter Bits

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Polycrystalline Diamond Compact (PDC)Bits

A polycrystalline diamond compact (PDC) bit employs no moving parts (i.e. thereare no bearings) and is designed to break the rock in shear and not incompression as is done with roller cone bits.

Rock breakage by shear requires significantly less energy than in compression,hence less weight on bit can be used resulting in less tear and wear on the rig anddrillstring.

A PDC bit employs a large number of cutting elements, each called a PDC cutter.The PDC cutter is made by bonding a layer of polycrystalline man-made diamondto a cemented tungsten carbide substrate in a high pressure, high temperatureprocess.

The diamond layer is composed of many tiny diamonds which are grown togetherat random orientation for maximum strength and wear resistance

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PDC Terminology

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Bit Design Elements

The PDC design is affected by:

1. Body design: can either be steel-bodied or tungsten carbide (matrix)

2. Cutters Geometry Cutters Number of Cutters and spacing of cutters Size of Cutters Back Rake Side Rake

3. Geometry of Bit Number of Blades Blade Depth

4. Diamond table Composition Shape

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PDC Bits Applications PDC bits are typically useful for drilling long, soft to medium shale

sequences which have a low abrasivity. In such formations they typicallyexhibit high ROP and extended life enabling entire sections to be drilled onone run.

PDC bits are not usually appropriate for highly abrasive well cementedsand sequences. When drilling tight siliceous formations the incidence ofPDC chipping and breaking is dramatically increased resulting in less thanexpected ROP and bit life.

When drilling heterogeneous formations containing alternating shales andor shale limestone sequences the use of hybrid PDC bits is encouraged.This bit incorporates the use of back-up diamond studs behind the PDCcutter.

When drilling mobile, plastic formations such as salt sections the use ofeccentric PDC bits should be considered. These bits have provedsuccessful in preventing incidence of stuck pipe

The use of bladed hybrid PDC bits is recommended for drilling hardformations. The deep watercourse on these bits enable optimum fluid flowacross the cutter to efficiently reduce the friction temperatures induced

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Diamond and TSP Bits

Diamond is the hardest mineral. Diamond also posses the highestthermal conductivity of any other mineral allowing it to dissipateheat very quickly. This is a desirable property from a cutting elementto prevent it from burning or thermal fracture due to overheating.

Diamond and TSP (thermally stable PDC) bits are used for drillinghard and abrasive formations and particularly useful in turbinedrilling applications.

ROP's achieved with diamond bits are generally low due to thenature of the formations that they are designed to drill. Due to theirfixed cutter design, greater endurance is achieved with diamond bitsas compared with similar formation rated insert bits.

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Diamond and TSP Bits

The cutting elements of a diamond bit consists of a large number ofsmall-sized diamonds geometrically distributed across a tungstencarbide body.

The bit does not employ moving parts and is especially suited todrilling hard and abrasive formations (such as quartzite) and whenlonger bit runs are required to reduce trip times.

Diamond bits are manufactured as either drilling or coring bits.

Diamond bits comprise: natural diamond bits, TSP bits andimpregnated bits. They share several features:– similar profiles– common drilling mechanism – grinding– hydraulics dominated by flow through waterways– application in hard and very hard formations, with corresponding

poor performance in soft rocks.

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Diamond Bit Terminology

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Impregnated Bits

Diamond-impregnated bits are specialized grinding wheels.

Dura-diamond technology provides options to handle any type of hardformation. Special mixtures of diamonds and tungsten carbide weredeveloped to increase penetration rates and ensure longer bit life.

Matching matrix and diamond wear balances bit life and penetrationrate. If the matrix is too soft, diamonds are released before theywear out, which shortens bit run time. If the matrix is too hard,diamonds are not properly exposed and penetration rates arereduced.

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Impregnated Bit Terminology

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Impregnated Bits

Three profiles are available (middle).– The most aggressive profile is a deep double cone (blue) for drilling

softer interbedded formations and horizontal sections– A rounded, shallow double cone (red) is used in intermediate- strength

formations.– A flatter rounded profile (green) is a general-purpose design for

harder, abrasive formations and angle-building sections of directionalwells.

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Drilling Mechanics

How do Bits drill ?

– Roller Cone: Crushing– PDC: Shearing– Natural Diamond & Impregnated: Grinding

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Drilling Mechanics

sonatrach drilling equipments

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