Script for All 10 CDs

Finished on July,

2010, INDIA

OILWELL DRILLING -----BHUVANESHWAR CHAUDHARI

CONTENTS

VOLUME ONE

AN INTRODUCTION TO RIG TYPES AND BASIC DRILLING STRING COMPONENTS

Rig types……………………………………………………………………………10

OverviewLand RigsMobilizing Land RigsJack-Up RigsMobilizing Jack-Up RigsPlatform RigsSubmersiblesSemi-submersiblesSemi-submersible MobilizationDrill ships

Kelly & Top Drives………………………………………………………………...11

Making HoleOverviewTop Drive SystemTop Drive OperationKelly SystemsKelly Operation

Drilling String Components……………………………………………………..12

OverviewDrill PipeDrill Pipe SpecsBox & PinDrill Pipe Make UpHeavy Walled Drill PipeSpiral Heavy Walled Drill PipeDrill CollarsSlick & Spiral Drill CollarsCrossover Subs Reamers & Stabilizers

SCRIPT CONTRIBUTED BY BHUVAN1


Bottom Hole AssemblyPipe Rack

Drill Bits…………………………………………………………………………….15OverviewRoller Cone BitsSteel Tooth BitTungsten Carbide BitFixed Cutter BitPDC BitPDC CompactDiamond BitCore Bit and Barrel

Special Drill String Tools………………………………………………………...16

OverviewDrilling JarsDrilling Jar OperationMWDMud MotorDirectional WellsHorizontal Wells

VOLUME TWO

BASIC BLOWOUT PREVENTION EQUIPMENTPressure Control………………………………………………………………….17

OverviewBlowoutTaking a Kick

Blowout Preventers………………………………………………………………18Basic ConceptsBOP Operation

Basic BOP Equipment……………………………………………………………20

OverviewDriller’s BOP ControlAccumulatorHydraulic LinesOperating Lever on AccumulatorChoke Manifold / ChokesChoke OperationChoke Control PanelMud-Gas SeparatorSeparator Operation



Flare Line & Flare PitTrip TankTrip Tank Operation

Subsea BOP Equipment…………………………………………………………22OverviewMarine Riser SystemRiser & Guideline Tensioner

Drill String Valves & IBOPs……………………………………………………...23

OverviewUpper / Lower Kelly CocksFull-Opening Safety ValveSafety Valve UsageFloat Valves

VOLUME THREE

INTRODUCTION TO DRILLING FLUIDSMud Types………………………………………………………………………….24

OverviewWater Based MudOil MudDrilling with AirFoam DrillingAerated Drilling

Drilling Fluid Function…………………………………………………………...25OverviewCleaning the HoleCooling / LubricationProtecting Wellbore WallsControlling Formation PressureObtaining Downhole Information

Mud Properties & Additives…………………………………………………….26BentoniteBaritePHCaustic SodaGelled Mud

Mud Tests…………………………………………………………………………..27OverviewMud BalanceMarsh FunnelRotational ViscometerFilter Press



Chloride Test

VOLUME FOUR

MUD CIRCULATION & TREATING EQUIPMENTMud System Overview…………………………………………………………...29

OverviewMud TanksMud PumpsStandpipe & Rotary HoseBit & AnnulusReturn Line, Shaker & Mud Tanks

Mud Storage, Tanks & Reserve Pit…………………………………………….30OverviewMud HouseBulk TanksActive TanksSand TrapSettling TanksReserve TanksSlug TankSuction TankChemical TankReserve Pit

Mud Pumps………………………………………………………………………...31

OverviewTriplex PumpTriplex Pump OperationDuplex PumpPump ComponentsBladder-Type Pulsation DampenerNonbladder-Type Pulsation DampenerSuction DampenerDischarge Line Relief ValveSuction Line Relief ValvePump Discharge Line

Mud Conditioning…………………………………………………………………34

OverviewShale ShakerDegasserVacuum Degasser OperationHydrocyclone Operation



Centrifuge AgitatorPit Volume TotalizerCentrifugal PumpHopperJet Hopper

VOLUME FIVE

HOISTING EQUIPMENTOverview……………………………………………………………………………37

Function of Hoisting EquipmentHoisting System ComponentsHoisting System Operation

Crown Block……………………………………………………………………….38Crown Block Operation

Traveling Block & HookOverviewMotion (Heave) CompensatorMotion Compensator OperationCombination Hook-BlockSeparate Hook & Traveling BlockHook, Links & ElevatorElevatorTypes of ElevatorsHook Positioner & Swivel Lock AssemblyHydraulic Snubber

Drilling Line………………………………………………………………………..40Drilling LineReeving Drilling LineSupply (Storage) ReelWear Points on LineSlipping and Cutting Drilling LineDeadline Anchor

Drawworks…………………………………………………………………………41OverviewBraking SystemDisk Brake SystemElectrodynamic BrakeLatest DrawworksCrown Saver

VOLUME SIX



ROTATING EQUIPMENT, MAST & SUBSTRUCTURERotating Equipment………………………………………………………………43

OverviewKelly & Rotary Table……………………………………………………………...43

Kelly AssemblyKelly DetailRotary Table Operation Setting SlipsSwivel & Rotary HoseSwivel Operation

Top Drive (Power Swivel) ……………………………………………………….45OverviewTop Drive Advantages & DisadvantagesTop Drive Assembly

Mast & Derricks…………………………………………………………………..46OverviewMastHeight & CapacityStandsCrown Walkaround (Water Table)MonkeyboardStabbing Board

Substructure………………………………………………………………………47OverviewV-Door, Pipe Ramp & Catwalk

VOLUME SEVEN

PIPE HANDLING EQUIPMENTPipe Handling……………………………………………………………………..48

OverviewPipe Handling Operation………………………………………………………..48

Making a Connection with KellyMaking a Connection with a Top DriveTripping out with KellyTripping in with KellyTripping with Top Drive, 1Tripping with a Top Drive, 2Tripping with a Top Drive, 3

Slips & Elevator Systems……………………………………………………….50SlipsSafety Clamp on Drill CollarSlips & Spiders



ElevatorLifting SubElevator on Top Drive

Spinning & Torquing Devices…………………………………………………..52TongsMakeup CatheadBreakout CatheadHydraulic CatheadPower TongsSpinning WrenchKelly SpinnerIron Roughneck

Pipe Transfer………………………………………………………………………54Pipe Racking SystemRatholeMouseholeAir HoistPipe Transfer System

Controls for Equipment………………………………………………………….54Driller’s consoleWeight Indicator, Gauges, Controls

VOLUME EIGHT

CASING & CEMENTINGCasing & Cement…………………………………………………………………55

OverviewCasing SpecificationsRunning Casing

Casing String………………………………………………………………………55

OverviewProgressive Casing Strings…………………………………………………….56

Conductor CasingSurface CasingIntermediate Casing StringsProduction Casing StringsLiner Strings

Casing Accessories………………………………………………………………57OverviewGuide ShoeFloat Collar & ShoeCentralizersScratcher



Cementing………………………………………………………………………….59OverviewCasing PointConditioning the HoleRunning the CasingMixing the CementFinishing the Job

VOLUME NINE

WELL LOGGING, MUD LOGGING & DRILL STEM DESTINGWell Evaluation……………………………………………………………………60

OverviewMud Logging / Testing, 1………………………………………………………...60

Mud Logging & TestingMud Logging UnitRig MonitorsChromatographCore Plugging ApparatusFluoroscopeMicroscopeComputersVacuum Oven

Mud Logging / Testing, 2………………………………………………………..62Core Heat SealerAnalytical BalancePorosimeterGas AnalyzerX-Ray DiffractometerCentrifugeDry Sample TrayHCL TestingMud Logs

Well Logging………………………………………………………………………63OverviewBasic Logging OperationLogging UnitLogging Unit DetailsLogging ToolsElectric LogNuclear LogSonic LogOther Logs



Drill Stem Testing…………………………………………………………………64OverviewDST Tool ComponentsLowering DST ToolSealing the HoleWater CushionFluid FlowPressure ChartsReverse CirculatingRemoving DST Tool

VOLUME TEN

POWER SYSTEM & INSTRUMENTATIONPower System……………………………………………………………………..67

OverviewPrime MoversAC to DC Power SystemDC to DC Power SystemMechanical Power System

AC to DC Power System…………………………………………………………67

OverviewDiesel & AC GeneratorSCR Switch & Control GearDC MotorsAC Motors

DC to DC Power System…………………………………………………………69

OverviewDC MotorsAC Generator (Alternator)

Mechanical Drive Power…………………………………………………………70OverviewCompound Drive

Hydraulic & Pneumatic Power Systems………………………………………70

OverviewHydraulic ForceHydraulic Power PackPneumatically Powered EquipmentRig Air Compressor

Rig Instruments………………………………………………………………………..73



OverviewDriller’s ConsoleWeight IndicatorPump Rate GaugePump Pressure GaugeRotary TachometerRotary Torque GaugeTong Torque GaugeMud Return Flow Rate IndicatorMud Tank Level IndicatorTrip Tank Volume IndicatorDrilling RecorderH2S Instrumentation



VOLUME ONE

AN INTRODUCTION TO RIG TYPES AND BASIC DRILLING STRING COMPONENTS

RIG TYPES

Overview:

Drilling rigs like these bore or drill holes into the earth. Usually they drill to find oil or gas.

They work both on land and offshore. Some are big and some are relatively small. Big

rigs drill very deep holes, 20000 feet (ft), 3000 meters (m) or more; small rigs may only

drill to a few thousand ft or meters. People in the oil land describe groups of rigs into 6

basic types: Land, Jack up, Platform, Submersible, Semi-Submersible and Drill Ship.

A land rig drills on dry land. There is the most common rig. Light duty rigs drill holes from

3000-5000ft, or 1000-1500m; Medium duty rigs drill to depth ranging from about 4000-

10000ft or 12000-3000m; Heavy duty rigs drill holes from about 12000-16000ft deep or

3500-5000m; Ultra-heavy duty rigs drill holes from about 18000-25000ft or more (5500-

7500m or more).

Crew members can move land rigs on trucks, tractors, trailers, barges, helicopters, heavy

rolling gear, skids and in rare cases, on specialized air-pressurized equipment.

Small light duty rigs are pretty simple to move. Ultra-heavy land rigs can be difficult to

move.

Jack-Up

A Jack up rig, drills offshore wells. It has legs that support deck and hole. When

positioned over the drilling site, the bottom of the legs rest on the sea floor. Jack up rigs

can drill in water depth ranging from a few feet or meters up to more than 400ft, over 120

meters. Boats to a Jack Up rig to a location with its legs up. Once the rig up crew gets the

legs firmly positioned on the bottom of the ocean, they can adjust the level of the deck

and the hole-height.

Platform

A platform rig is a non-mobile offshore structure, that is once built, it never moves from

the drill site. Companies drill several wells from the platform. Platform rigs can be Tender-

Assisted Rig. The tender floats next to the rigid platform, which is firmly pent to the sea

floor. Many platform rigs do not have a tender; they’re so large that they’re self-contained.

Big platform rigs include the Steel-Jacket Platform, the Caisson Type, and the Concrete

Gravity Type.

In deep water, rig builders have to make platforms that yield to water and wind

movements. Two Compliant Platform Rigs are the Guyed-Tower and the Tension-Leg.

Submersible Rig

A submersible rig rests on the sea floor when it is drilling. Workers flood compartments

that cause the rig to submerge and rest on the bottom. When ready to move, workers

remove the water from the compartments, this makes the rig float. Boats can then tow

the rig to the next site. Rig builders design submersibles to drill in shallow water and in



water up to about 175 ft deep, a little lower 50 meters.

Submersible drilling rigs include the Posted Barge Submersible, Bottle-Type

Submersible, and the Arctic Submersible.

Semi-Submersible

A Semi-Submersible rig is a floating offshore drilling rig. It has Pontoons and Columns.

When flooded with water, the Pontoons cause the unit to partially submerge to a

predetermined depth. The working equipment is assembled on deck. On the drill site,

workers can either anchor the rig to the sea floor or use a system of thrusters and

positioners to keep the rig over the hole. Here, they have it anchored. Crew members

mount the wellhead and blow-out preventers on the ocean floor. Special hollow pipe

called riser pipe connects the top of the blowout preventer to the rig.

In some cases, the crew uses thrusters to keep the rig over the hole, called Dynamic

Positioning. The thrusters, which are connected to an onboard computer, keep the rig in

position. Some Dynamically Positioned Semi-Submersibles can drill in water depths of

more than 7500ft, or over 2200 meters. When keeping a rig over the hole, drilling crews

use the term “On-Station”. Here is a semi-submersible rig loaded on a special carrier.

The carrier thus allows moving the rig far distance over the ocean. For shorter moves,

the rig owner tows the rig to the drill site, or, some semi-submersibles are self-propelled.

Drill Ship

A drill ship is a self-propelled floating offshore drilling unit. It usually uses a sub sea

blowout control system similar to the one on the semi-submersible.

KELLY & TOP DRIVES

Making a Hole

Many pieces of equipment make up a rotary drilling rig. Part of it is on surface and part of

it is underground, or subsurface. All the equipment has one main purpose: to put a bit at

the bottom of the hole, or it can drill or make hole. To put the bit on the bottom, rig crew

members screw it into a special pipe. The pipe is called the “Drill String”. Crew members

lower the drill string and attach a bit into the hole. For the bit to drill, surface rig

equipment has to rotate it, unless it is rotated by a mud motor. Equipment also has to put

weight on it to force the bit’s teeth, or cutters into the formation. As the bit rotates, a

circulating fluid has to take the drill cuttings away from the bit, otherwise, the hole will

clog up. The fluid which circulates is called drilling mud.

Overview

To impart rotary motion to the drill string so that the bit can turn, either a top drive or a

Kelly & rotary table system is used. Power is transferred from the surface down hole, via

the drill string.

Top Drive Systems

Some rigs rotate the drill string with a top drive unit. Top drives are expensive but very



efficient. Crew members can add drill pipe and joints to the drill string very quickly and

safely and they can drill the well more efficiently with less chance of sticking the drill

string in the hole as compared with the Kelly & rotary table. A powerful motor turns the

drive shaft which is connected to the top drive. Crew members make up or attach the drill

string to the drive shaft. The drive shaft turns the drill string and bit. Notice that the drill

string go through an opening in the rotary table, the table does not, however, rotate.

Top Drive Operation

A link system suspends the top drive unit from the rig’s traveling block. Drill mud enters

the unit through the gooseneck to the rotary hose, a flexible line that conducts drilling

mud from the pump. A motor and a gear box power the main drive shaft; the crew makes

up the drill string to the drive shaft. The built-in inside blowout preventers, IBOP or safety

valve keeps fluids from back flowing up the drill string when the driller closes it. The crew

uses the Torque Wrench assembly to make up and break out (connect & disconnect) the

drill string. The elevator links suspend the elevator; the rig crew latches the elevator

around the drill string to allow the top drive unit to lift it up or down.

Kelly Systems

A Kelly, a Kelly Drive Bushing, a Master Bushing and a Rotary Table rotate the drill string

and bit on some rigs. The Kelly is a heavy tubular device; it usually has either 4 or 6

sides, that is it either has a square or hexagonal cross section. Square kellys are less

expensive than hexagonal ones, but the hex kellys are stronger. So rigs drilling deep

holes often use them. Whether four or six-sided, crew members attach or make up the

Kelly to the top joint of pipe in the drill string.

Kelly Operation

The Kelly, four-sided or square as an example, moves through a square opening in the

Kelly drive bushing. The Kelly drive bushing meets with the master bushing, which the

rotary table turns. This rotates the entire drill string and attached bit. The Kelly moves

down as the hole deepens.

DRILL STRING COMPONENTS

Overview

There’re many components which make up the drill string as shown in this graphic.

Drill Pipe

Drill pipe is strong but relatively light weight pipe. Crew members attach it to a top drive

or Kelly. Drill pipe forms the upper part of the drill string. Usually the drill pipe rotates,

which also rotates the bit. Each section of pipe is called a joint. Crew members screw

together or make up several joints and put them into the hole as the bit drills. Drill pipe as

well as other tubulars can be specified according to these characteristics: Diameter,

Grades or Strength, Weight of steel, Length. The diameter, weight and strength used

depends on the size of the hole, the depth of the well and the well properties. Here is a



typical oil field tally book, many of these have sections in them which show standard drill

pipe specifications.

DP Spec

Drill pipe comes in three ranges of length: range one is 18-22 ft or 5.5-6.7 m; range two is

27-30 ft, or 8.2-9.1 m; and range three is 38-45 ft, or 11.6-13.7m. The most common

length is range two, 27-30 ft, or 8.2-9.1 m. Since a hole may be thousands of ft deep,

crew members may connect together hundreds of joints of pipe.

Drill pipe diameter can be as small as 23/8 inches or 60.3 mm. This size weighs 4.85

pounds per foot or 7.22 kg per meter. It can be as large as 65/8 inches, or 168.3 mm. This

pipe weighs about 27.70 pounds per foot or 41.21 kg per meter. However, 5 in (127mm)

drill pipe is one of the more common sizes. It weighs 191/2 pounds per foot or 29.01 kg

per meter.

Normal drill pipe grades are E75, X95, G105 and S135. S135 is the strongest.

Box & Pin

The rig crew makes up or connects drill pipe using threaded sections at each end of the

drill pipe. These threaded sections are tool joints. The female tool joint is the box end at

the drill pipe; the male tool joint is the pin end. Tool joints come in several sizes and

types.

Drill Pipe Make Up

Tool joints threads are rugged because the crew makes them up and breaks them out

over and over during the drilling process. But they have to take care not to damage them.

Proper care and handling of drill pipe and other oil field tubulars can prevent corrosion

later on the life of the well.

Heavy Walled Drill Pipe (HWDP)

Crew members make up a heavy walled drill pipe in the drill string below the drill pipe.

HWDP (often called heavy weight drill pipe) is made up between the drill pipe and drill

collars. HWDP is used to provide a transition between the limber drill pipe and the drill

collars, which are quite stiff. They use a HWDP reduces the stress that stiff drill collars

put on the drill string, as a result, HWDP reduces fatigue on the regular drill pipe. It also

helps keep the drill pipe in tension and may sometimes provide weight on the bit, just as

drill collars do, especially in directional drilling. Heavy walled DP (or Heavy weight DP)

has thicker walls and longer tool joints than standard DP. The longer tool joints reduce

wear on the pipe’s body. They keep the body away from the side of the hole. The wear

pad also prevents wear; it keeps the middle of the pipe’s body away from the side of the

hole.

Spiral HWDP

Spiral HWDP is another type of HWDP. Spiral HWDP has a spiral groove in the pipe’s

body. Regular HWDP has no groove, but spiral HWDP has no wear pad. When spiral

HWDP contacts the side of the hole, only a small part of the pipe body actually touches it.



In fact, only the part of the pipe body between the spiral grooves touches it. The groove

doesn’t touch the wall of the hole, thus reducing the surface contact area. Reducing the

surface contact area helps prevent the pipe from sticking.

Drill Collars (DC)

Crew members make up drill collars at the bottom of the drill string. Drill collars have

thick walls and are very heavy. They put weight on the bit to make the bit’s cutters bite

into the rock and drill. Drill collars range in diameter from 3-12 inches (or 76.2-304.8)

mm; they range in weight from about 650-11500pounds (or 300-5100kg). This particular 6

inch drill collar weighs about 2700 pounds (1225kg). Since the crew usually installs

several DCs, you can see that a bit requires a lot of weight to drill properly.

How much weight depends on the type of formation and the size and type of bit, where it

can be several thousand of pounds. DCs are normally 30-31 ft (9.4-9.5m) long and have

a threaded female connection at on end and a treaded male connection at the other end.

It is an interesting observation that in the drilling business tubular equipment diameters

and hole-diameters are almost always measured in inches but lengths are usu.

measured in meters or ft.

[TOOL BOX]: Let’s see how well you’ve been paying attention. In the section on drill pipe,

we told you what the names of the male and female connections record on oil field

terminology. Using the mouse, label the photo of the drill collar and then press “accept” to

see if you’re right.

Slick & Spiral DCs

[TOOL BOX]: Some DCs are slick. They have a smooth wall; some have spiral groove

machined into the wall. The rig uses slick collars under normal circumstances. The rig

uses spiral collars when drilling in formations where the collars may stick to the wall of

the hole.

Large diameter collars are fairly close to the diameter of the well bore. Under certain

circumstances, they can contact the wall of the well bore and get stuck. The spiral in the

DC helps prevent the DC from sticking to the wall by reducing its contact area.

Crossover Subs

Crossover subs go on the drill string between the DP & DCs and other points. A

crossover sub has a special box and pin threads. Manufacturers design them to join parts

of the drill string that have different thread designs. For example, a drill pipe’s pin may not

screw directly into a drill collar’s box so crew members make up a crossover sub in the

last joint of the DP where joins the first DC’s joint. The crossover sub’s box threads match

the DP’s pin threads and the crossover sub’s pin threads match the DC’s box threads.

These matching treads allow crew members to join the drill pipe string to the drill collar

string. Drilling rigs typically have a large variety of crossover subs.

Reamers & Stabilizers



Crew members often make up reamers and stabilizers in the drill collar string. Usually

they place one or more at various points on the drill collar string near the bottom.

Reamers and stabilizers hold the DC off the wall of the hole to prevent wear on the

collars, but even more important, reamers and stabilizers help guide the bit in the

direction that should drill.

Reamers have cutters on rollers that actually cut the rock they contact. Stabilizers have

blades that touch the wall of the hole but do not cut it.

Bottom Hole Assembly (BHA)

Notice the lower portion of the drill string. It includes the bit, DCs, stabilizers (or reamers),

and HWDP. Crew members call this part of the drill string the Bottom Hole Assembly or

BHA for short. They can make up many different BHAs, which one depends on the type

of formation, whether the rig is drilling straight or directional hole and so on.

Pipe Rack

The pipe rack is not part of the drill string but plays an important supporting role. The rig

crew cannot put drill pipe and collars on the ground or deck due to the debris will ruin

them. So they store them on the pipe rack. They also clean and inspect the drill string

and other tubulars or pipe on the rack.

DRILL BITS

Overview

As we discussed in the last section, crew members install the bit on the bottom drill collar.

Two kinds of bits are Roller Cone Bits and Fixed Cutter Bits. Fixed cutter bits are also

called fixed head bits. Roller cone bits usually have 3 cone-shaped devices with teeth or

cutters. As the bit rotates, the cone and cutters rotate to drill ahead. Fixed head bits also

have cutters, but manufacturers embedded them in the bit’s head. The bit’s head moves

only when the bit rotates. It has no moving parts like the cones on the roller cone bit.

Both roller cone bits and fixed head bits come in sizes ranging from only 2 or 3 inches (or

about 50-75mm) in diameter to more than 36 inches (about a meter) in diameter.

Roller Cone Bits

Two basic kinds of roller cone bits are available: one has steel teeth and the other has

tungsten carbide inserts.

Steel Tooth Bit

On a Steel Tooth Bit, also called a Milled Tooth Bit, the manufacturer mills or forges the

teeth out of the steel that makes up the cone. Steel tooth bits are the least expensive

bits. When used properly, they can make hole for many hours. Manufacturers design

steel tooth bits to drill soft, medium and hard formations.

Tungsten Carbide Bit

With tungsten carbide insert bits, the manufacturer presses very hard tungsten carbide



buttons or inserts into holes drilled into the bit’s cones. Tungsten carbide is a very hard

metal. Tungsten carbide insert bits cost more than steel tooth bits. However, they usually

last longer because tungsten carbide is more resistant to wear than steel. In general,

tungsten carbide insert bits drill medium to extremely hard formations, but can also drill

soft formations. Soft formation bits usually drill best with a mud of moderate weight and

high rotary speeds. Hard formation bits, on the other hand usually drill best with high

weight and moderate rotary speeds.

Fixed Cutter Bit

Three types of fixed cutter bits are available: Polycrystalline Diamond Compact (or PDC

bits), Diamond Bits and Core Bits.

PDC bit

This PDC bit has cutters made from man-made diamond crystals and tungsten carbide.

Each diamond and tungsten carbide cutter is called a compact. Manufacturers place the

compacts in the head of the bit. As the bit rotates over the rock, the compact shears it.

PDC bits are very expensive, however, when used properly, they can drill soft, medium or

hard formations for several hours without failing.

PDC Compact

A compact PDC layer is very strong and wear resistant. Manufacturers bond the diamond

crystals to the tungsten carbide backing under a high pressure and temperature. The

tungsten carbide backing gives the compact high impact strength; it also reinforces the

wear resistance properties of the cutters.

Diamond Bit

Manufacturers make diamond bits from industrial diamonds; the diamonds are the bit’s

cutters. Diamond is one of the hardest substances. A diamond bit breaks down the rock

during drilling by either compressing it, shearing it or grinding it as shown in this

ed i mation

Here, the diamond is acting like sand paper wearing the rock away. They embed the

diamonds into the metal matrix that makes up the head of the bit. Diamond bits are

expensive. When properly used, however, diamond bits can drill for many many hours

without failing.

Core Bit and Barrel

Crew members run a core bit in barrel when the geologist wants a core sample of the

formation being drilled. A core bit is normally a fixed head PDC or diamond bit. It has a

hole in the middle. This opening allows the bit to cut the core. Diamonds or PDC’s line

the opening and sides of the bit. The rig crew fix the core to a core barrel, the core barrel

is a special tube, usually about 30-90 ft (or 9-27 meters ) long. They run the core barrel at

the bottom of the drill string; it collects the core cut by the core bit. Cores allow geologists

to take a look at an actual sample of the formation rock. From the sample, they can often

tell whether the well will be productive.



SPECIAL DRILL STRING TOOLS

Overview

Special equipment of the drill string includes the drilling jars, measurement while drilling

(or MWD) tools and mud motors.

Drilling Jars

The rig crew installs a drilling jar in the drill string if there is a concern of becoming stuck.

Drilling jars are usually made up on the upper part of the bottom hole assembly with drill

collars placed above and below the jars. When activated, a drilling jar provides a heavy

blow to the stuck portion of the drilling string below the jar. Often the blow delivered by

the jar is enough to knock loose the stuck string.

Drilling Jar Operation

To create a jarring blow up with a hydraulic jar, the driller lowers the drill string to cock the

jar. Then the driller applies an upward pull. The upward pull puts the up jar in tension and

allows the jar trip mechanism to slowly bleed. Eventually, the jar trips when the hydraulic

oil bleeds past the ports. The drill string contracts, rapidly accelerating the bottom hole

assembly above the jars. When it reaches full stroke, the jar mechanism suddenly stops

the motion energy of the string. When the motion suddenly stops, it converts the kinetic

energy (or energy in motion) into impact force on the stuck point. This heavy upward

blow may free the stuck string below the jar.

MWD

Measurement while drilling—MWD tools are a big help to the driller as the bit drills. Crew

members usually place the tool in a special drill collar close to the bit. MWD tools send

down-hole conditions and transmit them to the surface. There, the driller monitors the

conditions in real time. Most MWD tools create pulses in the drilling mud; these pulses

carry the down-hole information up to drilling string to the surface. Information collected

by an MWD tool includes: Rock Properties, the Direction that the bit is drilling, Torque

and Weight on bit.

Mud Motor

Often, when drilling a directional or a horizontal well, a mud motor is made up at the

bottom of the drill string just above the bit as shown here. It’s called a mud motor

because drilling mud rotates the bit. That is, when using a mud motor, only the bit rotates,

not the rest of the drill string. Mud pumped down the drill string enters the top of the mud

motor when pressurized drilling fluid is forced between the elastic stator and the eccentric

steel rotor. A torque is applied which cause the rotor to rotate. The rotor is connected to a

drive shaft which is connected to the bit. Note that all the drill string does not rotate.

Directional Wells

Sometimes a well is drilled in an angle. This is called a directional well. The well is



steered in an angle specified in the drilling program for many different reasons.

For example, they may drill directionally sometimes if the oil or gas reservoir does not lie

directly under the rig site.

Horizontal Wells

Horizontal wells are drilled for many different reasons. Certain reservoirs can be

produced better if a horizontal portion of the well passes through the formation. The

transition to the horizontal segment of the well begins at some point in the vertical portion

of the well bore as shown here. This point is termed the “Kick-Off Point”. The horizontal

segment of the well can extend for several thousand ft. specialized drilling equipment and

techniques are required to drill horizontal wells.

VOLUME TWO BASIC BOP EQUIPMENT

PRESSURE CONTROL

Overview:

Fluids in the formation are under pressure. When drilled, this pressure can escape to the

surface if it is not controlled. Normally drilling mud offsets formation pressure, that is the

weight or pressure of the drilling mud keeps fluid in the formation from coming to the

surface. For several reasons however, the mud weight can become lighter than it ’s

necessary to offset the pressure in the formation. When this situation occurs, formation

fluids enter the hole. When formation fluids enter the hole, this is called a “kick”. A

blowout preventer stack is used to keep formation fluids from coming to the surface.

These are called “BOP”s. By closing a valve in this equipment, the rig crew can seal off

the hole. Sealing the hole prevents more formation fluids from entering the hole. With the

well sealed or shut in, the well is under control. Rig crews use a surface BOP system on

land rigs, jack-up rigs, submersible rigs and platform rigs. They use a subsea BOP

system on offshore floating rigs, like semi-submersibles and drill ships.

[TOOL BOX]: Why do you suppose subsea BOP system are used on semi-submersibles

and drill ships? Blowout prevention equipment is very large and very heavy. Semi-

submersibles and drill ships are dynamic, that is they float and thus move with wind &

waves while in working mode. On floating rigs, it is not practical to mount the BOP stack

on top of the long riser pipe. The BOP stack is much too heavy for the relatively thin and

flexible walls of the riser pipe. Also because the riser walls are relatively thin, they cannot

withstand the high pressures that could develop inside the riser when the well’s shut in

on a kick. So the rig crew mounts the BOP stack on the well head at the see floor and

makes up the riser on top of the stack.

Blowout

A blow out is dangerous. Formation fluids like gas and oil blow to the surface and burn.

Blow outs can injure or kill, destroy the rig, and harm the environment. Rig crews there

for trained and work hard to prevent blowouts. Usually they’re successful, so blowouts

are rare. But when they happen, they are spectacular and thus often make news.



Taking a Kick

A kick is the entry of formation fluids into the well bore while drilling. A kick occurs when

the pressure exerted by the drilling mud is less than the pressure in the formation that the

drill string is penetrating. The mud that circulates down the drill string and up the hole is

the first line of defence against kicks. Drilling mud creates additional pressure as it

circulates. The mud pressure keeps formation pressure from entering the well bore. On

the rig, they say mud keeps the well from kicking. Sometimes however, crew members

may accidentally allow the mud level or mud weight in the hole to drop, this drop in

weight or level can happen for several reasons.

For example, the crew may fail to keep the hole full of mud when they pull the pipe out of

it, or they may pull the pipe too fast, which can lower the bottom hole pressure. When the

mud level or mud weight drops, the pressure exerted on the formation decreases. If

either happens, formation fluids can enter the hole. If they do, the well takes a kick. In

other words, when the formation pressure exceeds the weight of the mud column, then

the well can kick.

[TOOL BOX]: Liquids and gases exert a force against the container. That is the liquid or

gas pushes against the wall of the container. If we measure the amount of push or force

being exerted on each unit of area on the container, we have the pressure of liquid or

gas. So pressure is defined as Force per Unit Area. Common units that are used to

measure pressure are Pounds per Square Inch and Kilopascals. This gauge shows the

down hole pressure of the mud column; this gauge shows the reservoir pressure.

Change the pressure of the mud column and see what happens. To keep a kick from

becoming a blowout, the rig crew uses blowout prevention equipment.

BLOWOUT PREVENTERS

Basic Concepts

The blowout preventer—BOP stack, consists of several large valves stacked on top of

each other. These large valves are called blowout preventers. Manufacturers rate BOP

stacks to work against pressure as low as two thousand pounds per square inch or 2000

psi, and as high as 15000psi, that’s about 14000 Kilopascals to over 100000 Kilopascals.

Rigs usually have two kinds of preventers. On top is annular preventer. It’s called an

annular preventer because it’s around the top of the wellbore in a shape of a ring or an

annulus. Below the annular preventer are ram preventers. The shown of valves in ram

preventers close by forcing or ramming themselves together.

The choke line is a line through which well fluids flow to the choke manifold when the

preventers are closed. Even though the preventers shut in the well, the crew must have a

way to remove or circulate the kick and mud out of the well.

When the BOP shut in the well, mud & formation fluids exert through the choke line to the

choke manifold. The manifold is made up of special piping and valves. The most

important valve is the choke. The choke is a valve that has an adjustable opening. Crew

members circulate the kick through the choke to keep back pressure on the well. Keeping



the right amount of back pressure prevents more kick fluids from entering the well. At the

same time, they can get the kick out of the well and put in heavier mud to kill the well.

That is regain control of it. The well fluids leave the choke manifold and usually to a mud

gas separator. A mud gas separator separates the mud from the gas in the kick. The

clean mud goes back to the tanks; the gas is flared or burned at a safe distance away.

BOP Operation

When the well takes a kick and the BOP is open, well fluids force mud to flow up the well

bore and into the BOP stack. When the driller closes the annular BOP, flow stops.

Usually, drillers close the annular BOP first. The closed annular BOP diverts the flow of

the choke line, which goes to the choke manifold. The driller can open a valve on the

choke line and safely circulate the kick out of the well through the choke manifold.

[TOOL BOX]: Here is an annular preventer, click on it to see how it works. An annular

BOP closes on drill pipe, drill collars or any shape of tubular in the well. It can also close

an open hole, a hole with no tubulars in it at all. It’s usually the first preventer used to

close in the well. Here are four types of Ram-Preventers: Pipe Rams, Blind Rams, Blind-

Shear Rams and Variable Bore Rams (VBR Ram). Click on each one to see how the

rams work.

Pipe Rams

Pipe rams are used when there is drill pipe in the BOP stack. The pipe rams fit around

the pipe, closing off the annulars. Pipe rams back up the annular preventer. That is then

it’s likely at the end the annular BOP failed, crew members could shut the pipe rams to

seal the well. Also some pipe ram preventers are used to hang off or suspend the drill

string and some subsea BOPs.

Blind Rams

Blind rams are designed to seal an open hole. If the annular BOP fails and there’s no

pipe in the hole, the crew could seal the hole by closing the blind rams.

Blind-Shear Rams

Blind-shear rams are designed with blades that cut through the drill pipe and then seal

the open hole. They’re used in extremely emergencies, like when an offshore floating rig

has to move off a well that they’re drilling because of a hurricane or other such

emergency. Blind shear rams allow them to cut the pipe, seal the hole and then move the

rig a safe distance away.

VBR Ram

Variable Bore Rams or VBR are special pipe rams that can close over a range of pipe

sizes such as 5 inch diameter to 3 inch diameter.

BASIC BOP EQUIPMENT



Overview

Here are the major parts of a land, jack-up, platform or submersible rig’s blowout

prevention equipment: the blowout preventer or BOP stack, the driller’s BOP control

panel, the BOP operating unit accumulator, the choke manifold, the choke control panel,

the mud gas separator, the flare line & flare pit, the trip tank and drill string valves.

[TOOL BOX]: Prompt quiz: You’ve just learned the names of the equipment used in well

control operations. Let’s see how well you can identify the equipment. Using the mouse,

drag the labels to their correct locations. When you’ve completed this exercise, click the

“accept” button.

Driller’s BOP Control

From this BOP control panel, the driller opens and closes or controls the blow out

preventers and the line to the choke manifold. Rig builders usually place the control panel

on the rig floor, close to the driller’s position. Lever and switches allow the driller to

quickly open and close the preventers and other valves in the system.

Accumulator

The accumulator bottles store or accumulate hydraulic fluid under very high pressure, up

to 3000 psi, over 20000 KPa. This high pressure fluid ensures that the preventers close

very fast. The BOP operating unit accumulator is installed some distance from the rig

floor.

Hydraulic Lines

When the driller activates the BOP operating unit, it pumps the hydraulic fluid through the

high pressure pipes of lines into the BOP stack. The hydraulic pressure opens or closes

the preventers.

Operating Lever on Accumulator

Usually, the driller operates the accumulator from a control panel on the rig floor. In an

emergency however, crew members can operate the BOPs by using the control valves

on the accumulator itself.

Choke Manifold / Chokes

Here is a choke manifold. Flow gets to it from the BOP stack via a choke line. The

manifold usually has two or more special valves that called chokes. Usually well flow

goes through only one of the chokes, the others are back ups or used under special

conditions.

Choke Operation

By adjusting the size of the opening in the choke, making the opening larger or smaller,

the driller adjust the amount of the flow through the choke. The smaller the opening, the

less flow; the larger the opening, the more flow. The less flow, the more back pressure on

the well; the more flow, the less back pressure on the well. This adjustment of back



pressure keeps the pressure on the bottom of the hole constant so that no more kick

fluids can enter the well.

Choke Control Panel

The driller or another crew member uses the choke control panel to adjust the size of the

choke’s opening as kick fluids flow through it. By watching the pressure on the drill pipe

and casing, and by keeping the mud pump at constant speed, the choke operator can

adjust the choke to keep the pressure on the bottom of the hole constant. The choke

operator must keep the bottom hole pressure constant to successfully control and

circulate a kick out of the hole.

[TOOL BOX]

Mud-Gas Separator

Often, kick fluids and mud from choke manifold go through a line to a mud gas separator.

Frequently, formation gas is the main part of a kick. However, kick fluids may also contain

water, oil, or combination of these fluids. In any case, the mud gas separator removes the

gas from the mud. With the gas removed, the pump circulates gas-free mud into the mud

tanks and back down the hole. The separated gas goes to a flare line.

Separator Operation

In the separator, mud with gas in it from choke manifold enters the top and falls over

several baffle plates. The gas breaks out of the mud as it falls over the baffle plates and

goes into the flare line. The gas-free mud falls to the bottom outlet where it goes to the

mud tanks for circulation down hole.

Flare Line & Flare Pit

The flare line conducts gas from the mud gas separator to a flare pit on land rigs. The

gas is burned or flared at the flare pit. Notice that the flare line outlet is a good distance

away from the rig floor, so even while gas is flaring, the crew can still safely work on the

rig floor.

Offshore, where there is no flare pit, the flare line conducts the gas over the side of the

rig. The line runs over the water, a safe distance away from the rig.

Trip Tank

A trip tank is a special mud tank. It is used when they pull drill string from the hole, for

example, to change out a dull bit. They also use the trip tank when they run drill string

back into the hole. Pulling the drill string and running it back in is called a “trip”, which is

why they call the small tank a “trip tank”. They use it to keep accurate track of how much

mud the drill string displaces in the hole.

Trip Tank Operation

When the crew pulls drill string from the hole, the mud level in the hole drops. If they let

the mud level drop too far, it won’t exert enough pressure to keep formation fluids from



entering the hole. So, as the crew pulls pipe, they continually circulate fluid from the trip

tank to replace the drill string and keep the hole full. They also watch for unusual

changes, and may make sure that the volume of mud they put in exactly replaces the

volume occupied by the drill string. Since the volumes are small, the level of mud in the

trip tank is calibrated in small increments, such as stands of pipe, or barrels or liters of

mud, or both. If the volume they put in is less than the volume occupied by the drill string

they removed, then it’s likely that formation fluids have entered the hole. For example,

let’s say the crew pulls one stand of drill pipe. In this instance, the stand displaces .7

barrels or 111 liters. There for, they should pump .7 barrels or 111 liters of mud to replace

the stand. The mud level in the trip tank should sure drop .7 barrels or 111 liters. If the

level in the tank shows less, then formation fluids have entered the hole and the crew

must take steps to control the well.

SUBSEA BOP EQUIPMENT

Overview

Subsea BOP equipment is similar to a surface stack. There are, however, some very

important differences. This section discusses these differences.

Subsea stacks attach to the wellhead on the sea floor. Meanwhile, the rig floats on the

water, hundreds or thousands of ft or meters above. Major parts include: the Subsea

BOP stack, this is a lot like a surface BOP stack; other parts are different, however.

Here’s the flexible or ball joint.

The marine riser with a choke line and a kill line, guide lines, the telescopic joint with riser

tensioners, the hose bundle, and two control pods. The driller controls the subsea BOP

valves from electric BOP control panel on the rig. The subsea hose bundle carries the

control signals and hydraulic fluid from the rig down to the control pod and selected

subsea BOP valves.

Marine Riser System

Marine riser pipe is special pipe and fittings. It seals between the top of the subsea BOP

stack and the drilling equipment located on the floating rig. Crew members run the drill

string into the hole inside the riser pipe. The riser pipe also conducts drilling fluid up to

the rig. Manufacturers attach two smaller pipes called the choke and kill lines to the

outside. Crew members use them to control the well during a kick or special operations.

Guide lines guide and help position equipment such as the BOP stack to ocean floor. The

flexible joint cuts down on bending stresses on the riser pipe and BOP. The telescopic

joint compensates for the vertical motion of the floating rig.

Riser & Guideline Tensioner

Crew members also attach the riser tensioning system to it. Riser tensioner lines support

the long riser pipe. The riser and guide line tensioners put constant tension on the riser

pipe and guide lines. This tension suspends the riser pipe. It also compensates what the

movement of the rig caused by wave action. Riser tensioner systems usually range in

capacity from over 300,000 to almost 1,000,000 pounds (that is 135,000 to over 450,000



kg) with 50 ft or 15 meters of wire line travel. They utilize up to 12 compression loaded

tensioners that use air pressure for compensation.

DRILL STRING VALVES & IBOPS

Overview

Drill string valves stop fluids from flowing up to drill string. Often, if the well kicks with the

bit off bottom, formation fluids flow up the annulus, and up the drill string. Crew members

close the drill string valves to stop the flow in the string. If the kelly is made up, they can

close the upper or lower kelly cock. If the kelly is not made up, then they can install a full

opening safety valve on the top of the drill string.

An inside blowout preventer or IBOP is a one-way valve, a check valve they can install in

the drill string. One side of the IBOP is a float valve that is sometimes made up in the drill

string near the bit. It prevents back flow up the drill string. Another type of IBOP is the

Drop-in valve or DIV. It’s dropped into the drill string and falls to a special landing sub

that’s usually located near the top drill collar and drill stem. It allows the driller to pump

mud down the string. But the check valve won’t allow influx fluid to flow up the string.

Another type of the inside BOP is the Heavy Duty Check Valve or Gray Type Valve after

one company that makes it. It’s a plunger check valve that the crew stab it in the drill pipe

at the surface. It’s usually used during stripping operations. Stripping is when the cerw

lowers the pipe in the hole while the BOPs are closed & under pressure.

Upper / Lower Kelly Cocks

An upper kelly cock is located above the kelly. The upper kelly cock normally surves as a

back up to the lower kelly cock. If the lower kelly cock failed, crew members will use a

special operating wrench to close the upper kelly cock. The closed upper kelly cock

prevents further flow, it protects the equipment above the kelly from high pressure flow.

Usually crew members close the lower kelly cock if a kick puts risk on the equipment

above the kelly. They make it up at the bottom of the kelly. A crew member uses a special

operating wrench to close it. The crew can also close the lower kelly cock to keep mud

from falling out of the kelly when they break out the kelly to make a connection. A cock is

another name for a valve. Cock is short for weathercock, which is English term for valve.

Full-Opening Safety Valve

Here is a full-opening safety valve. If the kelly is not made up in the drill string and flow

occurs. Crew members can insert the safety valve in the drill string. This procedure is

called “stabbing”. A full-opening valve has as large an inside opening as possible. When

fully open, flow from the frill pipe passes through the valve with no additional restriction.

This relatively large opening allows the crew to stab the valve against pressure coming

out of the drill string.

Safety Valve Usage

The crew picks up the safety valve by its lifting handles. They make sure it’s fully open

and stab it into the drill pipe. Then they screw it into the pipe. Finally they use a special



operating wrench to close the valve and shut off flow. Driller should make sure the rig has

the right crossover subs at hand on the rig floor. Crew members should be able to make

up the safety valves and any drilling string member coming out of the rotary. For

example, if a drill collar is in the rotary, the safety valve’s threads may not match the drill

collar’s threads. They will need the right crossover sub to make it work.

[TOOL BOX]: This well is taking a kick. To shut it in, choose one of the two valves you

see here: a one-way safety valve and a full-opening safety valve. Click on the valve you

wan to use. Hold your mouse button down and drag the valve to drill pipe… Good choice!

The full-opening safety valve is the correct valve to use in this situation. It can be stabbed

on the drill pipe while it’s open and then close to shut in the drill string. You’re not done

yet though, the annulus hasn’t been sealed, so the well is still not fully secured. Click on

the correct preventer on this BOP stack that should be closed first. That’s right! The

annular preventer is closed first. Good job! You’ve successfully closed in this well.

Float Valves

Float valves also prevent flow up the drill string. Crew members place a float valve in a

sub, a special drill string fitting, just above the bit. One type allows mud to be pumped

down but shut against upward flow. Under normal conditions, pump pressure moves

drilling mud through the open one-way valve, and influx of formation fluids from below

causes the float valve to close. This prevents further flow up the drill string.

VOLUME THREE INTRODUCTION TO DRILLING CLUIDS

OVERVIEW

Drilling fluid or drilling mud as many people call it is a vitality in a rotary drilling process.

The term “drilling fluid” includes air, gas, water and mud. “Mud” refers to the liquid that

contains solids and water or oil. The mud is made up with clay and other additives that

give it desirable properties.

MUD TYPES

Water Based Mud

Often, water is the base of drilling mud. Water makes up the liquid part or phase of a

water-based mud. Crew members put clay and special additives into the water to make a

mud with the properties needed to do its job well. For example, clays give it thickness or

viscosity. The water in the mud may be fresh water, sea water or concentrated brine (salt

water). The one used depends on its availability and whether it gives the mud the needed

properties to drill the hole efficiently.

Oil Mud

At times, down hole drilling conditions require the crew to add oil to the mud, or in some

cases, crew members use oil instead of water as the base of the mud. This is called oil-

based mud. Oil based mud has many advantages. It can stabilize the formation and



reduce downhole drilling problems. However, it is harder for the crew to work with

because it can create slippery conditions and environmental precautions must be used.

From an environmental standpoint, mud with oil is more difficult to handle because the oil

clings to the drill cuttings. The oil must be cleaned off the cuttings before they’re disposed

of.

Drilling with Air

Sometimes drilling fluid is dry air or natural gas. Here, dry air is coming out of the rig’s

Blooey Line, carrying very fine drilled cuttings. Air drilling uses very large air compressors

instead of mud pumps. Drilling with air or gas can prevent formation damage and can

overcome severe lost circulation problems. And it allows the bit to drill very fast. Down

hole conditions have to be just right for air or gas to be usable. For example, the bit

cannot drill through formations containing large amounts of water. The water mixes with

the cuttings and the air or gas and clogs up the hole.

Foam Drilling

If small amounts of water are present in the formations being drilled, special equipment

can inject a foam agent into the air stream. The foam helps separate the cuttings and

remove water from a hole.

Aerated Drilling

In some cases, the rig operator may use aerated mud, which like foam drilling, helps

prevent clogging of the well bore. Aerated drilling uses both mud and air pumped into the

standpipe at the same time.

DRILLING FLUID FUNCTION

Overview

When circulated down the drill string and up the hole, drilling mud serves many functions.

For example, mud cleans the hole, cools and lubricates the bit & the drill string, lifts

cuttings to the surface, carries information about formations being drilled, stabilizes the

well bore, controls formation pressure and suspends cuttings when pumping stops.

Cleaning the Hole

One function of mud is to clean the hole. A clean hole allows the bit to drill into uncut

formation rock. Here is an example of what can happen when cuttings are not moved off

bottom. Mud jets out of the bit and moves cuttings away from the bottom of the hole. The

mud then carries the cuttings up the annulus and to the surface for disposal.

Cooling / Lubrication

Heat is encountered down hole. Deep formations can be very hot and friction from

rotating drilling components generates a lot of heat. High temperatures increase drill

string and bit wear. Drilling fluid helps to reduce the temperature in the drill string down

hole while drilling. In addition, drilling fluid provides lubrication to the drill string and bit



that helps prevent wear.

Protecting Wellbore Walls

Mud stabilizes the hole, keeps it from caving in. As mud moves up the hole, it usually

flows by permeable formations. Permeable formations although allow the fluid to flow,

when the mud is next to a permeable formation, pressure forces the liquid part of the

mud, the filtrate, into tiny openings or pore spaces in the formation. This leaves behind a

thin sheet of solid particles, known as mud cake. These solids plaster the side of the

hole, much like the plaster on the wall of a building. The wall cake helps keep the well

from caving in.

Controlling Formation Pressure

The column of mud in the well creates pressure down hole, called hydrostatic pressure.

The hydrostatic pressure of the mud column offsets formation pressure. Mud is the first

line of defence in well control. As long as the hole is full of mud, that is the right weight,

the well cannot kick and perhaps blowout. A kick is the entry of formation fluids into the

well bore. The kick forces drilling mud out of the hole. If crew members fail to control a

kick, a blowout can occur. A blowout is the uncontrolled flow of drilling mud and formation

fluids out of the hole.

Obtaining Downhole Information

Mud is also used to obtain information about formations down hole. Mud loggers, by

examining cuttings at the surface, can gather important information about the formation

being drilled and the conditions down hole.

MUD PROPERTIES & ADDITIVES

Bentonite

In water, or oil based drilling mud, crew members usually add clay, called bentonite, or

similar mineral. Bentonite swells in water, therefore thickens the mud, gives viscosity, to

help clean the cuttings from the hole and provide other desirable properties.

[TOOL BOX]: Viscous fluids are more resistant to flow. Honey is a good example of a

viscous fluid, pure water is not viscous.

Barite

Barite is a heavy mineral. The crew adds barite to mud to make it heavy or dense. Barite

is over four times heavier than water. Dense mud exerts more pressure than light mud.

Weighted mud controls formation pressure. This is called “Primary Well Control”.

[TOOL BOX]: Primary well control is using the density or weight of the drill fluid to provide

sufficient pressure to prevent the influx of formation fluid into the well bore. If sufficient

mud pressure is not used while drilling, the pressurized formation fluid forces the mud up

the well bore where it blows out of control. When the hole is full of mud that weighs the



right amount, the pressure of the mud equalizes the pressure of the formation, so

formation fluids can’t enter the well bore.

PH

The control of many mud properties depends on its PH. The PH of mud is a measure of

its acidity or alkalinity. The PH scale runs from 0 to 14. If the mud is neutral, neither acidic

nor alkaline, it has a PH of 7. Mud with a PH below 7 is acidic, a PH above 7 shows that

the mud is alkaline. Most drilling muds require a high PH, at least 9, or higher.

[TOOL BOX]: Prompt quiz: We’ve said that most drilling mud should have a PH of 9 or

greater. Will the mud be called acidic or alkaline?

Caustic Soda

Because mud needs to have a high PH, another common mud additive is Caustic Soda

or Sodium Hydroxide. Caustic soda is often called “caustic”. Crew members add caustic

soda to the mud to control PH. Caustic soda increases the PH value, it makes the mud

more alkaline. In general, caustics are the most dangerous chemicals that you’ll handle

on the rig. High strength solutions can seriously burn your skin. Be very careful when

handling it to avoid injury, wear the proper personal protective equipment, also remember

to always add caustic soda to water, never add water to caustic soda. If you do, the

caustic soda will boil up, splatter and cover you with a burning chemical.

Gelled Mud

When drilling stops, say let the crew make a connection (add a joint of drill pipe to the

string), the driller normally stops pumping mud. When pumping stops, the mud stops

moving. At rest, mud gels, that is it becomes a semi-solid like gelatin. Gelled mud

suspends the cuttings. Gelling keeps the cuttings from falling down hole and piling up

around the bit. The ability of a gel to keep the cuttings suspended is measured by its gel

strength. When the driller starts the pump and resumes mud’s circulation, the mud’s gel

strength reduces, which allows the drilling fluid to flow easier.

MUD TESTS

Overview

We’ve just covered a few key points about mud additives and the properties that mud

should have to allow a successful drilling. On the rig, it is important for crew members to

constantly monitor and maintain these properties. An important member of the drilling

team is the mud engineer. The mud engineer runs tests on the drilling fluid. The mud

engineer’s job is to monitor and maintain the mud’s properties to the specifications of the

well operator. He may also recommend changes to improve drilling, such as adding more

caustic soda to increase the mud’s PH. In this section, we will learn about tools that’re

used to monitor mud properties.

Mud Balance



The density, or weight per unit volume of the drilling mud determines how much

hydrostatic pressure the mud column exerts on the formation. It is therefore important to

know the mud’s density at all times. To determine mud density, the mud engineer or

helper uses a mud balance. The person weighing the mud puts a small amount of mud in

the mud container at left on the balance. He then slides the adjustable counterweight to

the right or left until the arm balances on the fork room. The person then reads the mud

density at the point on the arm next to the counterweight. In many areas, mud density is

read in pounds per gallon but can also be reported in pounds per cubic foot, milligrams

per liter, and other units. Mud density is usually called mud weight by the rig crew.

[TOOL BOX]: Calculate the density of mud by adjusting the counterweight on the mud

balance. Click on the correct density when you’ve finished.

Marsh Funnel

The viscosity of the mud is thickness or resistance to flow, is also an important factor.

The mud’s viscosity determines how well it can carry cuttings up the hole. One measure

of a mud’s viscosity is its funnel viscosity. That is how many seconds does it take exactly

one quart of mud to flow out of a special funnel called a Marsh Funnel. A Marsh Funnel

has a hole in the bottom that’s the standard size. The mud engineer or helper pours one

quart of mud into the funnel and records the time that it takes to run out into a pitcher or

beaker. In this example, one quart of mud flows out of the funnel and into the beaker in

35 sec, so this mud has a funnel viscosity of 35 sec. A less viscous or thinner mud would

flow through the funnel faster; a more viscous or thicker mud would flow through the

funnel slower.

Rotational Viscometer

This device also measures mud’s viscosity. It is a more scientific viscosity measure than

the Marsh Funnel. A Fann V-G Meter measures the mud’s viscosity in centipoises. A

centipoise is a unit of measure for viscosity, just as an inch is a unit of measure for

length. The Fann V-G Meter works by spinning a rotor or bob in a sample of mud at two

different speeds. In addition, a Fann V-G Meter is used to determine a mud’s yield point,

which is a measure of the mud’s resistance to flow. Combined with a timer, the Meter

also measures the mud’s gel strength. Gel strength is the mud’s ability to temporarily

solidify or gel when it’s not flowing.

[TOOL BOX]: Here’s a mud with high gel strength. Click the button labeled “lower gel

strength” to see what would happen if the gel strength wasn’t this high.

Filter Press

This is a Filter Press. Inside the white container is a piece of porous paper called filter

paper. Also inside the container is a mud sample. The mud engineer puts the mud

sample under 100 pounds per square inch of pressure for 30 minutes. The pressure

forces the liquid part of the mud, the filtrate, through the filter paper and into the

graduated cylinder. By measuring the amount of the filtrate, the mud engineer can get an



indication of the amount of filtrate that will be lost to down hole formations and the

amount of solids or wall cake build up on the wall of the hole.

Chloride Test

Mud engineers may run other drilling mud tests. One common test is for salt or chloride

in the mud filtrate. By adding Potassium Chromate and other chemicals, the engineer can

determine if the hole has penetrated a salt formation. It can also determine whether salt

water has entered the well bore, which may be a sign of a kick.

VOLUME FOUR MUD CIRCULATION & TREATING EQUIPMENT

MUD SYSTEM OVERVIEW

Overview

The rig uses many pieces of equipment to circulate and treat or condition the mud.

Mud Tanks

Mud circulation begins here, in the mud tanks, sometimes called pits. Crew members

prepare the mud in these tanks and make it ready for circulation

Mud Pumps

The heart of the circulating system is the mud pump. Often, rigs have two pumps, one

primary pump and one for back up. Or, if hole conditions required, the driller can

compound or combine the two pumps to circulate large volumes of mud. In fact, on deep

wells, the rig may have three or four compound pumps. The powerful pump, or pumps,

pick up mud from the mud tanks and send it to the drill string and bit. The pump moves

the mud into the discharge line, up to standpipe and into the rotary hose.

Standpipe & Rotary Hose

The standpipe takes the mud about half way of the mast. The rotary hose is attached to

the standpipe. The rotary hose is strong, flexible hose that moves with the swivel as it

goes up and down in the mast. From the rotary hose, the pump moves mud through the

swivel and then down the kelly and drill string. On rigs with a top drive, the mud moves

through a passage in the top drive and then into the drill string.

Bit & Annulus

The pump moves the mud down the drill string to the bit. At the bit, the mud jets out of

the openings or nozzles in the bit. The jets of mud move cuttings away from the bit. Mud

then continues up the annulus, carrying the cuttings with it.

Return Line, Shaker & Mud tanks

From the annulus, the mud with the cuttings in it goes through the return line, sometimes

called the Flow Line, to the shale shaker. The shale shaker removes the cuttings from the

mud. The mud then falls into the mud tanks, where the mud pump can pick it up and

continue the circulation process.



[TOOL BOX]: Arrange this circulating equipment in proper order, place the mouse around

the component, click and hold on it and move it to its proper position. The mud pump is in

position, what comes next?

MUD STORAGE, TANKS & RESERVE PIT

Overview:

Mud is made up at the rig location. Most rigs have several steel mud tanks. Mud and

additives are mixed and held in the tanks. Some land rigs also have a reserve pit dug out

of the ground. Mud tanks are also called mud pits, a carrier over from the days of earthen

pits, mud tank is the preferred term. The rig does not necessarily use all the mud tanks at

once, although it does use several. The active tanks hold mud the pump actively

circulates.

Mud House

Often, mud components come to the rig in sacks. Normally, the crew stores the sacks in

a special compartment called the mud house or sack room. The house or room keeps the

sacks dry and allows them to be stored with care.

Bulk Tank

These silo-like tanks are bulk tanks or P-tanks. They hold mud additives like barite and

bentonite. Crew members use some additives in such large quantities that suppliers load

them into the bulk tanks to save time and money. Bulk tanks usually have their own

hopper or pneumatic system for transferring the additives to the mud system.

Active Tank

The pump takes the mud out of the active mud tanks and circulates it through the

system. Crew members connect the mud tanks with the piping and manifold. The number

of active mud tanks depends on the amount of mud needed to keep the hole full, and the

volume required on the surface to keep the mud in good condition for circulating.

Sand Trap

The sand trap is the tank directly below the shale shaker. The shale shaker removes

most of the cuttings from the mud, but some are so small the shaker cannot trap them.

These fall into the sand trap. The sand trap is the first settling tank. Crew members have

to clean it regularly to remove the built-up solids.

Settling Tanks

Some small or old rigs may have two or more settling tanks in the tank system. They

allow solids in the mud to settle out, but settling tanks do not do a very good job as

compared with newer generation solids-removal equipment. So, today, most rigs use a

dessander and desilter.

Reserve Tanks



Reserve tank is not a part of the active mud tank system, instead, the crew uses them to

hold excess mud, or they may use them to mix a different type of mud in the pump’s

currently circulating. They may also store heavy mud for emergency well control

operations.

Slug Tank

A slug tank is a relatively small separate tank, or it may be a small separate part of a

larger tank. The crew uses the slug tank to mix a slug. A slug is a small amount of heavy

mud that is pumped down the string. Crew members may also use the slug tank to mix a

small amount of mud for a special purpose. For example, the driller may need place or

spot a small quantity of high viscosity mud, also called a pill, at some point down hole.

Suction Tank

The suction tank is where the mud pump picks up mud ready to circulate down hole. Mud

in the suction tank should be clean, free of solids & gas, and be properly formulated or

conditioned.

Chemical Tank

Crew members use the chemical tank to make special chemicals, such as caustic, that

they will put into the active mud tanks.

Reserve Pit

On some land rigs, the rig owner digs a large pit next to the rig. This pit is called the

reserve pit. The crew puts waste mud and run-off from the rig site in the reserve pit. In an

emergency, they can also use it as a place to put more mud than the tanks can hold.

Often, the rig operator lines the reserve pit with a thick plastic sheet to prevent liquids

from leaching into the soil. And if the rig is on a migratory bird fly way, the operator

covers it with a netting to keep the waterfowl from landing in it. Land rigs drilling in

environmentally sensitive areas will not have a reserve pit. Instead, waste & run-off of a

hole to an approved waste disposal area.

[TOOL BOX]: Here is your chance to be the driller’s assistant and carry out task to keep

the mud system operating properly. For each task the driller gives you, click the location

where the task will be carried out. When you select the right location, you’ll get your next

instructions. See if you can carry out all five tasks before the timer runs out. Click “begin”

when you’re ready to start.

MUD PUMPS

Over View

Powerful mud pumps pick up mud from the suction tank, and circulate the mud down

hole, out the bit, and back to the surface. Although rigs usually have two mud pumps,

and some times three of four, normally they use only one at a time. The others are mainly

used as back up in case one fails. Sometimes however, the rig crew may compound the

pumps. That is, they may use two, three or four pumps at the same time to move large



volumes of mud when required. Rigs use one of two types of mud pumps: triplex pumps

or duplex plumps. Triplex pumps have three pistons that move back & forth in liners;

Duplex pumps have two pistons that move back & forth in liners. Triplex has many

advantages: they weigh 30% less than a duplex of equal horsepower or kilowatts; the

lighter-weighted parts are easier to handle, and therefore easier to maintain. The other

advantages include: they cost less to operate, their fluid end is more accessible, and they

discharge mud more smoothly, that is the triplex’s output does not surge as much as

duplex. One of the most important advantages of triplex over duplex pumps is that they

can move large volumes of mud at the higher pressure required for modern deep hole

drilling. Triplex pumps are gradually phasing out duplex units.

Triplex Pump

In a triplex pump, the pistons discharge mud only when they move forward in the liner.

Then when they move back, they draw in mud on the same side of the piston. Because

of this, they’re also called “single-acting”. Single-acting triplex pumps pump mud at

relatively high speeds. Input horsepower ranges from 220 to 2200 (from 164-1641 KW);

large pumps can pump over 1100 gallons per minute (over 4000 liters per minute). Some

big pumps have a maximum rated working pressure of over 7000 psi (over 50000KPa)

with 5 inch (137 mm) liners.

Triplex Pump Operation

Here’s a schematic of a triplex pump. It has 3 pistons, each moving in its own liner. It also

has 3 intake valves and 3 discharge valves. It also has a pulsation dampener in the

discharge line. Look at the piston at left, it has just completed pushing mud out of the

liner and through the open discharge valve. The piston is at its maximum point of forward

travel; the other two pistons are at the other positions in their travel, also pumping mud.

But right now, concentrate on the left one to understand how the pump works.

The left piston has completed its back stroke, drawing in mud through the open intake

valve. As the piston moved back, it lifted the intake valve off its seat and drew mud in, a

strong spring holds the discharge valve closed. The left piston has moved forward,

pushing mud out through the now open discharge valve, a strong spring holds the intake

valve closed. The left piston has completed its forward stroke, the full length of the liner,

completely discharging the mud from it. All three pistons work together to keep a

continuous flow of mud coming into and out of the pump. Crew member can change the

liners and pistons, not only can they replace worn-out ones, but they can also install

different sizes. Generally they use large liners and pistons when the pump needs to

move large volumes of mud at relatively low pressure; they use small liners and pistons

when the pump needs to move smaller volumes of mud at relatively high pressure.

[TOOL BOX]: You can control the position of the piston with your mouse to see how the

triplex pump operates at any given point in this cycle.

Duplex Pump



In a duplex pump, the pistons discharge mud on one side of the piston and at the same

time, taking in mud on the other side. Notice the top piston and liner. As the piston moves

forward, it discharges mud on one side as it draws in mud on the other. Then, as it moves

back, it discharges mud on the opposite side and draws in mud on the side where it

earlier discharged. Duplex pumps are therefore double-acting. Double-acting pumps

move more mud on a single stroke than a triplex, however, because they’re double

acting, they have a seal around the piston rod. The seal keeps them from moving as fast

as triplex. Input horsepower ranges from 190 to 1790 (or from 142-1335KW). The largest

pump’s max. rated working pressure is about 5000psi (almost 35000KPa) with 6 inch

(152 mm) liners.

[TOOL BOX]: Triplex and duplex pumps are called reciprocating pumps because of the

back & forth motion of their pistons. Use your mouse to move this duplex pump’s piston

back & forth so you can study the pump’s operation.

Pump Components

A mud pump has a Fluid End, Power End and Intake & Discharge Valves. The fluid end

of the pump contains the pistons with liners, which take in and discharge the fluid or mud.

The pump’s pistons draw in mud from the intake valves and push mud out through the

discharge valves. The power end houses the large crankshaft & gear assembly that

moves the piston assemblies in the fluid end. Pumps are powered by a pump motor.

Large modern DC electric rigs use powerful electric motors to drive the pump.

Mechanical rigs use chain drives or power bands (belts) from the rig’s engines and

compound to drive the pump.

Bladder-type Pulsation Dampener

A pulsation dampener connected to the mud discharge line smooth out surges created by

the pistons as they discharge mud. This is a standard bladder-type dampener. The

bladder in the dampener body separates pressurized nitrogen gas above from mud

below. The bladder is made from synthetic rubber and is flexible. When mud discharge

pressure presses against the bottom of the bladder, nitrogen pressure above the bladder

resists it. This resistance smoothes out the surges of the mud leaving the pump.

[TOOL BOX]: Here is a pump without a pulsation dampener. See the surges or pulses of

high pressure mud leaving the pump. These surges can cause vibrations and damage or

wear equipment. Add the pulsation dampener to see the difference it makes. Using your

mouse, click on the pulsation dampener and drag it into place.

Non-bladder Type Pulsation Dampener

Here is the latest type of pulsation dampener. It does not have a bladder. It is a sphere

about four ft (1.2 m) in diameter. It is built into the mud pump’s discharge line. The large

chamber is full of mud. It has no moving parts, so it does not need maintenance. The

mud in the large volume’s sphere absorbs the surge of the mud leaving the pump.



Suction Dampener

A suction dampener smoothes out the flow of the mud coming into the pump. Crew

members mount it on a triplex mud pump’s suction line. Inside the steel chamber is an

air-charged rubber bladder of diaphragm. The crew charges the bladder about 10-15 psi

(50-100KPa). The suction dampener absorbs surges in the mud pump’s suction line

caused by the fast moving pump pistons. The pistons constantly start and stop the mud’s

flow through the pump. At the other end of the suction line, a charging pump sends a

smooth flow of mud to the pump’s intake. When the smooth flow meets the surging flow,

the impact is absorbed by the dampener.

Discharge Line Relief Valve

Workers always install a discharge pressure relief valve. They install it on the pump’s

discharge side in or near the discharge line. If for some reason, too much pressure builds

up in the discharge line, perhaps the drill bit or annulus gets plugged, the relief valve

opens. The open valve protects the mud pump and system against damage from

overpressure.

Suction Line Relief Valve

Some rig owners install a suction line relief valve. They install it on top of the suction line,

near the suction dampener. They mount it on top, so it won’t clog up with mud when the

system shut down. A suction relief valve protects the charging pump and the suction line

dampener. A suction relief valve usually has a 2 inch (50 mm) seat opening. The installer

normally adjusts it to a 70 psi (500KPa) reliving pressure. If both of the suction and

discharge valves failed on the same side of the pump, a high back flow or a pressure

surge would occur. The high backflow could damage the charging pump or the suction

line dampener.

Pump Discharge Line

The discharge line is a high pressure line through which the pump moves mud. From the

discharge line, the mud goes through the standpipe, and rotary hose, to the drill string

equipment.

Mud Conditioning

Over View:

The shale shaker mechanically takes out the large cuttings from the mud. It does not,

however, remove very fine cuttings and other small solid particles. These solids can be

fine sand particles and other very fine materials, often called “silt”. Good drilling practice

requires removing these undesirable solids. If not removed, the solids can increase the

weight of the mud more than required, reduce the bit’s penetration rate and significantly

increase the rate of wear on circulating equipment. The rig uses mechanical solids-

removing equipment, such as hydrocyclones and centrifuges to remove the fine solids.

Sometimes the hole penetrates a formation that has small amount of gas. This gas gets

into the mud, becomes entrained in it and must be removed before the pump re-

circulates the mud back down hole. A degasser removes entrained gas from the mud.



Shale Shaker

The shale shaker has rapidly vibrating screens. The mud and cuttings from the return line

fall onto it. The vibrating screens catch the larger cuttings. These cuttings fall into the

reserve pit, the sea, or other container for disposal. The liquid mud goes into the sand

trap, which is a special mud tank. Shale shakers look simple, in fact, though,

manufacturers carefully design them to make the screens vibrate in a very-controlled

way.

Degasser

Sometimes, the crew sends mud through a vacuum degasser. The degasser removes

gas from the mud. If the gas were not removed, it could make the mud too light, not

dense enough. As a result, the well could kick, formation fluids could enter the well bore

and have to be controlled to prevent a blowout. Another problem, if the driller recirculates

gas-cut mud, the gas could cause the mud pump to gas-lock. Gas-locked pumps pump

gas and mud instead of just mud, which is highly inefficient. So to remove gas, crew

members use a degasser.

Vacuum Degasser Operation

In a vacuum degasser, mud with gas in it enters at the top and spills out over special

baffle plates, a spreader. Spreading out of the mud presents a large surface area for the

gas to break out. Also the vacuum pump creates a vacuum, pressure lower than the

surround atmosphere inside the degasser. This vacuum makes it very easy for the gas to

escape from the spread-up mud. The removed gas leaves through a vent, which sends

the gas a safe distance away from the rig. The gas-free mud falls to the bottom and goes

back into the mud tank’s down stream from the degasser.

Hydrocyclone

A hydrocyclone system consists of several cones. Mud enters through a side opening at

the large end of each cone. It swirls around inside the cone. This centrifugal force or

cyclone motion throws the larger particles to the side of the cone. There the particles

move to the bottom of the cone and drop out. Clean mud goes out the outlet at the top. A

desander has large cones, it removes particles as small as about 40 microns. A micron is

one millionth of a meter, which is very small. A desilter has smaller cones than a

desander. Disilters remove particles down to about 20 microns. A mud cleaner has steel

smaller cones, it removes particles down to bout 7 microns. Since barite, the desirable

solid, which gives weight to the mud, is also about 7 microns, screens are included on

mud cleaners to retrieve the barite so that it can be returned to mud system.

Hydrocyclone Operation

Inside the cone, mud enters from the side and spirals down. This movement flings the

solids to the side. The spiraling action creates a vortex in the center, somewhat like a

tornado. It is an area of lower pressure, so the vortex sucks the liquid mud up through the

center and out through the top of the cone. Meanwhile, the solids slide down the side and



out of the bottom of the cone. The smaller the cone, the smaller is the particle it can

remove, but more cones are needed to handle a given volume of mud.

Centrifuge

A centrifuge spins mud at high speed. This creates centrifugal force. Centrifugal force

throws the particles to the side of the centrifuge, where they’re removed. A centrifuge

removes particles as small as 2-5 microns, which includes barite. Sometimes, crew

members run a centrifuge at a specific speed to remove barite so the rig can use it again

on a next tool. Occasionally, the rig owner runs two centrifuges, the first removes the

barite, and the second the finer particles. Crew members then re-add the barite to the

mud system.

Agitator

Crew members mount agitators on one or more of the tanks. Agitators stir the mud in the

tanks to keep solids from settling and to maintain uniform mud properties. One popular

agitator is the paddle-type, an electric motor rotates paddle to stir the mud.

Pit Volume Totalizer

A Pit Volume Totalizer, or PVT, alerts the driller to changing the level of mud in the tanks.

A float in each tank rises or falls if the mud level rises or falls. For example, if the level

rises, the rising floats send a signal to a recorder and to a digital panel on the rig floor.

The panel alerts the driller of the rise. This device is called a pit volume totalizer, or PVT,

because it measures the gain or fall in each of the tanks or pits, totals the gain or fall and

sends this information to the driller on the rig floor. If the mud level in the tanks fall, the

PVT also alerts the driller. This float in a mud tank is part of a pit volume totalizer. Usually,

crew members install a float in each active tank. The floats rise or fall with the mud level

in the active tanks. Mud level in the tanks is vital information. If the mud level rises, it

often means that the well has kicked, formation fluids have entered the hole and forced

mud out. The kick fluids replace mud in the hole and cause the mud level in the tanks to

rise. On the other hand, if mud begins going into a formation, if mud is lost to the

formation, the mud tank level drops. Lost circulation can also be a serious problem. The

decrease in height of mud in the hole could lead to a kick, because hydrostatic pressure

is reduced. Also drilling without mud returning to the surface is like drilling blind, no

communication between the bottom of the hole and the surface exists.

Centrifugal Pump

The mud system normally has several centrifugal pumps. A centrifugal pump puts out

relatively low pressure but it can move a large volume of mud. Crew members therefore

use them in several ways. One job a centrifugal pump often does is supercharge the mud

intake of the main mud pump. The small pump takes the mud from a suction tank, moves

it through a line connected to the main pump suction line and keeps the suction line full of

mud at all times. If the system does not use a charging pump, the force of gravity alone

feeds the pump’s suction line. Sometimes, gravity cannot keep the pump’s intake

completely full of mud. The pump’s pistons suck in the mud so fast that gravity cannot



keep the suction line full of mud. The crew also uses a centrifugal pump to make some

mud components.

Hopper

A hopper is like a big funnel. Crew members put sacks of mud material into it. They do

not, however, use the hopper to mix caustic soda. The hopper can blow dry caustic back

into the face of the worker mixing it. In addition to being dangerous, adding caustic

through the hopper can flocculate the mud, cause it to clog up.

[TOOL BOX]: It takes special personal protective equipment to handle caustic soda.

When working with caustic, one must wear goggles, a face shield, rubber gauntlets,

safety boots, coveralls, and a hard hat. Caustic soda should be mixed using the chemical

tank, not the hopper.

Jet Hopper

A crew member opens the sack of material at the top of the hopper and feeds the

material into the funnel. At the same time, a jet of mud from a centrifugal pump goes

through a nozzle at the bottom of the funnel. This jet creates suction. The suction pulls

the material into the mud stream and thoroughly mixes it.

[TOOL BOX]: Let’s see how well you’ve learnt the names of mud conditioning equipment.

For each piece of equipment you see, click on its name.

VOLUME FIVE HOISTING EQUIPMENT

OVERVIEW:

Function of Hoisting Equipment

A rig is complicated, but easier to understand if divided into related parts. In this section,

we well cover the equipment used in hoisting. Hoisting equipment hangs or suspends the

drill string in the hole. It also allows the driller to raise and lower the drill string into & out

of the hole. Further, it allows the driller to adjust the weight on the bit, which is required to

make the bit drill.

Hoisting System Components

The equipment used in hoisting is shown here: the Crown Block, the Traveling Block &

Hook, the Drilling Line, the Drill Line Supply Reel, the Deadline to crown block, the Fast

Line to drawworks, the Drawworks and the Deadline Anchor.

Hoisting System Operation

Here is an overview of how the hoisting system operates. The supply reel stores drilling

line. To reeve the line, crew members start it at the deadline anchor. They pull the line

from the supply reel and spool it around the disk on the anchor. They then lift the line to

the top of the mast, to the crown block. Crew members then reeve the line several times

between the crown block sheaves and traveling block sheaves. The number of times



depends on how much weight the system needs to lift. In this case, they run the line 5

times between the two blocks to create 10 lines. Once they’ve strung the right number of

lines, they run the line to the drawworks and firmly clamp the line to the drum. The driller

then takes in the drilling line, which wraps around the drum. The driller usually takes in

enough line, so that the line makes it at least 6 wraps around the drum. They then clamp

the line at the deadline anchor. As the driller activates the drawworks to take in line, the

traveling block moves up. The driller uses the brake to stop the traveling block at any

position. When the driller releases the brake, the force of gravity pulls the traveling block

down.

[TOOL BOX]: Here are the components of the hoisting system, drag the labels to the

appropriate components.

CROWN BLOCK

Crown Block Operation

The rig builder mounts the crown block at the top of the mast. The crown block has

several pulleys called sheaves. The block manufacturer mounts the sheaves side by side

on a shaft. The drilling line runs over the grooves in the sheaves. Sometimes, like this

one, the crown block has a special fast sheave. The drilling line runs over the fast sheave

as it leaves or enters the side-by-side sheaves on the crown block. Crown blocks have

load ratings that range from about 420 to 1400 tons (about 380-1300 metric tonnes).

Sheave diameters range from 42 to 72 inches (or about 107-180 cm).

TRAVELING BLOCK & HOOK

Overview:

A traveling block also has several side-by-side sheaves. A steel housing encloses them.

Crew members thread or reeve the drilling line over the sheaves. [TOOL BOX]: The crew

must use drilling line that is the right size for the sheave groove that it fits in. Here are

cross section of use of three diameters of drilling line. Drag each one into this sheave to

see what happens. Small: the diameter of this wire rope is too small. The rope will move

back & forth in the sheave groove, causing it to flatten on one side and wear out

prematurely. Medium: the diameter of this wire rope is just fight. The wire rope can’t

move back & forth in the groove and it won’t wear excessively on the sides of the sheave

groove. Large: the diameter of this wire rope is too big. It will rub on the sides of the

sheave groove and wear out prematurely. A hook is attached to the bottom of the

traveling block. The hook suspends the swivel, kelly and drill string or a top drive & drill

string.

Motion (Heave) Compensator

This is a traveling block on an offshore floating rig. It has a drill string motion

compensator. The motion compensator is between the traveling block and the hook.

Offshore floating rigs move up and down with sea movements. The motion compensator



maintains drill string position by counteracting up & down vessel movement or heave. On

some semi-submersibles and drill ships, rig owners mount the motion compensator on

the crown or the top of the derrick.

Motion Compensator Operation

The compensator eliminates the motion of the drill string from hook to the bit. As the

vessel moves up & down, hydraulic pressure inside a piston and cylinder keep the hook

in a fixed position relative to the sea floor. The compensator keeps the drill bit on the

bottom of the hole, within the weight on bit limits set by the driller. A typical compensator

can compensate for up & down movement as much as 15-25 ft (4.5-7.5 m). Typically, two

sizes of motion compensators are available: one can handle loads up to 400,000 pounds

(or about 180,000kg); another one which is bigger can handle loads up to 600,000

pounds (or about 270,000kg).

Combination Hook-Block

Some traveling blocks have built-in hooks, they are single integrity unit. The combination

Hook-Block is shorter, and therefore allows more traveling distance when mast height is

limited. Typical combination hook-blocks have load ratings ranging from 175 tons to 650

tons (about 160- 590 metric tonnes).

Separate Hook and Traveling Block

Some traveling blocks & hooks are separate units. In this type, the bail of the hook fits

into a clevis on the bottom of the traveling block. Crew members suspend the swivel and

drill string from the hook. They open the hook’s latch, insert the swivel’s bail and close

the hook’s latch. A safety catch ensures that the hook stays latched. Separate traveling

blocks are available in load ranges from 100 to 1250 tons (or about 90 to 1125 metric

tonnes). Sheave diameters range from 24 to 72 inches, 61 to 183 cm. That is 2 to 6 ft, or

over half a meter to nearly 2 meters in diameter. Hooks have load ratings of from 350 to

1000 tons (about 300 to 900 metric tonnes).

Hook, Links & Elevator

The hook has two link ears. The crew attaches on piece of forged links and an elevator to

the ears. They lock the links to the ears with the link-locking arms. Crew members latch

the elevator to tubulars, joints of drill pipe and other types of pipe as they running into &

out of the hole.

Elevator

Crew members latch the elevator around the top joint of the drill pipe. Then when the

driller takes in drilling line, the traveling block goes up, raising the elevator and attached

pipe. Conversely, when the driller lowers the traveling block, the elevator and attached

pipe also go down.

Types of Elevators

Crew members use many types of elevators, which one depends on the kind and size of



the tubulars. For example, most drill pipe and lifting subs require a center-latch

bottleneck elevator. But some drill collars require a side-door collar type elevator; tubing,

a light-weight pipe used in completing wells usually needs a slip type tubing elevator;

casing, large pipe the crew lines the hole with requires a special heavy-weight casing

elevator. The two types here are the Single-Joint, Casing Pick-Up type and the 500-ton

(or 450-metric tonne) Casing Elevator-Spider.

Hook Positioner & Swivel Lock Assembly

Most hooks have two locks: a rotation lock and automatic positioner lock. Crew members

use a long steel rod, called a shepherd stick or a checking hook to unlock and lock the

rotation lock and the automatic hook positioner. When crew members unlock the rotation

lock, they rotate the hook to make the elevator face a desired direction. Once positioned,

they lock the rotation lock to keep the hook in position. Crew members can also release

the rotation lock when the hook needs to rotate freely. The other lock, an optional

automatic hook positioner prevents rotation of the elevator links when the hook is

traveling empty. Normally, just before making a trip in cased hole, crew members unlock

the rotation lock, turn the hook, and relock it, so that the elevator faces the derrick man.

This makes it easy for him to latch and unlatch the elevator. If crew members are tripping

pipe in open hole, they activate the automatic hook positioner. This lets the hook rotate

freely when hoisting the drill string, allowing the drill string to turn in open hole as it is

being pulled, keeps it from damaging the hole and prevents the reeve to drilling line from

twisting. Then, when the elevator reaches the derrick man and the driller stops hoisting,

the positioner automatically rotates the elevator into correct position for the derrick man.

Hydraulic Snubber

Inside the hook is a hydraulic snubber. The snubber is like a shock absorber. It prevents

drill pipe bounce and tool joint damage when spinning out the connection.

DRILLING LINE

Drilling Line

Drilling line is high strength heavy-duty wire rope. The manufacturer braids several wires

together to form the rope. Drilling line comes in diameters ranging from 7/8 to 2 inches

(about 22-51 mm). Crew members string or reeve drilling line between the crown block

and the traveling block. The more lines they reeve, the more weight the system can

support. Here for example, they reeve the line 5 times between the blocks, so that ten

lines support the traveling block.

Reeving Drilling Line

Here is the crown block & traveling block strung together by drilling line. Note how the

traveling block goes up & down as the driller takes in or lets out drilling line. The deadline

is drilling line that runs to the deadline anchor. The fast line is drilling line that runs to the

drawworks. Notice the five wraps of drilling line between the crown & the traveling block.

Five wraps makes for ten lines. Ten lines can lift ten times the weight of a single line.



Also notice that the crown block has one more sheave than the traveling block. This extra

sheave is for the fast line.

[TOOL BOX]: This photo shows the fast line and the deadline on a rig. Using your mouse,

drag each label onto the correct line, then click the “accept” button to see if you’ve gotten

it right.

Supply (Storage) Reel

Drilling line comes to the rig on a large supply reel. Normally crew members string the

needed amount of line through the traveling & crown blocks and onto the drawworks.

Then they keep the extra line on this supply reel. The reason they keep the extra line is

for a Slip-and-Cut Program.

Wear PointS on Line

As the driller raises and lowers the traveling block and its associated loads, the drilling

line wears. It tends to wear more where it passes over the traveling block sheaves and

the crown block sheaves. The line has to bend around the sheaves and this puts extra

stress on it. The line also wears more where it reaches the end of the drawworks’ drum. It

has to reverse direction here, and start back the other way on the drum. This direction

change puts extra stress on the line.

[TOOL BOX]: Not only does the drilling line wear, but the sheaves do also. One thing that

the crew does to prolong the life of the sheaves is to rotate the traveling block 180°

degrees. Click on it and we’ll see why this is done. During operation, each sheave moves

at a different speed. The one closest to the fast line moves the fastest and the one

closest to the deadline moves the slowest. Since the faster moving sheaves wear

quicker, the wear can be distributed evenly among the sheaves by rotating the traveling

block periodically. This is often done between wells.

Slipping and Cutting Drilling Line

To distribute the wear on the drilling line, the crew slips the line a predetermined amount.

Slipping the line moves the wear points on the line. To slip the line, crew members lower

the traveling block to the rig floor. They then rig up a special hang line from the crown

beam to the top of the traveling block. The hang line keeps the block from moving. With

the block unable to move, they unclamp the drilling line at the deadline anchor. The driller

then uses the drawworks to pull new line off the supply reel. The line slips through the

deadline anchor and stationary traveling block. The worn line reels onto the drawworks’

drum. To keep too much line from accumulating on the drum, crew members cut off the

end of the worn fast line and discard it.

[TOOL BOX]: This is an example of bird-caged or wicker wire. Bird-caged wire is unsafe

and needs to be removed by slipping & cutting. Bird-caged wire is caused by sudden

dropping of the traveling block. Driller should raise & lower the traveling block as

smoothly as possible.



Deadline Anchor

This is the deadline anchor. It firmly secures the drilling line and keeps it from moving.

Drilling line comes off supply reel, and loops several times around the anchor. The rig

crew then firmly clamps the line to the anchor. The line leaves the anchor, goes through

the crown & traveling blocks and then to the drawworks. Clamping the deadline to the

deadline anchor mechanically isolates the drilling line from the supply reel. Because the

line is stationary, it is called the deadline.

DRAWWORKS

Overview

The drawworks has a large spool or drum around which the crew members wrap the

drilling line. Power from the engines or electric motors drives the drawworks’ drum. When

the driller activates its control and releases the brake, the drum reels in drilling line.

Reeling in drilling line raises the traveling block and whatever’s attached to it. To lower

the traveling block, the driller releases the drawworks’ brake. The force of gravity pulls

the block down. The driller controls the descent by applying the brake to slow or stop the

downward travel. The smallest drawworks are around 550 hp, while the largest have

4000 hp, about 400-3000 KW. Small drawworks can handle wells drilled to around 3000

ft (1000m) deep; the largest can handle 40000-foot or 12000-m depth.

Braking System

When the driller moves the brake handle down, the drawworks’ brake bands exert friction

on both rims of the drum. We’re only showing one rim to keep it simple. This friction

slows or stops the drum. When the driller lifts the brake handle a small amount, tension

on the band eases. With tension eased, the drawworks’ drum rotates a small amount to

gradually lower the load. When the driller lifts the handle up fully, the bands do not touch

the drum rims at all, the drum rotates freely and the load drops in free-fall.

Disk Brake System

Many new drawworks use a disk brake system. Disk brakes are more efficient than drum

brakes. A typical disk brake system consists of three major components: two Disks, one

on each end of the drum; a Hydraulic Operating System, which you can’t see here, and

Caliper-and-Pad Assemblies. The system has 6 service calipers, 3 on each disk, and 2

emergency calipers, one on each disk. When the driller engages the brake, hydraulic

pressure pushes in the pads inside each service caliper. The pads contact the disk and

slow or stop the drum. If hydraulic pressure fails, the emergency caliper set automatically.

Electrodynamic Brake

Mounted on the end of the drawworks’ drum shaft, is an electrodynamic brake. It is an

auxiliary brake that uses powerful electromagnets. The electromagnetic force works

against the turning force of the drawworks’ drum shaft. It assists the mechanical drum or

disk brake you just saw. It controls the speed of the load as it goes down. The driller can

not control the load’s speed with the drum or disk brake alone. The weight of the load



plus the tremendous inertia creates when moving is just too great. So the driller activates

the eletrodynamic brake. The electrodynamic brake provides most of the braking force

when the drawworks’ drum is turning.

[TOOL BOX]: Drag the labels to proper location to identify the components in this photo.

Latest Drawworks

The most modern drawworks’ braking system does not use an electrodynamic brake.

Instead, the drawworks is powered by a special computerized motor and control system.

The computer-control system allows the drive motor to power the drawworks and provide

the auxiliary braking force.

Crown Saver

Mounted on the drawworks, near the drawworks’ drum, is a crown saver, or a crown O-

Matic, a brand name. A crown saver keeps the driller from accidentally raising the

traveling block into the crown block. It has a probe that activates an air-actuated toggle

switch if the driller takes in too much drilling line onto the drawworks’ drum. Too much

line indicates that the driller has raised the traveling block too high in the mast. If he

raised the block any more, it would crash into the crown block, or separate the rotary

hose, causing a lot of damage. Too much line on the drum activates the toggle switch.

The switch then immediately engages the drawworks’ brake and disengages the

drawworks’ clutch. Clutch disengagement disconnects the drawworks’ drum from its

power source. The latest drawworks uses an electrically actuated crown saver system,

but still maintains the pneumatic crown saver as back up.

VOLUME SIX ROTATING EQUIPMENT, MAST & SUBSTRUCTURE

ROTATING EQUIPMENT

Overview

Some rigs use a kelly and rotary table to rotate the drill string and bit. This system

consists of the Swivel and Rotary Hose, the Kelly Assembly and the Rotary Table. Some

rigs use a top drive system to rotate the drill string and bit. A modern top drive, also

called a power swivel, is an integrity unit that includes a Pipe Handler Assembly, Block,

Swivel and a powerful Motor or motors to rotate the drive shaft. Crew members make up

the drill string to the drive shaft.

KELLY & ROTARY TABLE

Kelly Assembly

Crew members make up the kelly to the swivel stem. The kelly has either four or six

sides and passes through a four or six-sided opening in the kelly drive bushing. The kelly

drive bushing meets with the master bushing, so when the machine inside the rotary

table rotates the master bushing, the kelly drive bushing rotates the kelly and attached

drill string and bit.



Kelly Detail

The kelly is flat-sided, with either a square or hexagonal cross section. It is square in this

drawing. It is hollow so the drill fluid can flow through it. The kelly moves through a

square or hexagonal opening in the kelly drive bushing. The kelly drive bushing meets

with the master bushing in the rotary table. The rotary table turns the master bushing, the

kelly drive bushing, the kelly and the attached drill string & bit. The kelly can move

vertically while rotating.

Rotary Table Operation

The rotary table performs two functions. First, it transmits rotary motion to the master

bushing, which drives the kelly and drill string, and with systems of slips, hangs the drill

string. The master bushing goes inside an opening in the rotary table. Small master

bushings are usually a solid single piece as shown here. Large master bushings are

either split or hinged.

Crew members install a two piece or split insert bowl in a receptacle in the center of the

master bushing. The insert bowl is tapered inside and supports the back of the slips.

They come in varied sizes. The crew changes out the insert bowls to match with the

types of slips in use. Insert bowls are also called inserts or bushings. Rotary tables have

openings that range in diameter from 17-49 inches (43 cm to about1.2 m). The smallest

can hold a nonmoving load of 250 tons (about 225 metric tonnes). The largest can hold a

nonmoving load of 800 tons (about 725 metric tonnes). Some small rotaries can spin as

fast as 500 revolutions per minute, rpm; large rotaries spin a bit slower, with upper

ranges about 300 rpm.

Setting Slips

Manufacturers taper the inside of the insert bowl. They taper it to match the taper of the

back of the slips. The slips grab the drill string and suspend it inside the insert bowl. The

insert bowl fits inside the rotary table’s master bushing. Suspending the drill string in this

manner allows crew members to disconnect the kelly or top drive and break out joints of

drill pipe. Crew members can remove the insert bowls to provide a larger opening

through the rotary table. If necessary, they can also remove the master bushing. They

may have to do this to run a large hole opener bit or large casing. Casing is pipe that the

crew runs to line the walls of the hole after they drill it.

Swivel & Rotary Hose

A rotary table & kelly system includes a swivel & rotary hose. The swivel has a bail, like

the bail or the handle on a bucket, only much larger. The swivel bail hangs from the hook

on the traveling block. The swivel allows the attached kelly & drill string to rotate. At the

same time, the rotary hose conducts drilling mud into a curved pipe, called the

gooseneck. The gooseneck attaches to the swivel and carries drilling fluid to the swivel

via the washpipe. The rotary hose is flexible, steel-reinforced hose that allows the swivel

to move up & down within the mast. A passage way inside the swivel stem conducts the

high pressure drilling mud into the kelly and drill string.



Swivel Operation

Here is an isolated view of the swivel. The bail hangs the swivel from a hook, which is not

shown. The rotary hose conducts drilling mud to the gooseneck. Mud flows through the

gooseneck, down the washpipe, and into the stem & drill string below. Washpipe packing

seals the high pressure mud in the washpipe as the stem rotates. The stem rotates on

heavy-duty radial bearings & thrust bearings. The main thrust bearings support the entire

weight of the drill string as it rotates. Swivels have dead load capacities ranging from 150

to 1250 tons, about 135 to 1125 metric tonnes. An oil reservoir lubricates the bearings

and rotating parts.

[TOOL BOX]: Here are all the pieces of the rotating assembly. Put them together, starting

from the rig floor and working your way up. Drag each piece into place with your mouse.

TOP DRIVE (POWER SWIVEL)

Overview

Some rigs use a top drive system to rotate the drill string & bit. A top drive has a powerful

motor or motors, and a drive shaft. The crew attaches the drill string to the drive shaft.

When the motor rotates the drive shaft, the attached drill string & bit also rotate. Crew

members attach the top drive to Guide Rails or Tracks, which keeps the whole unit from

rotating. With a top drive, the rotary table does not rotate the drill string.

Top Drive Advantages & Disadvantages

The most important benefit of a top drive is that it reduces drilling time. It also rotates the

drill string more efficiently than the kelly & rotary table system. Further, it handles stands

and pipe more efficiently. A top drive system provides more variable rotating power than

a rotary table. It allows drill string rotation and circulation at any point in the hole, when

tripping in, drilling, or tripping out. These features help prevent hole problems. It provides

rapid response to well kicks during tripping or running casing. The driller can make up

and remotely shut the built-in IBOP to stop drill string flow faster than the crew can set

slips, stab and close a full opening safety valve. In highly deviated holes, it helps to

prevent the pipe from getting stuck by allowing the driller to immediately ream or back

ream the drill stem. If the crew can make three joint stands of pipe before drilling starts, a

top drive can drill triple stands, instead of just one joint, as is necessary on a kelly drive

rig. Making up 3 joint stands reduces the number of connections required to 1/3. In many

cases on large offshore rigs, the crew no longer needs to lay down pipe between wells.

That is the crew can set stands back vertically in the derrick, and the rig can be moved a

short distance without the pipe being laid down.

Top drives have a few disadvantages. They’re more expensive to maintain and they’re

very large. Because of the additional weight, the rig’s drilling line wears faster. They are

more difficult to move on land rigs that must be disassembled.

Top Drive Assembly

A top drive does not use a kelly or the rotating components of the rotary table. The top

drive includes a traveling block and an integrated swivel. The rotary hose conducts



drilling mud to the integrated swivel via an S-pipe assembly. A passage inside the swivel

drive shaft directs mud into the drill string. The top drive motor, connects to the traveling

equipment at the integrated swivel assembly. Drive motor horsepower ranges from 600

up to 2100 (or 420 to 1500 KW). The motor turns the main drive shaft through a gear box

or transmission. Crew members make up a saver sub on the bottom of the drive shaft

and make up the drill string onto the saver sub. The saver sub cuts down on wear & tear

to the drive shaft’s threads. Top drive have hoisting capacities ranging from 350 to 750

tons (or 315 to 680 metric tonnes). Guide tracks or rails in the mast keep the top drive

unit form rotating as the motor in the drive shaft assembly turns the drill string. The top

drive dully assembly moves up or down on the guide rails. Service loops which are

bundled cables and hoses transfer the required electric, pneumatic, and hydraulic power

between the mast’s standpipes and the junction boxes located on the top drive. The top

drive unit also includes a pipe handler assembly that has an upper inside blowout

preventer, IBOP, a lower IBOP and a torque wrench. The torque wrench makes up (or

connects) or breaks out (or disconnects) joints of drill pipe. The driller controls the top

drive’s operation from a console. The pipe handler assembly also includes links, an

elevator, and an automatic Link-Tilt assembly. The driller activates the link-tilt assembly to

position the links and elevator at the mouse hole for picking up or laying down drill pipe.

The link-tilt assembly also assists the derrick man in racking stands.

[TOOL BOX]

MAST & DERRICKS

Overview

The rig’s mast is a strong tower that supports the equipment attached to the traveling

block & hook. Crew members sometimes use the words “mast” and “derrick”

interchangeably. In reality, a mast stands independently on the rig floor and is raised as a

single piece unit. In the old days, rig owners used a lot of derricks. A standard derrick as

it’s called, is usually bolted together. It has four legs, beams and girds, or cross braces.

Unlike the mast, the derrick cannot be lowered or raised as a single unit. Today masts

are much more common than derricks.

Mast

Manufacturers usually weld and pin the mast together for easier to assembly or

disassembly. A self-erecting mast may be a Cantilever type, a folding type, or a

telescoping type.

[TOOL BOX]:

Transporting Mast: Once take a look at some of the alternative ways that heavy roading

here can be used to transport a mast to the land rig well site. These transport methods

can be used in terrain that’s fairly flat and open, like desert. Here you see a mast

together with the substructure being towed in the upright position. Here is another mast

being towed with its substructure. However, this one is being towed in a horizontal

position. Once it’s at the well location, it will be raised up into position using the

drawworks. This mast is also being towed in a horizontal position, but its substructure is

towed separately. The mast will have to be mounted and raised on the substructure once



it arrives at the well location.

Height & Capacity

A mast or derrick is tall, normally having a clear height from 100 to 160 ft (30-50 m).

They’re also strong; they’re able to support static weights ranging from 275,000 pounds

to 31/4 million pounds (or 125,000 to 1.5 million kg). A rig’s mast must be tall enough to

allow crew members to set back drill pipe, tubing and other tubulars they pull out of the

hole during a trip out. It also has to be tall enough to allow the driller to raise the traveling

block above the height of the derrick man’s monkey-board.

Stands

With the traveling block high in the mast, and the elevator at the derrick man’s position on

the monkey-board. The derrick man sets back drill string elements or stands. Most rigs

pull three-joint stand of drill pipe and drill collars. A three-joint stand is three made-up

joints of drill pipe or collars. Small rigs may pull two or even one joint stand. In rare

cases, a really large rig may pull four-joint stand. Regardless of the number of joints,

pulling pipe in stands instead of a single joint at a time speeds up the tripping process.

Crown Walkaround (Water Table)

The working platform at the top of the derrick or mast that permits access to the crown

block is called the walkaround. It is also called the water table.

Monkey-board

The monkey-board is the derrick man’s working platform when crew members pull pipe

or run it back into the hole. The derrick man sets stands of pipe back into a finger board,

a platform with projections that holds the top of the pipe in place as it stands in the mast.

Stabbing Board

A stabbing board is similar to the monkey-board. It is a small platform in the mast or

derrick about 30-40 ft (or 9-12m) above the rig floor. A drilling crew member, usually the

derrick man, works on the platform when running casing or tubing. The derrick man

guides the top of the casing or tubing from the stabbing board. The crew member calls

the stabber, adjust the stabbing board’s height with a hydraulic, electric or air-powered

motor. The height varies depending on the length of the casing or tubing being made up

and running into the hole.

[TOOL BOX]

Here is a picture of a rig. When you’re given a rig component, click on the photo where

the component is located.

SUBSTRUCTURE

Overview

The substructure is a rugged set of beams. It supports the mast or derrick and the heavy



hoisting & rotating equipment. It also supports the drilling tubulars on the rig floor. It must

be high enough to accommodate the blowout preventer stack underneath the rig floor.

V-Door, Pipe Ramp & Catwalk

Crew members hoist pipe and equipment from the catwalk up to the rig floor by raising it

up the pipe ramp. They hoist it onto the rig floor through the V-door.

[TOOL BOX]

The V-Door takes its name from the early days of the oil patch. On old standard derricks,

this opening looked like a large up side down “V”. The name’s stuck, even though today

the opening may not look much like a “V”.

VOLUME SEVEN PIPE HANDLING EQUIPMENT

PIPE HANDLING

Overview

The rig crew needs pipe handling equipment for several reasons. One is to make a

connection, to add a joint of pipe as the hole deepens; another is to trip the pipe, to take

the pipe out and put it back in the hole, so they can change out bit, put a new bottom hole

assembly and drill string or perform any other action that requires the drill string’s

removal from the hole. Crew members can make connections either by using a kelly &

rotary table system or a top drive unit. Handling pipe, tripping it in and out of the hole,

connecting joints together, and moving it around the rig floor requires a lot of equipment.

Included in this equipment are the elevator, slips, tongs, power tongs, spinning wrenches,

catheads, kelly spinner, Iron Roughneck, rathole, mousehole and air hoist. Much of this

equipment is controlled at the driller’s console. Transferring pipe from the deck to the rig

floor may also involve special handling equipment.

[TOOL BOX]: Here is a little exercise to help you learn the names of all this equipment.

When you’re given the name of a component, click on it with your mouse. If you don’t get

it the first time, keep trying until you do.

PIPE HANDLING OPERATION

Making a Connection with Kelly

Notice that the kelly is drilled down, that is the rig can drill no deeper without adding a

joint of pipe. Here’s the sequence to make a connection with the kelly and rotary table

system. The driller picks up the kelly with the hoisting system and the floor crew sets the

slips to suspend the drill string in the hole. Using large wrenches, called tongs, the crew

loosens or breaks out the kelly from the drill string. They latch one set of tongs called the

back up tongs around the drill pipe to keep the pipe from turning when they apply break

out torque with the second set of tongs, called the lead tongs.

The driller actuates the break out cathead, which is an automatic winch on the

drawworks. The break out cathead pulls a line attached to the lead tongs and loosens the

connection. With the connection loosened, the driller spins put the drill pipe from the

kelly, usually by slowly turning the rotary table. The back up tongs latched onto the kelly



saver sub, keeps the kelly from turning as the pipe spins out. The crew then moves the

kelly over to the new joint of pipe placed in the mousehole, a lined opening in the rig floor

that holds the joint to be added. They stab the kelly into the new joint. They latch the

back up tongs around the tool joint of the pipe joint in the mousehole. The back up tongs

keep the joint from turning as the driller spins up the kelly into the joint, using the kelly

spinner. The kelly spinner is a pneumatic or hydraulic device mounted near the top of the

kelly. To make up the kelly onto the drill pipe to final tightness, the crew latches the lead

tongs around the kelly while holding the back up tongs on the pipe’s tool joint box. The

driller then actuates the make up cathead on the drawworks. The make up cathead pulls

a chain attached to the lead tongs and tightens the kelly onto the drill pipe joint. The

driller, using the hoisting system, picks up the kelly and new drill pipe joint out of the

mousehole, and the crew guides it to the drill pipe joint, hanging in the rotary table. The

crew stabs the new joint into the suspended joint, and the driller actuates the kelly

spinner to spin up the new joint.

[TOOL BOX]: Click on the play button to see a video of the kelly being made up.

Once bond up, the crew latches the back up & lead tongs around the joints to make them

up to final tightness. With the joints made up, the driller picks up the kelly and drill string.

The crew pulls the slips, and the driller lowers the kelly and meets the kelly drive bushing

with the master bushing. Drilling then continues.

Making A Connection with a Top Drive

Here is how to make a connection using a top drive. After drilling down the stand, the

crew sets the slips. The driller stops circulation, and the crew breaks out the saver sub

from the drill pipe using the torque wrench and the top drive’s pipe handler. The driller

then uses the top drive’s drilling motor to unscrew the connection. The driller picks up the

top drive and a crew member opens the drill pipe elevators to allow it to pass over the

box of the pipe, setting in the slips. The driller raises the top drive assembly to the

monkey-board. The derrick man latches the triple drill pipe stand in the elevators. The

elevators pick up the stand and the floor crew stabs the bottom pin into the drill pipe box

in the rotary table.

[TOOL BOX]: Click on the play button to see the joint being stabbed into the drill string.

The driller lowers the top drive to stab the saver sub into the box at the top of the stand.

Using the top drive’s drilling motor, the driller spins up both the top connection and the

lower connection at the rotary table. The rotary helpers use back up tongs to keep the

connection stationary as the pipe spins. Finally, the driller begins circulation, the crew

pulls the slips and drilling resumes.

[TOOL BOX]: Here is your chance to supervise the making of a connection, using a top

drive. The stand has been drilled down and it’s time to set the slips. The top drive has

already been broken up from the drill string and attached to the stand of pipe in the mast.



Raise the stand of drill pipe by clicking on the top drive… Good! Now lower the tool joint

on to the drill string by moving the top drive downwards with your mouse. Activate the top

drive by clicking on it with your mouse. Lift the drill string by moving the top drive

upwards. And finally, remove the slips by dragging them out of the insert bowls. Excellent

work! Now you are ready to make hole.

Tripping Out with Kelly

Here is a crew on a rig with the kelly & rotary table system tripping pipe out of the hole.

That is the rotary helpers, the derrick man and the driller are working together to pull the

drill string from the hole. Maybe to change the bit, or something similar.

First, the crew suspends the drill string in the hole with slips. Then they break out the

kelly assembly. They swing the assembly over to a lined hole, called the rathole, and the

driller lowers the assembly into the rathole. With the kelly assembly in the rathole, the

crew unhook the swivel bail from the hook, this action frees up the elevator. Crew

members latch the elevator around the joint of pipe hanging in the rotary table opening.

The driller, using the hoisting system, then lifts the pipe from the hole. Usually, the driller

lifts pipe until the third joint clears the rotary table opening. The floor hands then set the

slips around the top of the fourth joint. Using the tongs and a spinning wrench, the crew

breaks out the three-joint stand from the drill string and sets it back in the mast.

Meanwhile, up on the mast, the derrick man handles the upper end of the three-joint

stand. He places the top of the stand into a fingerboard, a series of projections near the

derrick man’s work platform called the monkey-board. The driller, rotary helpers and

derrick man repeat the process until all the drill string is out of the hole.

Tripping with Kelly

Here, the crew is tripping pipe back into the hole. The floor-hands, derrick man and the

driller work together to get the drill string back into the hole. Tripping in is pretty much the

opposite of tripping out. The driller sends the elevator up to the monkey-board, where the

derrick man latches the elevator around the top of the stand. The driller then picks up the

stand a little, and the rotary helper guides the lower end over to the string hanging in the

rotary table opening. They stab the stand, using the spinning wrench to spin up the stand

and make it up to final tightness with the tongs. The crew repeats this process until all the

string is back in the hole.

Tripping with Top Drive, 1

When tripping with a top drive, crew members use the drive’s elevator as much as they

use a conventional elevator when tripping with a kelly & rotary table rig. With a top drive,

the driller can position the links & elevator close to the derrick man on the monkey-board.

The driller moves the links & elevator by actuating the remote-controlled link-tilt

mechanism on the top drive. Moving the links & elevator makes it easy for the derrick

man to latch & unlatch the elevator around the drill pipe stand’s top tool joint.

Tripping with a Top Drive, 2

The drilling crew can also position the elevator in any direction by unlocking the rotation



lock and rotating the pipe handler assembly. Being able to position the pipe handler

assembly in any direction enables the derrick man and rotary helpers to position the

elevator where they need it to make a latch. The elevator returns to its original position

when rotated by the drill string.

Tripping with a Top Drive, 3

One advantage of a top drive over a conventional kelly system is its ability to ream or

back ream at any position in the mast while tripping. The driller can rotate and move the

string up & down through tight section of hole. These actions can ream out the tight

section of hole.

SLIPS & ELEVATOR SYSTEM

Slips

Crew members use wedge-shaped gripping devices called slips to suspend the drill

string in the hole. They fit it around the top joint of pipe and wedge in the taper of the

rotary table’s opening. Slips have seriated inserts or dies. The inserts grip the outside

diameter of the suspended tubular. To set the slips, crew members place them around

the pipe. The driller then slowly lowers the pipe until the slips can take up the load. The

seriated inserts or dies in the slips firmly hold the pipe. To remove the slips, crew

members grasp the slips’ handles. And as the driller picks up the pipe, they lift them out

of the rotary table opening and set them aside.

Safety Clamp on Drill Collar

When using drill collars and other tubulars that don not have an elevator shoulder, crew

members install a safety clamp above the drill collar slips. If the gripping elements on the

drill collar slips failed, the drill collar will slide down. Before the collars could slide all of

the way out of the slips, however, the safety clamp would hold the collars against the top

of the slips.

Slips & Spiders

Crew members use several types of slips and spiders. A spider, like slips, suspends pipe

in the hole, but spiders do not fit inside the rotary table’s opening. Instead, they rest on

top of it. Spiders are used instead of slips when the rotary table’s bushing size is not

compatible with the tubulars being run. Here you can see Drill Pipe Rotary Slips, Drill

Collar Slips, Drill Pipe Coil-Spring Power Slips and Air-Powered Tubing Spider and a

750-ton Air-Controlled Casing Spider. Crew members use each one to hold the

corresponding drill pipe, drill collars, casing or tubing. Power slips are powered by a

heavy duty, high strength coiled spring or by air. Instead of manually placing air-powered

slips in the master bushing, crew members or the driller operate them by remote control.

Elevator

Crew members latch the elevator around the top of pipe joint in the drill string. Once

latched, the driller can raise and lower pipe in and out of the hole. Crew members attach

the elevator to the hook with 2 forged high grade steel rods called links or bails. One end



of the links fits into the link ears on the hook, link locking arms secure the links into the

ears. Crew members then attach the elevator to the other end of the links. Most elevators

are hinged. Crew members open and close them by operating the latch with two handles

on each side. Notice that this elevator has a tapered seat. This taper matches the taper

on a tool joint of a length of drill pipe. When properly latched, the tool joint taper rests in

the elevator taper and makes a firm, positive grip without damaging the drill pipe.

Lifting Sub

On drill string members that do not have an elevator shoulder, crew members make up a

lifting sub into the end of the joint. For instance, this drill collar does not have a shoulder,

it is slick. So the crew made up the lifting sub. They latch the elevator onto the taper on

the lifting sub to raise or lower drill collars into and out of the hole.

Elevator on Top Drive

On a top drive, the links holding the elevator have an air-operated or pneumatic tilt

mechanism. The driller activates the tilt mechanism when the pipe is being pulled from

the hole. When the top of the drill string reaches the derrick man’s position at the monkey

board, the driller can tilt the top of the stand of the pipe toward the derrick man. The

derrick man can then unlatch the elevator and set the stand back in the finger board. The

finger board is a rack that supports the top of the stands of pipe being stacked in the

mast or derrick.

[TOOL BOX]: It’s time for a quick question: Which one of these tubulars would require a

safety clamp? Click on the correct one and then press the “accept” button.

SPINNING & TORQUING DEVICES

Tongs

Tongs are large wrenches that crew members use to make up and break out pipe. The

crew uses two sets of tongs to make up & break out pipe. One set is the lead tongs. The

lead tongs apply torque to tighten or loosen the connection. The other set is the back up

tongs. The back up tongs keep the lower joint of pipe from turning as the lead tongs

apply torque to the upper joint.

[TOOL BOX]:

Just what is torque, well torque is a twisting force. Here force is applied in a straight line.

Force applied in a straight line is not torque. Torque is force applied in a turning or

twisting motion. Here is a top view of a tong arm. We can calculate the torque or the

twisting force that the tong arm is putting on the pipe by multiplying the length of the tong

arm by the amount of line-pull in pounds or kilograms applied to it. In this case, the tong

arm is 4.2 ft or 1.3m long and 2000 lbs or 900 kg of line-pull is applied to it. Click on the

tong arm to rotate it. With this length of arm and this amount of line-pull, the tong applies

8400 ft-lbs or 1170 kg-m of torque to the pipe. That’s 4.2 times 2000 equals 8400 and 1.3

times 900 equals 1170. To increase the torque, you can either apply more pounds or



kilograms of pull or you can apply the same amount of the line-pull but use a longer tong

arm. For example, here the tong arm is 5 ft or 1.5 m long. The line-pull is, however, the

same 2000 lbs or 900 kg. Click on the tong arm to see how much torque the longer arm

gives. It’s 10000 ft-lbs or 1350 kg-m of torque with a 5 ft (or 1.5m) tong arm. Five times

2000 equals 10000 and 1.5 times 900 equals 1350. So increase of the length of the tong

arm or the line-pull increases the torque.

Makeup Cathead

Crew members use the tongs in conjunction with special catheads or winches on the

drawworks. When making up drill pipe, the driller actuates the make up cathead on the

drawworks. The cathead takes in the tong pull line, a chain in this case, and exerts a

strong pull on the tong arm. This pull causes the lead tongs to apply torque to the joint to

make it tight.

Breakout Cathead

When breaking out pipe, crew members use the break out cathead on the drawworks.

The break out cathead takes in the tong pull line and exerts a strong force on the tong

arm. This force breaks out the pipe connection.

Hydraulic Cathead

This is a hydraulic cathead. It’s an auxiliary torquing device. It helps crew members break

out and make up very large drill collars. Very large collars require a lot of make up torque

so much in fact that the break out cathead’s pulling force may not be strong enough. One

solution is to use a hydraulic cathead with rig tongs. The hydraulic cathead includes a

hydraulic cylinder housing and a wire assembly. The hydraulic cathead is controlled

remotely by the driller from his position on the rig floor. This device produces a safe,

powerful, and steady tong line pull to break high torque connections.

Power Tongs

Manufacturers make many types and sizes of power casing & tubing tongs. Crew

members use them to connect casing and tubing couplings. Power tongs allow fast and

uniform makeup & break out of connections. The make up torque can be preset by

adjusting a built-in pressure-relief valve.

Spinning Wrench

Accompanying a rig’s regular tongs is the spinning wrench or pipe spinner. Crew

members use a spinning wrench to spin up or spin out pipe connections. For example,

once a connection is lubricated and stabbed, they place the spinning wrench on the

upper joint and activate the wrench. Rollers engage the pipe and turn it rapidly until

shoulder meet shoulder. Then the crew latches the regular tongs to make up the joint to

final tightness. They can also reverse the direction of the spinning wrench to spin out a

joint that it loosens with the regular tongs.

Kelly Spinner



To spin up or spin out the Kelly, most rigs have a Kelly spinner. The Kelly spinner is

hydraulically or pneumatically operated. When the driller activates it, the Kelly spinner

rapidly spins up or spins out the Kelly from a joint of drill pipe. Crew members attach it to

the Kelly below the swivel.

Iron Roughneck

Some rigs have this vertical pipe handling device. The manufacturer calls it an Iron

Roughneck. It combines the lead tongs and back up tongs into a single package. The

built-in tongs are hydraulically powered, self-contain torque wrenches. They allow the

crew to make up and break out joints without using catheads on the drawworks. An Iron

Roughneck mounts on the rig floor and rolls into place on tracks. It reduces the labor

involved in making up and breaking out pipe. However, crew members have to maintain it

carefully to ensure proper operation.

PIPE TRANSFER

Pipe Racking System

Some rigs working in rough seas or harsh environments use automated pipe racking

system. The rig owner mounts the racking system on the rig floor and to the mast. The

device racks pipe stands in the mast’s fingerboard. The operator controls the pipe racker

from a remote station and views the operation from a camera located directly above the

fingerboard. The pipe racking system works in conjunction with the Iron Roughneck.

Another type of pipe racking system found on drill ships racks the drill pipe stands in

horizontal racks outside the mast or derrick.

Rathole

Crew members place the Kelly assembly in the rathole when they’re ready to make a trip.

The rathole is made of large diameter pipe that extends below the rig floor. The rathole

also protrudes above the rig floor to make it easily accessible.

Mousehole

The mouse hole is a length of large diameter pipe that extends below the rig floor. The

crew places a joint of drill pipe in the mousehole in preparation for adding it to the drill

string.

[TOOL BOX]: Drag each label to its proper location by the mousehole and the rathole,

then, press the “accept” button.

Air Hoist

Crew members use an air hoist to move pipe and other drilling equipment around the rig

floor. An air hoist is an air-powered winch that contains a reel of wire rope. When a crew

member actuates the hoist, it takes in rope to lift a piece of equipment. It also has a wire

rope guide that the crew member uses to keep the line from winding unevenly on the

reel. Usually rigs have several air hoists placed around the rig floor.

Pipe Transfer System



Some rigs use automatic pipe transfer system to pick up and lay down tubulars. The pipe

transfer system also moves tubulars onto the pipe deck. The automatic pick-up and lay-

down system (PLS) hoists tubulars from the V-Door position to a vertical position. The

PLS consists of the Guide Rail Assembly, Hydraulic Lift Arm with slue capacity, Carriage,

Winch and control console. The system can pick up or lay down drill pipe, drill collars or

casing joints weighing up to 7000 lbs (over 3000kg) and up to 20 inches (or 500 mm) in

diameter. The Pipe Deck Machine (or PDM) has a hydraulically controlled mechanical

arm. This arm moves tubulars between the pipe rack on deck and the drill floor. The PDM

picks up the tubular from the pipe rack, moves perpendicularly on a floor track, and then

lowers the tubular to a conveyer. The conveyer carries the pipe up to the V-Door. There,

the PLS picks up the tubular and moves it to the elevator for hoisting. Pipe transfer

systems are used on jack-ups, semi-submersible, platform and land rigs.

CONTROLS FOR EQUIPMENT

Driller’s Console

The driller controls the rig’s operations from this position at a console. The console is

usually on the rig floor, either in the open next to the drawworks or on the latest rigs in a

control house on the floor.

Weight Indicator, Gauges, Controls

One important gauge on the instrument panel is the weight indicator. It tells the driller the

weight on the bit and the hook load. The hook load is the weight that is suspended from

the traveling block and hook. Weight on bit is the portion of the bottom hole assembly

weight acting on the bit. Several gauges show the driller pump pressure, pump rate,

rotary speed, rotary torque and tong line torque. The driller’s control panel allows the

driller to operate the rotating, hoisting and mud pump equipment on the rig.

VOLUME EIGHT CASING & CEMENTING

CASING & CEMENT

Overview:

Virtually every well drilled requires casing & cement. Casing is steel pipe that the crew

puts into the well bore. The casing prevents the hole from caving in and seals off

formations. To do its job, though, the casing has to be cemented in place. A cement crew

pumps cement down inside the casing and up the annulus. The cement hardens or sets

to hold the casing in place.

Casing Specifications

Casing is steel pipe that comes to the rig in individual joints. A casing crew couples the

joints together to run them into the well bore. Casing comes in three ranges of lengths.

Range one is 16 to 25 ft (or 4.88 – 7.62m) long; range two is 25 – 34 ft (or 7.62-10.36m)

long; range three is 34-48 ft (or 10.36–14.63m) long. The length used depends on the

well owner’s requirement and the physical requirements of the well. Casing also comes in

different grades or strengths. Which strength is used depends on the well’s

characteristics.



Running Casing

To run the casing, the crew joins the joints with threaded connections called couplings or

collars. Do not confuse casing collars with drill collars. Casing collars are couplings. They

use special heavy-duty elevators and large casing slips, called spiders. They make up

the casing joints with multi-speed power casing tongs. Power casing tongs not only screw

the threaded connections together, but also torque them to the correct amount.

[TOOL BOX]: Which of these is a casing collar? Click on the casing collar with your

mouse and then click on the “accept” button.

CASING STRING

Overview

By the time the crew drills the well to final depth, it usually has several strings of casing in

it. These strings are called conductor casing, surface casing, intermediate casing and

production casing. Notice that the cased well looks something like a telescope pulled out

a full length. That is as the crew drills the well deeper, the size of the hole and the size of

the casing gets smaller in diameter. Almost or always, the drilling contractor can not

begin drilling at the surface and go all the way to total depth in one step. For one thing,

formations near the surface tend to crumble and cave in easily, so conductor casing

prevents cave-ins. For another thing, formations near the surface may also hold fresh

water that the well can not contaminate. So surface casing protects fresh water zones.

For still another thing, deep formations are sometimes so-called troublesome formations.

That is they can be drilled by adjusting the properties of the drilling mud, but once drilled

need to be sealed off to prevent problems in drilling the deeper portion of the well. So

intermediate casing seals off troublesome zones. Sometimes deep wells require more

than one intermediate casing string. Finally, once the producing zone is drilled, it needs

to be protected and sealed. So production casing isolates the producing zone.

[TOOL BOX]: Here are all of the casing strings unlabeled. To the right you’ll see all of the

labels. Using your mouse, drag each label to the proper place on the diagram. When

you’ve finished, click on the “accept” button.

PROGRESSIVE CASING STRINGS

Conductor Casing

The first string of casing is the conductor casing. The hole drilled for is pretty big, often as

much as 36 inches or more (almost a meter in diameter). The conductor hole has to start

up pretty big because as drilling goes on, the hole’s diameter decreases. In some cases,

the rig will hammer the conductor casing in place if the ground near the surface is really

soft. If the conductor hole is drilled, the casing is cemented in it. Using a bit whose

diameter is small enough to easily go inside the conductor casing, the rig drills the hole

below the conductor to a prescribed depth.

Surface Casing



The diameter of the surface hole can still be relatively large, say 17 inches (over 400 mm

or even more). The surface hole’s depth is usually set by Regulatory Agencies. They

require that the surface hole be drilled through all fresh water zones, and the surface

casing be set and cemented to protect the zones from damage by additional drilling

operations.

This step could be from hundreds to thousands of ft or meters. Normally crew members

nipple up or connect the BOPs to the surface casing at the well head. So this casing

must be strong enough to support the BOP stack. In addition, it has to withstand the gas

or fluid pressures the well may encounter. Surface casing also has to be strong enough

to support the additional casing strings hanging inside of it.

Intermediate Casing Strings

To drill the intermediate hole, the operator chooses a still smaller in diameter bit which

easily fits inside the surface casing. A bit of about 12 inches (or 300 mm) in diameter is

one example of the size. Intermediate casing is also cemented in the place to seal off

troublesome formations like lost circulation zones or abnormally pressured zones. It is

often the longest section of casing in the well. Also the crew connects or nipples up the

BOPs to the top of the intermediate casing by using an adapter and casing head or a

drilling spool which is stacked on or connected to the top of the surface casing well head.

It therefore anchors the BOPs for the drilling comes later. Remember that the crew has to

nipple up a stack of BOPs to each string of casing that’s run into the well. First, they

nipple up on the surface casing, then on the intermediate casing, and finally on the

production casing. To drill to final depth below the intermediate casing, the rig owner

selects a bit whose diameter is small enough to fit inside the intermediate casing, say

from 8 to 10 inches (or 200-250 mm).

Production Casing Strings

This part of a hole penetrates the producing zone. When cemented in place, production

casing seals off the production zone and readies it for production. Production casing also

houses and protects the tubing and other equipment used to produce the well. The

operator usually perforates, puts holes in this casing when the well is complete, already

for work to begin. Well completion is the term describing the activities and methods of

preparing the well for production of oil or gas. Oil and gas flow into the well through the

perforations.

Liner Strings

Sometimes well owners run liners instead of casing into the well. A liner is a shorten

string of casing used to case the smaller open hole section below an existing casing

string in the hole. It’s just like casing, except that a liner does not run all the way to the

surface. Instead, the casing crew hangs it from the bottom of a previously run casing or

liner string using a special piece of equipment called a liner hanger. In this case, there is

an intermediate liner and a production liner. Using liners saves money since they do not

extend to the surface.



[TOOL BOX]: For each type of casing you see, you’ll be given the diameter. Using your

mouse, click on the correct name of the casing shown.

CASING ACCESSORIES

Overview:

Because the crew will cement the casing string in place, they also have to install some

special devices on this string, which come to play during the cementing operation.

Guide Shoe

The guide shoe is a heavy steel and concrete fitting that the crew makes up on the end of

the first casing joint to go in the hole. It guides the casing pass the rough spots and

ledges on the well bore. It also has an opening in the end. Drilling mud enters this

opening when the crew runs the casing into the well bore. Later, cement will come out of

this opening on its way into the annulus.

Float Collar & Shoe

Usually, the crew installs a float collar in the second or the third casing joint run into the

well bore. Or sometimes they install a float shoe. Whether a float shoe or a float collar is

used, each has a one-way valve in it. Fluids can flow downwards through the valve, but

can not flow upward pass the valve. The float collar or float shoe keeps drilling mud from

entering the casing string as the crew runs it into the hole.

Keeping the casing empty of mud allows the casing to partially float in the mud. That is,

in the annulus, just as a hollow steel boat floats on water. Letting the casing float cuts

down on stress and fatigue on the hoisting equipment. But the crew can not keep the

casing totally empty of mud. If they did, the hydrostatic pressure of the mud in the

annulus could crash the casing. So from time to time, the crew puts mud into the inside of

the casing from the surface to offset hydrostatic pressure. The float valve also holds the

cemented place once it is displaced into the annulus; otherwise it would u-tube, back into

the casing.

Centralizers

On various joints of casing, crew members also install centralizers. Centralizers keep the

casing from leaning against the side of the hole. In other words, centralizers keep an

opening between the outside wall of the casing and the wall of the hole. Centralizers

reduce drag and differential sticking while running the casing. Drag is resistance to

motion caused by the casing contacting the well bore. Differential sticking happens when

the casing contacts a permeable formation in the well bore. And the pressure in the hole

is greater than the pressure in the formation. The higher hole pressure tenses the hole

the casing in contact against the area of lower formation pressure. Keeping the casing off

the wall off the hole also ensures that cement will surround the outside of the casing and

bond it securely to the hole.

[TOOL BOX]: In order for the cement to fill the annulus properly, it is important that the

casing string be as centered as possible. Click on the button marked, add centralizers to



see the effect of centralizers. Here you see a casing string that has zero percent standoff,

this means that it’s up against the side of the well bore. Change the standoff to see how

standoff effects cementing. 50 percent: This string has a 50% standoff. As the cement

flows up the annulus, it will fill the wider side of the annulus more quickly. This leads to an

inadequate cement job; 75 percent: This string has a 75% standoff. 67% standoff is the

minimal acceptable standoff. So it’s 75%, this cement is adequate. However, it’s not

optimal; 100 percent: Here the string has a 100% standoff. That means it is perfectly

centered. At 100% standoff, the cement flows evenly on both sides of the casing, leading

to a good cement job.

Scratcher

Another device that helps ensure a good bond of cement to the hole is a scratcher.

Depending on the well bore’s characteristics, crew members install several on the casing

string. Just before they pump the cement into the casing in hole, they rotate the casing

string. When move it up & down, that is reciprocate it. Depending on the type of

scratchers they install. In either case, the scratchers remove wall cake left by the drilling

mud during drilling. Removing the wall cake, solid particles in the mud is stick to the wall

of the hole, helps the cement bond better to the hole.

[TOOL BOX]: Let’s see what happens when the cement does not bond properly to the

hole. Click on the buttons to compare a good cement job to a bad one. GOOD: The

cement in this well bore is properly bonded; the production fluids enter the casing through

perforations, and flow up the casing to the surface. Fluids and gas from other formations

are not allowed into the well. BAD: The cement in this well bore is not properly bonded to

the hole. This creates channels that allow the fluids & gases from formations besides the

one being produced to enter the annulus. This is undesirable since the well and other

formations can be damaged.

CEMENTING

Overview

Here is an overview of casing cemented in a well, called primary cementing, the cement’s

main jobs are to completely isolate or totally seal off all the oil, gas and water zones from

the well bore, and to bond the casing firmly to the wall of the hole.

Casing Point

Here, the crew has drilled the well to the casing point, the depth at which they’ll set and

cement casing.

Conditioning the Hole

The driller circulates drilling mud to clean the hole and make sure the mud is in good

condition. Then the crew pulls the drill string out of the hole.

Running the Casing

The next step in primary cementing is for the casing crew to run the casing into the well,

one joint at a time. Notice that at the bottom of the casing, the guide shoe and float collar.



Also notice the centralizers and scratchers. The guide shoe guides the first joint of casing

into the well bore. A valve in the float collar lets the crew float the casing into the well to

lessen the load on the rig’s hoisting system. Centralizers keep the casing off the wall of

the hole to ensure a good cement job. And scratchers remove wall cake to ensure a good

cement bond to the wall of the hole.

Mixing the Cement

The cementing crew next to ready the cementing unit. The cementing unit rapidly mixes

water, dry cement, and special additives to the cement to make a liquid cement slurry. A

high pressure cement pumping unit moves the slurry down the casing.

Pumping Cement

To get the cement slurry down the casing, the cementing crew makes up a cementing

head, also called a plug-retainer, on the top joint of casing suspended in rig’s elevator.

The cementing head has an inlet for the cement slurry from the cement pump. Slurry

enters the head at the connection on the side. The valves on the head allow the crew to

control the point at which the slurry enters the head. From the cementing head, the slurry

goes into the casing. The head also holds special plugs called wiper plugs. The wiper

plug retainers keep the wiper plugs in head until the crew releases them to allow the

plugs to be pumped down the casing. The fluid inlet allows the crew to pump mud, water

or special displacement fluid, the fluid that pushes the cement into the annulus. This

head holds two wiper plugs, a bottom wiper plug, and a top wiper plug. The bottom plug

goes into the casing first. It wipes mud off the inside of the casing and separates the mud

from the cement. The top plug follows the last of the cement into the casing. It wipes

cement off the inside of the casing and separates cement from the displacement fluid.

[TOOL BOX]: Often the wiper plugs are identified by different colors to avoid confusion.

The bottom plug is usually red or orange. It has a diaphragm that breaks when the plug

gets to the bottom of the casing string; so that the cement can pass through the plug. The

top plug is usually black.

Finishing the Job

Cement pump pressure moves the cement slurry to the cementing head where a crew

member releases the bottom wiper plug. Slurry pushes the bottom plug down the casing

until it seats in the float collar. When the plug seats, continued pump pressure on the

slurry raptures the diaphragm on the bottom of the plug. This allows cement slurry to go

out the guide shoe and into the annulus. When the calculated amount of cement slurry

has been pumped, a crew member releases the top wiper plug. Displacement fluid forces

the top wiper plug down the casing until it seats in the float collar on the top of the bottom

plug. Because the top plug is solid, pump pressure rises when the plug seats. A sharp

rise in pump pressure signals the pump operator to shut down the pump. The float valve

holds the cement in place, not allowing it to u-tube back into the casing once it is

displaced into the annulus. The cementing job is complete. Depending on hole conditions

and the type of cement used, the cement slurry hardens or sets up firmly generally with



12 to 24 hours.

VOLUME NINE WELL LOGGING, MUD LOGGING & DRILL STEM TESTING

WELL EVALUATION

Overview

One question that often faces the well owner is “will this well produce oil and gas?” To

help answer this question, one or more methods of evaluation are used including: Mud

Logging, Well Logging and Drill Stem Testing (or DST). Mud logging involves doing tests

on the drilling mud and cuttings circulated out of the hole; well logging is the recording of

information about subsurface geologic formations; drill stem testing is a way to test a

formation using the drill stem, a special tool & packer assembly installed in the drill stem,

records down hole pressures and temperatures and retrieves fluids examples.

MUD LOGGING / TESTING 1

Mud Logging & Testing

As the bit drills, drilling mud lifts cuttings up the hole. The drilling mud also carries traces

of any hydrocarbons & other substances the hole may have penetrated. Therefore,

catching and analyzing the mud and the cuttings that come to the surface can tell the well

owner and geologist a great deal about what’s going on down hole as the bit drills.

Analyzing the drilling fluid is called mud logging.

Mud Logging Unit

An overview of a land rig shows the mud logging unit. Offshore, a similar skid-mounted

unit houses the mud logging equipment. Both contain sophisticated data acquisition

system and equipment for analyzing drilling fluid & cuttings. Here is the inside of a mud

logging unit. You can see some of the equipment used to analyze or log mud. This

drawing of a mud logging unit shows many items of equipment used to analyze and

monitor the drilling process. Not all rigs will have such a set-up and some will even have

more sophisticated set-ups.

Rig Monitors

Rig monitors give read-out to the mud logger, a person whose specialty is observing and

analyzing mud & cuttings. The rig monitors show the rate of penetration (or ROP), how

fast the bit is drilling, weight on the bit (or WOB), total hook load, Kelly or top drive height,

rotary speed (or RPM), rotary torque (the twisting force on the drill string), pit volume (the

level of mud in the mud tanks), mud weight (in and out of the hole), mud temperature,

pump strokes, casing & stand pipe pressure, and other information. Mud loggers can

combine rig information with other information from the driller, the wire line operator and

area well records to help improve the well’s progress.

Chromatograph

A chromatograph displays the percentages of hydrocarbon gases in the mud returning to



the surface. The chromatograph has sensors in the mud return line. These sensors

detect such gases as methane, ethane, and propane that maybe in the mud.

Core Plugging Apparatus

The core plugging apparatus takes a small plug out of a core sample. The mud logger

can analyze the plug to get an idea of what the larger core sample may contain.

Fluoroscope

A fluoroscope contains an ultra violet lamp. When the mud logger or geologist puts

cuttings or plug under the fluoroscope, the cuttings or plug glow or fluoresce if they

contain hydrocarbons.

Microscope

A microscope, this unit has two, helps the mud logger or geologist identify the formations.

By looking at cuttings or plugs under the microscope, the loggers can note very small

rock characteristics, they may also find fossils that help identify the rock.

[TOOL BOX]: A fossil is the remains or impressions of a plant or animal of past geological

ages, that’d been preserved in or as rock, because certain kinds of fossils tend to occur

in certain kinds of rock. Identifying the fossils helps identify the rock.

Computers

Computers help mud loggers analyze and interpret an important information they gain

from mud logging equipment. In some logging units, powerful computers directly read

drilling information, process it, and print out detail reports on the status of the well.

Vacuum Oven

Mud loggers use a vacuum oven to dry up formation samples. Then they evaluate the

dried samples for further facts about the formations being drilled.

Mud Logging & Testing 2

Core Heat Sealer

Geologists use a core heat sealer to make an air-tight container for cores. The heat seal

air-tight container keeps any formation fluids in the core from leaking out while it is being

shipped to a core laboratory for analysis.

Analytical Balance

Loggers use an analytical balance to accurately weigh rock samples. They calculate a

rock’s density & porosity from exact accurate weight.

Porosimeter

A porosimeter measures rock porosity, the amount of pore space in a rock. The more

pore space a rock has, the more space available for the rock to store oil and gas.



[TOOL BOX]: Formation fluids such as oil, water & gas can flow through rock formations

when the rock has empty spaces or pores and the spaces are connected (permeable).

Click on the magnifying glass to get a closer look at the pore spaces. The ratio of the

volume of empty space to the volume of solid rock is called porosity. The measure at the

ease at which the fluid flows is called permeability.

Gas Analyzer

Loggers use a gas analyzer to examine samples of gas from the well. Gas analyzers not

only indicate what kind of hydrocarbon gases the mud brings up, but also non-

hydrocarbon gases, such as hydrogen sulfide and carbon dioxide.

[TOOL BOX]: Gas that has hydrogen sulfide in it is called sour gas; gas that contains little

or no hydrogen sulfide is called sweet gas.

X-ray Diffractometer

An X-ray diffractometer penetrates a rock sample with x-rays. Different types of rock

react differently to the x-rays, which allows well loggers to identify a rock’s structure.

Centrifuge

The centrifuge spins formation fluid samples at a high-rated speed. Loggers put the fluid

samples into a test tube and then put the test tube into the centrifuge. The spinning or

centrifugal motion separates the fluid into its components. The heaviest components

(usu. water) collect on the bottom of the tube, the lighter components (such as oil) collect

in the tube above the water.

Dry Sample Tray

A dry sample tray holds dry rock samples. Loggers put dry samples on the tray and then

place the tray under the microscope where they examine the samples. Microscopic

examination of dried samples tells loggers and geologists much about a formation’s

characteristics.

HCL Testing

Mud loggers use hydrochloric acid or HCL to test for limestone. If the logger puts a drop

of hydrochloric acid on a sample and the sample bubbles up or fizzes, then the sample

contains limestone. Limestone sometimes holds hydrocarbons.

Mud Logs

This is a computer-generated mud log, and it’s most basic. The log records the rate of

penetration, percent hydrocarbons found in the mud at various depths, and the

percentage of rock types in samples caught at the shale shaker. The log may also record

other well characteristics to help the well owner drill the well efficiently and safely.

[TOOL BOX]: What would you use to find out if cuttings contain hydrocarbons?



WELL LOGGING

Overview

In most wells, the owner orders a well log. A well log can review whether there is enough

oil or gas in a formation to go to the expense of running and cementing production casing

to complete the well.

Basic Logging Operation

To log a well, the well owner usually calls a well logging company. On land rigs, the

logging company sends a truck-mounted logging unit to the well. Offshore, the logging

unit is usually permanently installed on the rig. In either case, the logging unit lowers a

logging tool on conductive wire line into the well to the depth of investigation. The unit

then reels in the tool. As the tool comes up the hole it detects certain aspects of the

formations it passes. It sends this information up the conductive wire line to the surface.

On the surface, computers in the logging unit record the information. The computers then

print out the information, print a log that the well owner can examine. Often the log gives

enough information for the well owner to determine whether oil or gas exists in the

formation.

Logging Unit

Here is a logging truck, it contains the computers, the wire line on a reel and the controls

that make the logging operation work. Offshore, instead of a truck, the equipment is

installed in a small house, a logging unit.

Logging Unit Details

The logging unit, whether truck-mounted or skid-mounted, houses conductive wire line on

a reel, wire line controls which allow an operator to lower, stop and raise the wire line,

and the computers that record and display the information relay from a logging tool

through the conductive wire line.

Logging Tools

The well owner can choose from many types of logging tools. Plus, the owner can run

some of the tools in combination. Logging companies group logging tools into four broad

areas: electric, nuclear, sonic, and other.

Electric Log

Electric logging tools measure and record certain electrical properties of the formation.

This is a recording, a log, made by an electric logging tool as it came up out of the well,

passed the formations. The squiggles on the log called curves. Notice that the curves

move to the left and to the right on the log. This is called deflection. A person familiar with

these curves can look at the way they deflect and learn a lot about the formations.

A basic premise of the sample listed electric logs is that the salt water conducts electricity

considerably better than oil. Thus a formation containing oil deflects the log’s curve

different from a formation containing salt water.



Nuclear Log

A nuclear log, sometimes called a radioactive log, looks a lot like an electric log because

it has curves that deflect left & right. Nuclear logs measure either natural or induced

radiation in the formation. Natural radiation can indicate the type of rock and its density.

Bombarding the formation with a low level radioactive source and a logging tool can

indicate whether liquids or gases are in the formation.

Sonic Log

A sonic log records the time that it takes sound to travel through a formation. A sonic

logging tool creates a sound that hits the formation rock near the tool. Sound moves

faster through solid rock than through rock that has fluid filled pores. The curves record

the travel times, and allow an expert to determine whether the rock is solid or fluid-filled.

If fluid-filled, the fluid might be oil or gas.

Other Logs

Many other logging tools are available. A common one is a caliper log. This log shows

the diameter of the hole and any irregularities in it. One thing caliper logs can do is help

the cementing crew determine the volume of the hole. With hole-volume known, the crew

knows how much cement they will need to properly cement the casing.

DRILL STEM TESTING

Overview

In addition to logs, the well operator will sometimes order a drill stem test. The drill stem

test, or DST, temporarily produces hydrocarbons through the rig’s drill string or stem.

DSTs also measure and record formation pressure and temperature data. To determine

formation permeability and the makeup of hydrocarbons, the well owner may run a drill

stem test, DST tool. The crew runs this assembly on the drill string, or the drill stem as is

sometimes called. The test evaluates a selected test zone. While qual. logging, DSTs

help well owner decide whether to run casing and complete the well. A DST tool lets

formation fluids flow to the surface or sometimes into a sample chamber inside the down

hole tool. While the well flows, the well owner can determine the producing

characteristics of the well. Such information allows the owner to produce the well more

efficiently when completed.

DST Tool Components

Here is a drill stem test tool, made up on the bottom of the drill stem. From top, it has a

reverse circulation sub, shut-in valve, hydraulic bypass, recorder, hydraulic jar, safety

joint, packer, perforated pipe and an anchor shoe. The crew lowers this assembly to the

depth the well owner wants to test, in this case, the bottom of the hole. You’ll see what

the parts do as you go along.

[TOOL BOX]:Let’s see if you can build a DST tool from a bottom up. Here are the label

parts of the DST. Using your mouse, drag each component into place in the proper order.



Lowering DST Tool

The crew lowers the DST tool into the hole on the drill pipe after the well is well-circulated

and conditioned with drilling fluid. The hydraulic bypass is open, because the DST packer

has limited clearance with the upper casing in open well bore. The open bypass allows

drilling fluid in the hole to flow up inside the tool as the crew lowers it. Letting drilling fluid

flow up inside the tool prevents it from creating pressure surges. Pressure surges could

fracture the formation to be tested.

Sealing the Hole

With a DST tool on the bottom, the driller slacks off the drawworks’ brake to put weight on

the tool. Weight causes the packer to expand. The packer seals off the hole beneath it.

With the hole sealed by the expanded packer, the DST operator rotates the drill string.

Rotation opens ports inside the DST tool. With the ports open, formation fluids flow into

the tool and to the surface. During this time, crew members closely monitor annulus

pressure. They monitor annulus pressure to make sure the packer maintains a good seal

between the hole section being tested and the annulus above the packer.

Water Cushion

The test crew puts water into the drill pipe above the DST tool. This is a water cushion.

The water cushion supports the drill pipe against mud pressure in the annulus, until the

test starts. The water cushion also puts hydrostatic pressure on the formation when the

DST tool ports are open. The hydrostatic pressure is however, not enough to keep the

formation from flowing into the DST tool. The water cushion is just that, a cushion. It

keeps the formation fluids from surging with great force into the tool and the drill string. If

allowed to surge, the force could damage the recording instruments and the tool and the

formation rock.

Fluid Flow

With the ports open in the DST tool, formation fluids flow. They push any drilling fluid in

the hole below the packer into the tool. Then they flow up the tool and the drill string to

the surface. The test crew first lets the well flow for a short time to clear out the drill stem.

They then shut in the well for a time to allow pressure to build. The well owner then

allows the fluid to flow for a few hours of for several days depending on the well.

Produced fluids are contained in a holding tank or burned off if they reach the surface.

During the flow period, the owner determines the well’s production potential and fluid

properties.

Pressure Charts

After letting a well flow for the required time, the test crew closes the shut-in valve by

rotating the drill string. The flow of formation fluids stops. With flows stopped, formation

pressure builds up inside the tool. This pressure build up is recorded on a pressure chart

in the tool. Later the well owner examines the chart on the surface. The record of the

pressure build up rate gives information about the permeability and size of the formation.



[TOOL BOX]: Permeability is the quality of a formation that allows oil and gas to flow

through the pore spaces of rock. Highly permeable formations allow fluids to flow easily.

A formation with low permeability is called “tight” formation. It is harder to produce than a

formation with high permeability.

Reverse Circulating

To remove the DST tool from a hole, the driller first opens the reverse circulation sub.

The driller usually opens the reverse circulation valve hydraulically by pumping drilling

fluid down the annulus. This increased pressure in the annulus opens the sub. With the

sub open, drilling fluid reverse circulates down the annulus and up the tool and drill string

to the surface. Reverse circulation pumps the remaining formation fluids out of the drill

stem and puts drilling fluid back in. The drilling fluid kills the well, that is the drilling fluid

once again keeps the formation pressure under control.

Removing DST Tool

To pull the drill string & DST tool from a hole, the driller first releases the packer by

easing up on a string. If necessary, the driller uses the built-in hydraulic jar to jar on the

DST tool. In most cases, jarring loosens the packer and frees the tool. If the driller can

not pull the packer free for some reason, he can separate the tool at the safety joint.

Removing the tool above the safety joint gets all of the tool above the packer, including

the recorder with its data.

VOLUME TEN POWER SYSTEM & INSTRUMENTATION

POWER SYSTEM

Overview

There’re three basic ways a rig distributes or transmits power: an AC to DC power

system, or SCR power system, a DC to AC power system, and a mechanical power

system. At the heart of every rig power system, whether electrical or mechanical, is the

prime mover. A prime mover is the rig’s main source of power. Most rigs have more than

one prime mover. Prime movers are almost always large and tumult combustion engines.

Some equipment on the rig requires hydraulic power and pneumatic power. The rig’s

hydraulic & pneumatic systems also obtain their power from one of the three basic

distribution systems.

[TOOL BOX]: Just what is power and how is it measured. Well, to understand power, we

have to understand force and work. Think about a force is a push or a pull. If a constant

force is applied over a distance, we have work. Work = Force X Distance. Power is the

amount of work done per unit of time. See these horses pulling their loads, the top one is

moving much slower than the second. But by the time they’ve gone the same distance,

they’ve done the same amount of work. The bottom one though, finished five times

quicker than the first. So it did five times as much work per second as the top one. That

means the bottom horse delivered 5 times as much power as the top one.



Prime Movers

Large diesel engines are the main power source, the prime movers, for most rigs. These

engines often produce from 500 to over 8000 hp (or 350-5600 KW). Rig builders usually

house several engines together to drive the rig’s equipment. They also keep extra engine

sets available for back-up engines. Most rig engines are diesel, because unlike gasoline

engines, they can produce a lot of power when running slow. Also diesel fuel is not as

volatile as gasoline, so it is safer to use, transport and store.

[TOOL BOX]: A diesel engine takes chemical energy or fuel and converts it to mechanical

energy, rotational force to power the rig equipment.

AC to DC Power System

Here is an AC to DC power system. The prime mover, usually a diesel engine, supplies

power to the AC generator, also called an alternator. From the AC generator, AC current

is sent to the SCR (the silicon controlled rectifier). An SCR is a high-tech solid state

electric device. The SCR converts AC to DC current, which drives the heavy rig

equipment, such as the mud pumps, the drawworks, and the rotary system. Auxiliary

loads such as small pumps and rig lighting need lower voltage AC power, so a

transformer steps down or reduces the voltage to the rig’s auxiliary electric equipment.

DC to DC Power System

Here is a DC to DC power system. The prime movers, usually diesel engines, power DC

generators. From the generator, DC current goes through a control panel directly to DC

motors. The DC motors power the mud pumps, the drawworks, and the rotary system. A

smaller AC generator is also part of the system. It supplies AC current for equipment that

works best with this current type, for example, a chemical mixing pump requires AC

power.

Mechanical Power System

Here is a mechanical rig system. Mechanically powered rig’s usually smaller than those

rigs which use electric power. The prime mover drives a mechanical compound

transmission, which in turn, powers the drawworks, the rotary table, and the mud pumps.

Auxiliary loads such as small motors are supplied with AC from an alternator connected

to the prime mover.

AC to DC POWER SYSTEM

Overview

Alternating current put on by the AC generators goes through heavy-duty electric cables

to a special device called silicon controlled rectifier (or SCR). The SCR converts AC to

DC. Other heavy-duty electric cables carry DC electricity to the DC motors. The DC

motors convert electrical energy back into mechanical energy to drive the powerful

hoisting, rotating and circulating equipment.

Diesel & AC Generator



Rig owners like to use AC generators because they can be built to be very powerful for

their sizes, which is an advantage over DC generators. Also rig equipment can distribute

AC easier than DC. But direct current has certain advantages when driving large

equipment. Mainly DC motors produce a lot of torque at low speed that the drillers can

easily control. Using remote switches on this console to control the SCR control panel,

the driller can select and deliver the power from the various generators wherever it is

required. But some AC generators power big motors. In fact, most of today’s diesel

electric rigs use AC generators and a system called an SCR power system. Here, a large

AC generator, an alternator, is connected to the diesel engine prime mover. As the

engine mechanically drive the AC generator, the generator produces alternating current,

or AC electricity. AC is like the electricity used in most cities and homes.

[TOOL BOX]: Remember, an electric generator or alternator takes mechanical energy

and creates electrical energy. An electric motor does just the opposite. It takes electrical

energy and creates mechanical energy.

SCR Switch & Control Gear

Equipment in this electrical cabinet converts or rectifies (as the electric term) most of the

AC current produced by the AC generators into direct current. As mentioned before, rig

owners usually prefer DC current for driving the very large equipment that requires

precise variable speed control and high torque. The control equipment includes solid

state electrical components called silicon controlled rectifiers or SCRs. Heavy duty

electrical cables come out of the cabinet and carry DC electricity to the powerful motors,

driving the circulating, hoisting and rotating equipment.

DC Motors

Usually large DC motors supply power to the mud pumps, the drawworks, and the rotary

table or top drive. Sometimes the drawworks mechanically drive the rotary table, but on

some rigs the rotary table has its own motor. The driller can control the speed of a DC

motor very accurately, which is why rig owners use DC instead of AC motors. With

accurate speed-control, the driller can accurately set the speed the drawworks slips, the

mud pump operates, and the rotary table turns on rigs without a top drive.

AC Motors

Various small components on a rig need power, too. For instance, these two centrifugal

pumps move mud from a tank to supercharge the intake of the mud pumps. In this case,

it is more efficient to use small motors to power the centrifugal pumps rather than using

the prime movers, hydraulic fluid or air. Here is another AC motor; it powers the paddles

on the mud agitator in a mixing tank. AC motors generally power equipment that does not

require a lot of horsepower. So they vary in power from less than 1 hp (or .75 KW) to

more than 150 hp (100 KW).

[TOOL BOX]: Here is a chart covering the uses of advantages of AC & DC motors. Drag

each test box to its proper place on the chart, then click on “accept”.



DC to DC POWER SYSTEMS

Overview

For electric power distribution, some rigs use DC to DC power. DC to DC was the first

electric power system. In a DC to DC system, each engine drives a DC generator. The

DC generator converts the rotating mechanical energy of the diesel engine into DC

electricity. Heavy duty electrical cables carry DC electricity via the control panel to large

1000 hp (or 700 KW) DC motors. The motors convert the electricity back into mechanical

energy. This mechanical energy powers the hoisting, rotating & circulating equipment.

DC Motors

For large equipment, most rig owners prefer DC motors over AC motors. DC motors put

out high torque (twisting force) at low speed. Further, the driller can easily control the

torque from his console on the rig floor. Keep in mind, though, that recent technological

advances are allowing computerized controls and variable speed AC motor drives to be

used where only DC motors were used in the past.

AC Generator (Alternator)

This is a generator (or alternator) on a DC to DC rig. It generates the AC electricity that

DC to DC rigs need. The alternator powers smaller equipment on a DC to DC rig, like the

small AC motors on centrifugal pumps, air conditioners, lights, fans, water-maker units

and other small equipment.

[TOOL BIX]: Which of these two motors do you think is an AC motor? Select one and

then click the “accept” button.

MECHANICAL DRIVE POWER

Overview

Mechanical drive rigs normally compound (or connect) two or more engines to drive the

main pumping, rotating and hoisting equipment. Generally small to medium size land rigs

use mechanical drives. They use clutches, converters, chains, shafts, belts or

compounding transmissions to connect the prime movers to the driven equipment. Here

is a common way to get power to the components on a mechanical drive rig. This shows

three engines that the rig owner compounded. That is the power from each engine goes

through a series of sprockets and chains & housing, called a compound. The compound

transfers engine power to the drawworks, the rotary table, and the mud pumps.

[TOOL BOX]:

You’ve probably notice that the engines and motors are commonly rated according to the

amount of power they produce in horsepower or kilowatts. Power is the amount of work

performed over a period of time. In the English system of measurements, power is often

measured in foot-pounds per second. One foot-pound per second is the amount of power

that would lift a one-pound weight one foot off the ground in one second. Click on the

weight with your mouse to lift it. One horsepower is equal to 550 foot-pounds per second.



So one horsepower is the amount of power that would lift 550 foot-pounds one foot off

the ground in one second. Click on the weight. In the metric system of measurements,

power is often measured in joules per second. A joule is equivalent to one Newton-meter.

One joule per second is the amount of power that would lift a .102 kg object one meter off

the ground in one second. Click on the weight with your mouse to lift it. One horsepower

is equal to 746 joules per second. So one horsepower is the amount of power that would

lift a 76.1 kg object one meter off the ground in one second. Click on the weight.

Compound Drive

In a compound drive, engine power usually goes through torque converters to the

sprockets & chains. Steel guards cover the sprockets & chains, removed here so you can

see them. Torque converters smoothly transfer engine power to the compound. Here you

can see the steel guards covering the machinery in the compound. Not only do the

guards protect personnel, they also keep a lubricating oil spray confined to the chains &

sprockets. Also, note that large V-belts called power bands drive the mud pumps. Steel

shrouds also guard them.

HYDRAULIC & PNEUMATIC POWER SYSTEM

Overview

Many tools use hydraulics to transmit power. Examples include the Kelly spinner, the Iron

Roughneck, and casing tongs.

Hydraulic Force

Hydraulics means transmitting power by pushing on a confined liquid. Here is a piston

moving inside a cylinder. Hydraulic fluid fills the cylinder to the left of the piston. The

piston’s surface area is 10 in2. If a pump puts 1000 pounds per square inch (or psi) of

hydraulic fluid pressure on one side of the piston, this 1000 psi acts on the 10 in2 piston to

produce 10000 lbs of force. That’s a lot of force available for powering certain tools and

equipment.

Hydraulic Power Pack

Here is a typical hydraulic power pack used on many rigs. It has an electrical motor or

internal combustion engine to power the high pressure pump. The pump takes hydraulic

fluid from the reservoir and sends it out a high strength steel-reinforced hose to the

devices needing hydraulic power. The fluid returns to the reservoir after it passes through

the Kelly spinner or other tool. The hydraulic power pack is a closed system; the fluid is

used over and over.

Pneumatically Powered Equipment

Certain controls, valves and tools on the rig are air of pneumatically operated. For

instance, the driller uses pneumatic controls on the driller’s console to engage &

disengage clutches on equipment like the drawworks. The rig crew may use air-powered

hand tools, like a grinder. They also use an air hoist, an air powered winch, to hoist and

move relatively light equipment onto and around the rig floor. Many diesel engines on rigs



have an air starter, which is air-operated motor that turns the engine crankshaft over to

start it. Finally, a floating rig’s motion compensator operates large amounts of

compressed air to compensate for vessel heave or keeping the drill string in position.

[TOOL BOX]: Which of the rig types uses a motion compensator? Select the correct

answer or answers and then press “accept”.

Rig Air Compressor

An air compression system provides air pressure to operate the pneumatic controls,

valves & tools on the rig. Rigs use rotary screw compressors or reciprocating

compressors to compress air. A typical reciprocating air compressor has two, three or

four pistons moving inside cylinders. The compressor takes in air from the atmosphere,

and raises its pressure, that is, compresses it. The volume tanks stores a given amount

or volume of compressed air that is ready for use when needed.

[TOOL BOX]: Air, compressed 100 pounds per square inch, or 670 KPa, can be

dangerous. Care must be taken when working on or around air systems. Always wear

proper safety equipment, such as a hard hat, eye & ear protection, work clothes and work

boots. Never attempt to open a component of an air system or a section of pipe without

making sure that all of the air has been bled off first. Periodically check pressure and

temperature gauges to be sure they’re at the proper level. Also, inspect pipes and

vessels for corrosion. And be aware, if there’s a fire on the rig, any break in the air

system instantly adds oxygen from the air to fan the flames.

RIG INSTRUMENTS

Overview

A drilling rig has many instruments and gauges. They help the driller and other crew

members keep track of the drilling operation. Rig instruments vary from the most basic to

sophisticated computers with video displays. Here we’ll cover the basics.

Driller’s Console

The driller’s console is the driller’s work station on the rig floor. It has several instruments

and gauges. All of them help drillers track the drilling process and keep them informed of

the situation. Indicators and gauges on the driller’s console include the weight indicator,

the pump rate indicator, mud pump pressure gauge, rotary tachometer, rotary torque

gauge, tong torque gauge, mud return mud flow rate indicator, mud tank level indicator

and trip tank volume indicator.

Weight Indicator

The weight indicator is the largest gauge on the driller’s panel. It indicates the hook load,

and weight on the bit. The hook load is the total amount of the weight hanging from the

hook. Weight on the bit (or WOB) is the amount of weight put on the bit by the drill string.

It is less than the hook load. The weight indicator is extremely sensitive to hook load

changes. Drillers can use the hook load changes to monitor the amount of drag or friction



the well bore puts on the drill string when they move the pipe up or down. Or because it

is so precise, the driller can use it to monitor the operation of down hole tools requiring

small variations in weight.

Pump Rate Gauge

The pump rate gauge shows the number of times one mud pump piston moves per

minute. This console has two pump rate gauges because this rig has two mud pumps.

The driller can determine the total volume of mud being pumped by multiplying the pump

rate by the number of pistons in the pump times the amount of mud each piston pumps.

Pump Pressure Gauge

The mud pump pressure gauge shows drillers the amount of pressure the pump is

putting out. They monitor pump pressure from the standpipe to ensure that it is the

correct amount needed to keep the hole clean and return cuttings back to the surface.

Rotary Tachometer

The rotary tachometer shows the revolutions per minute (or rpm) of the rotary table or a

top drive unit. Drillers monitor rotary rpm because they need to know the rate the bit is

turning. Different bits rotate at different rpms. Rpm ranges for a bit are specified by the

manufacturer.

Rotary Torque Gauge

Drillers use the rotary torque gauge to see how much twisting force or torque the rotary is

applying to the drill string. Knowing rotary torque helps keep drillers from parting the drill

string because of too much rotary torque. Parting the drill string in this manner is called

“twisting-off”.

Tong Torque Gauge

A tong torque gauge helps the driller and the rotary helpers make up the drill pipe and

drill collars with the right amount of torque. Too little torque or tightness in the connection

may leak or unscrew while drilling; too much torque can damage or gall threads, which

cause them to leak and eventually to come apart.

[TOOL BOX]: These two photos show how important it is to properly torque up the

connections. Both of these connections were under torqued, which lead to severe

erosion.

Mud Return Flow Rate Indicator

Drillers use the mud return flow rate gauge as a relative indicator of how much drilling

fluid is returning at the flow line. The sensor is mounted in the mud return line, the flow

line. A paddle inside the return line moves as mud flows past it. As the paddle moves, it

sends a signal to a readout panel, mounted on the driller’s control console panel. The

driller sets the readout so that as long as return flow is normal with constant pump speed

and output, no alarm sound or lights up. However, when the return flow rate changes,



increases or decreases, the paddle’s motion also changes. This change in paddle motion

sends a signal to the driller’s readout and sounds or aluminates an alarm. A change in

the return flow rate of the mud may indicate one of the two things: if the flow rate

decreases, mud may be being lost to a down hole formation; if the flow rate increases,

formation fluids may have entered the hole and are forcing drilling mud out. So a mud

return flow rate indicator can help drillers detect kicks and loss of circulation.

Mud Tank Level Indicator

This mud tank has a special float in it. It goes up or down as the mud level in the tank

rises or falls. Usually several mud tanks have floats in them. The floats send a signal to a

digital totalizing panel mounted on the driller’s console. This panel takes the tank level

signals from all the floats in the tanks, totals them and sends the information to the chart

recorder next to the panel on the rig floor close to the driller’s console. If the level of mud

in the tanks falls and no one has removed mud from the tanks, then that it is likely that

mud is being lost to a down hole formation. If the level of mud in the tanks rises and no

one’s added mud to the system, then it is likely that formation fluids are flowing into the

well. Thus a mud tank level indicator is another tool to help the driller detect kicks and

loss of circulation.

Trip Tank Volume Indicator

A trip tank volume indicator helps the driller monitor the amount of mud being displaced

by the tubulars or wire rope being run in and pulled out of the hole. Crew members

calculate tubular displacement before each trip using tables from a handbook. Then

during a trip, they compare the calculated volumes to the actual displacement. Close

monitoring of the trip tank during trips is crucial to proper well control.

[TOOL BOX]: Here is a quick little review for you. Click on the weight indicator on this

control panel then click on the “accept” button.

Drilling Recorder

A drilling recorder makes a record of drilling variables such as the hook load, weight on

bit, rate of penetration, torque, pump strokes and pump pressure during drilling. It’s

usually located in the doghouse on the rig floor. The driller puts a chart onto the revolving

drum. Several pens with ink in them trace records onto the chart. Drilling recorders may

have from one to several pens depending on how they’re hooked up. The recorder gets

signals from sensors mounted near the gauges that measure the drilling variables. For

instance, a load cell on the dead line anchor sends its hook load and weight on bit. Here

is a photo of a drill recorder. Note that it has a hinged plexiglass cover; the drillers can

raise it to change the chart when necessary.

H2S Instrumentation

Hydrogen Sulfide, H2S or Sour Gas, is the most poisonous gas encountered in drilling

operations. It occurs worldwide in various concentrations associated with gas, oil and

water produced from wells. It is extremely toxic, explosive and heavier than air. It is also



colorless so you can not see it. In low concentrations, it smells like rotten eggs, but you

can not depend on your sense of smell to escape harm. H2S quickly deadens your ability

to smell. Where H2S may be present, rigs are equipped with sensors, automatic monitors

and alarms. This is an audible and visual H2S alarm. The horn sounds a siren or the light

flashes brightly if they’re activated by H2S sensors placed on the rig. This H2S sensors

place near the mud tanks; others may be at the bell nipple on the rig floor, shale shakers,

flow line, rig accommodation’s air intake and other places on the rig. When a sensor

picks up H2S gas above a predetermined level, the monitor triggers both the visual and

audible alarms. Upon hearing or seeing the alarm, crew members can take action to

avoid injury or death. You’ll receive detailed H2S training if your rig is working in an area

where H2S may be encountered.


Script for All 10 CDs

Documents

fixed cutter

tungsten carbide

steel tooth

hydraulic

conductive

subsea bop

rotary table

pipe handler