142559179 drillin manual drill quip

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c 1996 DRIL-QUIP, INC.

This document is the property of DRIL-QUIP, Inc and shall not be copied or used for any purpose other than that for which it is supplied without the express written authorization of

DRIL-QUIP, Inc., 13550 Hempstead Hwy., Houston, Texas 77040, U.S.A.

OFFSHORE DRILLING

AND

COMPLETIONS

TRAINING MANUAL


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How Oil and Gas Reservoirs

Accumulate

Table of Contents

Introduction ................................................................................ 1

Sedimentary Rocks ..................................................................... 1

The Formation of Oil and Gas................................................... 2

Underground Traps for Oil and Gas ........................................ 3

Anticlinal and Dome Traps........................................................ 4

Fault Traps .................................................................................. 4

Stratigraphic Traps .................................................................... 4

Salt Dome Traps ......................................................................... 5

Reservoir Pressures .................................................................... 5

Pressure Gradients ..................................................................... 5

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IntroductionThis chapter provides a general outlook of the following:

• How reservoirs of oil and gas accumulate

• How drilling for these reservoirs is done

With few exceptions, all naturally occurring oil and gas thatcomes from wells, drilled on land and offshore, is found inlayers or beds of sedimentary rocks deposited millions of years ago. The first chapter in this manual is devoted to theformation of sedimentary rocks and trapped accumulationsof oil and gas.

Sedimentary RocksSedimentary rocks, or derived rocks, are formed by the ero-sion and decomposition of uplifted land masses. Years ago,

these uplifted land masses of basement rock were predomi-nantly made up of granites and basalts formed into hills andmountain ranges. These mountains and hills were exposed tothe elements of sun, wind, rain, frost, etc. which graduallycaused small fragments of the base rocks to break off and getwashed or blown down to a lower level. Some of the minerals,such as silicates and carbonates, also dissolved and went intosolution.

How Oil and Gas Reservoirs

Accumulate


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How Reservoirs ofOil and GasAccumulate

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The natural drainage system of streams and rivers finallydeposited these rock particles and dissolved minerals intolakes, swamps, river deltas and the sea. In many cases, the beds of these lakes, swamps, river deltas and seas becamesinking sedimentary basins. This meant that more and moredeposition, or sedimentation, could take place as the bed of thesedimentary basin was sinking. As the deposits of sedimentsgot thicker and thicker, the lower layers were exposed toincreasing compressive loads called overburden and increas-ing temperatures occurred as the sediments got deeper.

Under the conditions of increasing load and temperature, thesediments became compacted. Coupled with the chemicalaction of silicates and carbonates coming out of solution, thedeposited fragments became cemented together into a com- bined rock. The cementing medium of silicon (quartz) orcalcium carbonates (calcite) make up nearly one third of thecombined rocks formed in this way.

The types of rocks formed by this process are shales, clays,

siltstones, sandstones and gravels. They are classified asclastic sedimentary rocks. This type of sedimentation androck formation has been occurring for nearly 500 million yearsand is still very obvious today. The thickness of marinesedimentary rocks have been measured in excess of 60,000feet.

The Formation of Oil and GasThis is not the only form of sedimentation that occurs. Thedecomposition of dead animal and plant life, both land andmarine, have also been taking place on a large scale in the

previously referenced sinking sedimentary basins. The or-ganic and skeletal matter from these dead animals and plants became trapped in the water borne sediments and were also buried by additional deposits of sediment and organic matter.

The most prolific source of organic matter deposited andtrapped in this manner comes from very small dead marineanimals, particularly those with protective shell structures.

Figure 1.1. Anticlinal or Dome Traps


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This occurred on such a massive scale that very thick layers of sediments were formed entirely from dead microorganismswith protective calcareous shells and skeletons. Coral reefsare an example of this type of deposit.

As these organic derived deposits were buried deeper anddeeper by subsequent layers, they were subjected to increas-ing compressive loads and temperatures. The fragments of shell and skeletons became cemented together, and the or-ganic matter consolidated. Rocks formed by this process

include limestone, dolomite, chalk and coal. Naturally occur-ring oil and gas are formed by the effects of pressure, tempera-ture and chemical and bacterial action on the trapped organicmatter in sediments that has decomposed into various con-stituents. The layer of sedimentary rock where this decompo-sition has taken place is known as the source rock.

Almost all sedimentary rocks are deposited in a water envi-ronment. As oil is lighter than water and gas is lighter than oil,it is not unexpected that these constituents will try to separate

themselves with gas at the top, oil in the middle and water atthe bottom.

Underground Traps for Oil and GasAs the majority of rocks are permeable (allow passage of fluidsand gases through interconnected pores in the rock), thenatural tendency for oil and gas is to migrate upwards throughthe permeable formations until they can escape at the surface.This process has continued slowly throughout time and is stillevident today in oil and gas seeps at the surface. This upwardmigration of oil and gas is occasionally halted by an impervi-

ous barrier (one with little or no effective permeability) or caprock. The oil and gas then start to accumulate in the rocks below the cap rock. The rocks below the cap rock are knownas reservoir rocks. A typical cap rock is very compacted withno interconnected pore space, such as a shale or clay. Typicalreservoir rocks include sandstones, siltstones and limestones.In terms of natural occurrence in sedimentary rocks, shalesaccount for about 50%, sandstones and siltstones about 25%

Figure 1.2. Fault Trap


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and limestones also about 25%. This simple picture of oil andgas formation and accumulation in neat horizontal beds of rock is complicated by movement in the Earth's crust. Thesemovements are created by massive forces of tension andcompression in the Earth's crust which have caused landmasses to separate and push up into hills and mountainranges.

Anticlinal and Dome TrapsThese movements affect the layers of sedimentary rocks caus-

ing them to form anticlinal or dome structures (upward folds).Synclines are downward folds. When these anticlines ordomes have an impermeable layer or cap rock within theirstructure, they form a very nice trap for the oil and gasmigrating upwards (Figure 1.1).

Fault TrapsEarth movements also cause the layers of sedimentary rocks totilt. Any migrating oil and gas can escape upwards throughthe tilted rock formations which ultimately become exposed

and eroded at the Earth's surface. The same forces of tensionand compression in the Earth's crust can also cause the rockformations to separate at a plane of weakness. Forming a fault,the rock formations move relative to one another along thefault plane. Sometimes this faulting in tilted sedimentaryrocks will place an impervious barrier next to the migrating oiland gas. In this manner, a fault trap is created and anaccumulation of the oil and gas can occur (Figure 1.2).

Stratigraphic TrapsAnother form of trap can be created when tilted rock forma-

tions are exposed at the Earth's surface and, in turn, areweathered and eroded by the elements. This eroded surface becomes the bed of a sinking sedimentary basin. Subse-quently, an impervious layer of sedimentary rock is laid on topof the tilted rock formation as the formations sink once again.Over time, the migrating oil and gas in the tilted formation is

Figure 1.3. Stratigraphic Trap


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trapped by the impervious layer of rock. This form of trap iscalled a stratigraphic trap (Figure 1.3).

Salt Dome TrapsAnother form of trap for oil and gas accumulations is associ-ated with salt domes. These traps are formed when a massiveplug of salt tries to move upwards through denser layers of rock. The layers of rock above the salt dome are forced into afolded structure and, with the correct layers of rock in place, atrap for oil and gas is formed. It must be pointed out that not

all salt dome structures are traps for oil and gas simply becauseoil and gas accumulations weren’t there in the first place.Historically, the very high success ratio for finding oil and gasassociated with salt domes, particularly in America, lead theearly drillers to believe that oil and gas had it’s origins in theactual salt. As explanied, this is not the case, just a popularmisconception (Figure 1.4).

What is obvious is that the erosion and the process of creatingsediments of oil containing formations is a constant cycle. All

parts off this cycle have occurred (and are still occurring)throughout history.

Reservoir PressuresThe formation of oil and gas has generally occurred at someconsiderable depth which accounts for the fact that mostreservoirs of oil and gas are under pressure. This knowledgeshould help with the understanding that drilling holes intothese reservoirs requires due care and attention. Duringdrilling operations, the reservoir pressure needs to be overbal-anced by the hydrostatic column of drilling fluid in the well

bore as the hole is drilled through the cap rock into thereservoir. A rough pressure gradient of 1/2 psi/ft. can be usedto calculate an estimated reservoir pressure. For instance, areservoir 10,000 ft. below the surface would have an approxi-mate pressure of 5,000 psi.

Pressure GradientsFresh water has a pressure gradient of 0.433 psi/ft. and sea-

Figure 1.4. Salt Dome Trap


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water has a pressure gradient of 0.443 psi/ft. Simple multipli-cation quickly reveals that a sea-water column of 10,000 ft.only exerts a pressure of 4,430 psi which is insufficient tooverbalance a 5,000 psi reservoir. This tells us that a heavierfluid is required for adequate control of the reservoir pressure.This concept is fundamental to all drilling and productionoperations and explains why pressure control of formationfluids and gases is given the highest priority in the oil industry,as oil and gas flowing out of control are extremely dangerousand potentially life threatening.


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Equipment Used in Rotary

Drilling2

Table of Contents

Introduction ................................................................................. 7

Drilling Bit ................................................................................... 9

Drill Collar Sub ........................................................................... 9

Drill Collars ................................................................................. 9

Drill Pipe .................................................................................... 10

Kelly Saver Sub ......................................................................... 10Kelly and Kelly Bushing ........................................................... 10

Kelly Cock .................................................................................. 11

Swivel.......................................................................................... 11

Travelling Block and Hook ...................................................... 12

Crown Block and Drilling Line................................................ 12

Mast or Derrick ......................................................................... 12

Support Systems ........................................................................ 13

Drilling Fluid Circulation System ........................................... 13

Mud Pump or Slush Pump ....................................................... 13

Standpipe and Standpipe Valve............................................... 13

Rotary Hose ............................................................................... 14

Bell Nipple and Return Flowline ............................................. 14

Shale Shaker .............................................................................. 14

Running and Pulling System .................................................... 15

Drawworks ................................................................................. 15

Brake System ............................................................................. 15

Rotating System......................................................................... 15Rotary Table .............................................................................. 15

Rotary Beams ............................................................................ 16

Master Bushings ........................................................................ 16

Elevators and Links .................................................................. 16

Drilling Fluids ............................................................................ 17

Top Drive Drilling ..................................................................... 19

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Equipment Used in RotaryDrilling2

IntroductionThe purpose of this section of the manual is to give a brief overview of the equipment and systems used to drill andcomplete a well for production.

As the training course continues into offshore drilling and

production, it will be seen that the equipment and systemsused on land have been adapted for offshore use but theprimary functions of the equipment have not changed at all.

Figure 2.1 is an illustration of a land drilling operation andFigure 2.2 illustrates the configuration of a land rotary drillingrig that will be used to describe the equipment involved inrotary drilling.

The primary function of the drilling rig used in the oil industryis to drill a hole that penetrates an oil or gas reservoir in a safe

and timely manner. Starting from the bottom of the hole, thedrilling bit is the business end of the whole system as it is theonly piece of equipment that actually makes hole. All of therest of the equipment can be considered as the support system;to raise and lower the bit into the hole; to rotate the bit withcontrolled weight; to flush the cuttings from the bit/rockinterface as the hole is drilled; and to provide fluid pressurecontrol as the bit penetrates beds of rock that may contain gas,

Figure 2.1. Illustration of a landdrilling operation


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2Equipment Used inRotary Drilling

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LEGEND

DRILLING FLUID

CIRCULATION PATH

Configuration of a Rotary Drilling Rig

DRILLING LINE

TRAVELING BLOCK

GOOSENECK

WATER TABLE

KELLY

STAND PIPE

ROTARY HOSE

KELLY BUSHINGS

RIG FLOOR

ROTARY TABLE

ROTARY BEAMS

KELLY SAVER SUB

SUBSTRUCTURE

GROUND

CELLAR

CEMENTEDCONDUCTOR

CEMENTEDCASING

CASING SHOE

ANNULUSRETURNS

WELLBORE

DRILL COLLAR SUB

DRILL COLLARS

STAND PIPE VALVE

KELLY COCK

SWIVEL

HOOK

DRILL PIPE

MAST OR DERRICKSTRUCTURE

CROWN BLOCK

MUD PUMP OR SLUSH PUMP

BLOWOUT PREVENTER STACK

CASING HEAD

BELL NIPPLE

RETURN FLOWLINESUCTION PIT

SETTLING PIT

SHALE SHAKER

Figure 2.2

DRILLING BIT


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2 Equipment Used inRotary Drilling

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oil or water at high pressures.

Drilling BitThe most common bit used in rotary drilling is the roller cone bit and its most common form is the three-cone, or tri-cone, bit.Each roller cone is equipped with teeth that chip off fragmentsof the rock as the bit rotates and the roller cones roll over the bottom of the hole.

The resulting chips or cuttings have to be cleared from the

drilling face. This is accomplished by the circulation of thedrilling fluid down through the inside of the bit, and back tothe surface in the annulus return.

Many improvements have been made to roller cone bits overthe years including the introduction of nozzles, or jets, thatutilize teeth with hardened inserts and larger and better bearings. All of these improvements have been made in orderto increase penetration rates and extend the life of the bit.

The bit has a threaded pin up. This connection is threaded forright-hand make up, with the thread being very coarse andrugged, machined on a taper. This form of tool joint is verycommon in drill pipe, drill collars and drilling assemblies.

Drill Collar SubThe next piece in the drilling assembly is a short, heavy-walledpipe section with a tool joint box up/box down configuration.This short section of heavy-walled pipe is called a drill collarsub, or substitute, and is made up to the tool joint pin of thedrilling bit.

Drill CollarsThe next section of the drilling assembly is made up of drillcollars. Drill collars are usually 30' heavy-walled, high-gradesteel pipe that have right-hand tapered tool joints in a box up/pin down configuration which is the most common way thatoilfield tubulars are used.

Figure 2.3. Photo of a typical drillingbit

Figure 2.4. Illustration of two typicalbottom hole assemblies

STABILIZER

DRILL COLAR

STABILIZER

DRILL COLLAR

STABILIZER

BITBIT


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The number of drill collars required in the drilling assemblywill depend on the expected range of weight that will beapplied to the drill bit. The required weight on the bit isachieved by letting a certain length of the drill collars act on the bit as a compressive load while the drilling string is turned tothe right. The rest of the drill collars and the attached drill pipeabove will be kept in tension. The balance point betweencompression and tension is called the “neutral point” and itappears to be one of the more common points of failure for drillcollar tool joints.

Drill PipeAs already mentioned, drill pipe is used above the drill collarsection of the drill string. Drill pipe has a thinner wall sectionthan drill collars and is made from high-grade steel pipe. It isequipped with tapered, right-hand threaded tool joints box-up/pin down. Drill pipe normally comes in 30' lengths.

Kelly Saver SubAt the top of the drill string is the kelly and it's attached kelly

saver sub. The kelly saver sub is a short section of heavy-walled, high-grade steel pipe with tool joints box up/pindown. As the name implies, this sub is a protective tool whichremains attached to the kelly and is a replacement item whenthe tool joint pin on the saver sub is worn out or damaged afternumerous connections and disconnections to drill pipe.

Kelly and Kelly BushingThe kelly is made from high-grade steel pipe with a square orhexagonal section. It is usually 40' long for rotary drillingoperations on land. The square or hexagonal section fits into

a corresponding square or hexagonal hole in the kelly bush-ing. The kelly bushing is equipped with drive pins which fitinto corresponding holes in the rotary table. When the rotarytable is rotated to the right (clockwise), the kelly bushing isturned to the right. This rotates the kelly, which also rotatesthe attached drill string and rotary bit, to the right.

Figure 2.5. Photo of a typical kellyand kelly bushing


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As the bit makes more hole, the kelly moves down throughrollers in the kelly bushing until another 30' section or more of hole has been drilled. The whole drill string and kelly are thenpulled up until the kelly bushings are picked up out of therotary table so that the last drill pipe connection can be broken(unscrewed) to insert another length of drill pipe. In thisoperation, the kelly and kelly bushing are handled together.

The threaded connection at the top of the kelly is a left-handthread as the right-hand rotation applied to the kelly during

drilling operations would effectively unscrew right-handthreaded connections above the rotary table.

Kelly CockThe next piece of equipment above the kelly is the kelly cock.The kelly cock is a safety valve which can be closed manuallywith a quarter turn. Remotely-operated kelly cocks are alsoavailable. The purpose of the kelly cock is to provide a meansof closing in pressure inside the drill pipe string in the eventthat higher than expected pressures are encountered during

the drilling of the hole. The kelly cock will normally beequipped with left-hand threaded connections box up/pindown.

SwivelThe upper box connection of the kelly cock mates with the pindown connection of the next major piece of equipment, namelythe fluid swivel. This extremely important unit supports theweight of the entire drilling assembly on a large, sealed bearing housed in the swivel. This bearing allows the drillstring to rotate without rotating the swivel body. The swivel

has a fluid inlet through which the circulating drilling fluid ispumped through the bore of the sealed bearing and then intothe bore of the kelly and attached drill string.

The upper part of the swivel body is equipped with a large,heavy bail through which the hook of the travelling block ispassed.

Figure 2.7. Photo of a typical crownblock

Figure 2.6. Photo of a typical kellyand kelly cock


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Travelling Block and HookThe travelling block and hook form part of the hoist mecha-nism which enables the drilling assembly to be lowered into,or pulled out, of the hole. On standard exploration drillingrigs, the travelling block will usually house 6 large pulleywheels, wire or sheaves. The travelling block is strung withinterconnecting drilling line, or cable, to the crown blockintegrated into the top of the mast or derrick structure.

Crown Block and Drilling Line

The crown block also has 6 large sheaves and the stringing isaccomplished by reeving the drilling line around the sheaveson the travelling block and crown block. One end of thedrilling line is anchored at the foot of the mast or derrickstructure. This line is known as the “dead” line. The other endof the line is wound onto the cable drum of the hoist mecha-nism, or drawworks, on the rig floor. This line is the “fast” line.The stringing of the drilling line does not necessarily use all thesheaves of the travelling block and the crown block. Thedrilling line may use 4, 5 or 6 of the sheaves. The number of

sheaves selected will determine if “8-line stringing” (4 sheaves),“10-line stringing” (5 sheaves) or “12-line stringing” (6 sheaves)is being used. The fewer lines used in the stringing meansfaster hoisting or lowering speeds, but decreases the loadcarrying capacity. The more lines used in the stringing meansslower hoisting and lowering speeds, but increases the loadcarrying capacity.

Mast or DerrickThe large mast or derrick structures that support the crown block and all of the load carried by, and including, the travel-

ling block and hook, are commonly rated at 1,100,000 lbs. to1,300,000 lbs. maximum load capacity. The height of mostland exploration masts or derricks does not exceed 150'. Thereason for this height arises from the need to accommodate thetravelling block and hook while pulling the drill pipe out of thehole, usually 3 joints at a time. This is called a thribble and is

Figure 2.8. Photo of a typical derrick

Figure 2.9. Photo of a typical mud pump.


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Figure 2.10.A Photo of a typicalstandpipe

approximately 90' in length. The length of 3 interconnected joints of drill pipe is called a “stand”. These “stands” areracked in a vertical manner within the mast or derrick struc-ture.

Support SystemsThe topics thus far have covered the equipment required todrill a hole. However, the hole could not be drilled without themeans to circulate the drilling fluid, raise and lower thedrilling assembly and rotate the drill string. All of these

support functions can be operated independently of one an-other as well as collectively in any combination required.The following notes will discuss these support functions.

Drilling Fluid Circulation System (Refer to Figure 2.2)

Mud Pump or Slush PumpIn the drilling of exploratory or development wells, a verylarge pump is required to maintain a circulation system. Theoilfield pumps used for this purpose are called mud pumps or

slush pumps. They are large, positive displacement duplex ortriplex pumps. By changing the piston and liner sizes, thepiston stroke and the strokes per minute of these pumps candeliver volumes in excess of 1,000 gallon per minute andoutput pressures over 6,000 psi. The drive units or primemovers for mud pumps are usually diesel engines. Powertransmission from the engine to the pump is usually by way of V-belts and grooved pulleys mounted on drive shafts.

Standpipe and Standpipe ValveThe drilling fluid is delivered under pressure to the standpipe

through the standpipe valve. The standpipe valve is a safetyvalve and performs a function similar to the kelly cock valvewhen unexpected pressure anomalies occur in the drillingoperation. It can be operated manually usually with a quarterturn from the fully open position to the fully closed position.The standpipe is made from high-grade steel and is normallyattached to a leg of the mast or derrick structure. The highpressure drilling fluid passes through the standpipe and

Figure 2.10. Typical standpipe valvemanifold


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gooseneck at the upper end of the standpipe into the flexiblerotary hose. The other end of the rotary hose is connected tothe inlet on the swivel which provides the fluid path into thedrilling string.

Rotary HoseThe rotary hose is exposed to very tough conditions in it'sservice life. It has to be flexible as it is connected to the swivelwhich goes up and down in the mast or derrick as the drillingassembly is raised or lowered during drilling operations. Therotary hose has to withstand high pumping pressures as well

as high temperatures from the drilling fluid, particularly asthe hole gets deeper and abrasive action of the drilling fluid.Pressure ratings for rotary hoses are found in the range of 5,000psi to 10,000 psi working pressure depending on the serviceanticipated. Rotary hoses vary in length, but 75' is the normallength for land drilling.

The drilling fluid passes through the bore of the kelly, thestring of drill pipe, the section of drill collars and the jets, ornozzles, in the bit at the bottom of the hole. From here, thedrilling fluid returns carrying the cuttings from the action of the drilling bit up the annular space between the drill stringand well bore to the surface.

Bell Nipple and Return FlowlineHere the fluid passes through the blowout preventer (B.O.P.)stack mounted on a casing head or wellhead spool, and theninto the bell nipple mounted on top of the B.O.P. stack. Thedrilling fluid then enters the return flowline which directs thefluid over the vibrating screen of the shale shaker.

Shale ShakerThe purpose of the shale shaker is to separate the cuttings fromthe drilling fluid so that they are removed from circulation andcollected as samples for examination. The “strained” drillingfluid then drops into the settling pit. The settling pit gives thedrilling fluid time to drop the very fine particles of andintoformationthat have become entrained in the drilling fluid.The drilling fluid then passes over a partition in the settling

Figure 2.11. Photo of a typical rotaryhose

Figure 2.12. Typical bell nippledischarge line and shale shaker


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tank the suction pit where it is picked up by the suction pipeof the mud pump, and the circulation cycle starts all overagain.

Running and Pulling System

DrawworksAs previously mentioned, the drawworks (hoist mechanism)provides the means to reel in the drilling line (fast line) onto alarge drum as it raises the travelling block, hook and drillingassembly. The drawworks also lets out the drilling line as the

drilling assembly is lowered. The drawworks is usuallypowered by large diesel engines or electric motors and hasvarious gear selections to alter the winch speed of the drumpulling in the drilling line.

Brake SystemThe drawworks is also equipped with a very powerful brakesystem that is controlled by the driller as the drilling assemblyand drill pipe is lowered into the hole. The amount of the load being lowered into the hole is measured by a weight indicator

sensing mechanism which is attached to the “dead line”. Thereadout from the weight indicator sensor is transmitted to alarge scale dial that the driller can observe on his console.During drilling operations, it is this weight readout that tellsthe driller how much weight is being applied to the bit.Drilling rigs are generally equipped with a dual brakingsystem, a mechanical braking system and an electric or hy-draulic braking system.

Rotating System

Rotary TableThe means to rotate the drilling assembly is provided by therotary table which is usually powered by a diesel or electricprime mover. A large rotary chain, engaging sprocketsmounted on the drive shafts, is the normal means of powertransmission from the prime mover to the rotary table. Therotary table itself is a very large, rugged piece of equipment. It

DEADLINE

DRILLING LINE(8 LINES ARE STRUNG)

TRAVELING BLOCK

DRILLING HOOK

DEADLINE ANCHOR

STORAGE REELDRUM BRAKE

DRAWWORKS

DRUM

FASTLINE

CROWNBLOCK

Figure 2.13. Illustration of drawworks, brake, and hoistingsystem

Figure 2.14. Photo of a typical rotarytable and bottom of the block and hook.


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is mounted on very large steel beams, called rotary beams, atthe rig floor level.

Rotary BeamsThese rotary beams are integrated into the substructure whichsupports the entire derrick structure. The rotary table ispositioned centrally below the crown block. The center sec-tion of the rotary table rotates while the main section remainsfirmly anchored. The center opening is normally 17-1/2" to27-1/2" on land based rigs. Offshore, the central opening of rotary tables are larger, normally 37-1/2" to 49-1/2".

Master BushingsFor easy removal, the master bushings are split in half. Eachhalf sits into a matching recessed profile in the center of therotary table. When in place, the master bushings have atapered, central hole that provides the seat for the drill pipeslips. The drill pipe slips are used to wedge around andsupport the drill pipe string at the rotary table. This functionis required when adding another joint of drill pipe, or single,and when the drill pipe is tripped (pulled or run) in and out of

the hole.

The kelly bushing fits into the rotating center section of therotary table and around the kelly. As the center section of therotary table rotates, so does the kelly bushing, the kelly, theconnected drill pipe and drilling assembly.

Elevators and LinksA set of elevators and bails are required on the rig site for eachsize casing and tubing used to drill the well. These items aresized by the outside diameter and anticipated weight of each

string of pipe. These tools provide a rapid means for runningand pulling pipe while the kelly, kelly bushing, swivel androtary hose is stored in the "rathole". Elevators are generallyrental items, but are occasionally supplied by the casing crew.

For the larger casing sizes, slips are sometimes an integral partof the elevator for easier handling due to the size and weight.

Figure 2.15. Photo of a typicalsubstructure.

Figure 2.16. Photo of casing elevatorsuspended by links from the block andhook.


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This concludes the main functions needed to drill a hole. Theyare pumping, rotating, raising and lowering. As our earlierdiscussion on oil and gas reservoirs mentioned, the need forcontrol of formation pressures must be constantly addressedwhile drilling a hole. The next section will address the func-tion of drilling fluid as a medium to control these pressures.

Drilling FluidsThis subject is a major topic in its own right. The purpose of the following discussion is to highlight the primary functions

of drilling fluids. These functions are summarized below.

1. Control pressures of formations penetrated. This isachieved by ensuring that the hydrostatic column of drill-ing fluid exerts a pressure on the formation that is higherthan the water, oil or gas pressure in the formation. Thisprevents entry of the formation fluids or gases into thewellbore.

2. Clear the cuttings from between the drilling bit and thecutting face on bottom. This is achieved by the largevolume of drilling fluid blasting through the nozzles on the bit that is positioned to clear the freshly cut face. This jetting action also provides a hydraulic cutting actionwhich can be significant in some rock formations.

3. Remove the cuttings from the hole. This is achieved by itscarrying properties, directly related to its “gel strength”,and the upward velocity of the annulus return.

4. Cool and lubricate the drilling assembly. The cooling is

achieved by providing a cooler drilling fluid from thesuction pit and circulating out the hot drilling fluid gener-ated downhole by the cutting action of the bit and thedeeper, hotter formations. The drilling fluid provideslubrication by lessening the frictional losses between thedrill string, the walls of the drilled hole, and at the cuttingface between the bit and rock.


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5. Consolidate the walls of the drilled hole to prevent thecaving-in, or collapse, of certain types of rock into thewellbore. This is achieved by the drilling fluids capacity todeposit a thin "mud cake" on the walls of the hole. The mudcake forms because the hydrostatic pressure of the drillingfluid is greater than the formation pressure and a naturalloss of drilling fluid to the formation occurs. Large lossesof drilling fluid are prevented by the “mud cake” formingon the walls of the hole, just as a filter cake forms in anyfiltration process. By keeping a small pressure differential(100 - 150psi) between the hydrostatic column of the drill-

ing fluid and the formation pressure, the loss of drillingfluid to the formation is also minimized.

The simplest drilling fluid is water, either fresh water or seawater, and it is commonly used to drill the shallow sections of the hole. Although water is very good for penetration rates, ithas poor properties for preventing the collapse, or caving in,of the sides of the hole, particularly where the formations areunconsolidated or have thick beds of natural clay. During thedrilling of shallow hole sections, the re-circulated water will

pick up clay minerals which will hydrate in the water forminga natural slurry or thin mud. These hydrated clay mineralswill form a “gel” with the water which improves the cuttingcarrying properties of the “mud” along with its higher viscos-ity.

Water-based muds as drilling fluids have undergone manyimprovements over the last hundred years with the additionof specially prepared bentonite clays that form very stable gelsor muds. Saltwater clays have also been used extensively.Low solids mud have been introduced using cellulose-based

gels as the clay substitute in the mud. Oil-based muds have been used for many years, particularly where water loss froma conventional mud is seen that cause formation problems ordamage.

As has been stressed in previous notes, the pressure control of formations containing water, oil or gas accumulations needsconstant attention. Controlling the density of the drilling


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fluid, or mud, also controls the bottom hole pressure exerted by the mud on the formation. This is achieved by addingweighting materials to the mud. The most widely usedweighting material is barites (barium sulfate). It is added tothe mud as a finely powdered mineral that stays suspended inthe mud. The gel strength of the mud is very important inensuring that the barites stays suspended and not drop out asa sediment, particularly when the mud is not being circulated.Barites are about 4.2 times denser than water.

Top Drive Drilling

In the early eighties, top drive units, one of the most significanttechnical advances in drilling, were put into service. Insteadof turning the drill pipe with a kelly and rotary table, a topdrive unit is suspended from the traveling block assembly andturns the drill string with a direct hook-up eliminating theneed for the kelly, kelly bushing, and rotary table drive. Theunit rides up and down a rail mounted to the derrick, givingit stability and keeping the drill string centered over the hole.The top drive is powered by either electric or hydraulic motors

which generate the equivalent rpm and torque as like-sizedrotary drives. Top drive units generally have two integralkelly cocks, a manual and a remote hydraulic. There are twotypes of top drives, permanent (Figure 2.17) and portable(Figure 2.18), permanent being the only means of drilling andportable being a removable assembly as a secondary means of drilling using many components of the rotary drive configu-ration. On both permanent and portable top drives, the standpipe and rotary hose must be extended to allow the top driveto travel to the top of the derrick. Since the drilling powersource can now be positioned at the top of the derrick, two to

three stands can be drilled at a time, depending on the heightof the derrick.

Permanent drives have an integrated swivel and are mountedto the traveling block, while the portable unit is suspendedfrom the existing swivel, block and hook assembly. On

Figure 2.17. Typical Permanent TopDrive

Figure 2.18. Typical Portable TopDrive


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permanent top drive systems, the rotary table is replaced by amaster bushing and slip bowls to facilitate the use of casingand tubing slips. On portable drives, the kelly bushing isremoved from the rotary and slip bowl inserts are used in itsplace to facilitate hanging off the drill string to make up joints.Other advantages of the top drive system include the continu-ous rotation and circulation going in, or out of, the hole andthat the connections can be made up, or broken out, at anypoint in the derrick. The links extend forward from the topdrive unit hydraulically and allow the elevators to pick uppipe at the V door and monkey board. In general, top drive

units provide enhanced well control and reduce the chances of sticking pipe while running in and out of the hole.


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3Drilling a Well on Land

®

Introduction ............................................................................... 21

Primary Conductor ................................................................... 21

Starting Head............................................................................. 22

Mud Riser .................................................................................. 22

Starting to Drill Ahead ............................................................. 22

Running Casing ......................................................................... 24

Installing the Casing Hanger ................................................... 28

Blowout Prevention and Control ............................................. 29

Ram Type Preventers ............................................................... 30

Annular Preventers ................................................................... 31

Controlling a Potential Blowout .............................................. 32

Choke and Kill Lines ................................................................ 33

Table of Contents


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3

IntroductionThis chapter of the manual assumes that the drilling rig is inplace with all the support systems ready to “spud in”, orcommence drilling. The land rig diagram in the previouschapter can be used as a reference.

Primary ConductorMost of the wells drilled on land will require a short section of large diameter pipe, or casing, be installed in the cellar floor.This primary conductor can be driven into place using adiesel, or steam hammer, or can be lowered into a pre-drilledhole and cemented in place. The purpose of the primaryconductor is to prevent loose soil and unconsolidated rockformations from caving in, or collapsing, into the drilledsection of hole. The collapse, or wash out, of unconsolidatedsurface formations can plug the hole and, in severe cases, canundermine the drilling rig to such an extent that the location

has to be abandoned and the rig moved to an adjacent site. Theprimary conductor may range in size from 16" to 30" for mostland drilling operations and the lengths used will depend onthe local conditions varying from a few feet up to 500 ft. ormore. The pressure requirements and ratings of these pri-mary conductors are extremely low as they are not usuallyexpected to contain more than average formation pressure, but are mainly in place to provide a primary conduit for the

Drilling a Well on Land

Figure 3.1. Illustration of the cellardeck and the primary conductorinstalled

CONDUCTOR


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Drilling a Well onLand 3

22 ®

drilling assembly and prevent formation collapse. Figure 3.1shows the primary casing in place.

Starting HeadIf the primary conductor pipe has been driven into place, theexcess amount above the cellar floor will be cut off and astarting head will be welded to the primary conductor. If casing has been used that is equipped with a casing thread orspecialty connector, the drilling operator will have drilledenough hole and spaced out the lengths of casing so that when

the casing is cemented in place, the last connection is posi-tioned at the cellar floor level. This makes it very convenientto attach a starting head with a matching thread or specialtyconnector. The starting head is equipped with a large, low-pressure flange or hub face looking up. It can have two sideoutlets and also have an internal landing profile for the firstcasing hanger.

Mud RiserA mud riser is a short length of large diameter pipe with

matching flange, or hub face, to the starting head and is either bolted or clamped to the starting head. The upper end of theshort length of riser is equipped with a “bell nipple”, or “flownipple”, which has an outlet made up to the mud return flowline. The purpose of the riser is to provide a conduit for thedrilling fluid returns and rock cuttings as the well is drilled. Insome areas of the world, a large “bag-type” blowout preventer,or custom designed “flow diverter” system, may be installedon the starting head. This is usually only done if a long lengthof primary conductor has been installed and shallow pocketsof formation gas are anticipated. The riser and bell nipple are

installed on top of the blowout preventer, or flow diverter,either as separate units or integrated into the equipmentdesign. Figure 3.2 illustrates the conventional drilling set-up.

Starting to Drill AheadAs can be seen from the illustration in Figure 3.2, the bit with bit sub have been connected to a short length of the drill collarwhich, in turn, has been connected to the kelly. The mud

ROTARY

TABLE

RIG

FLOOR

Figure 3.2. Preparing to drill out forsurface casing

DRILLING BIT

CELLAR

RISER

STARTING

HEAD

DRILL PIPE

ROTARY

TABLERIG

FLOOR


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Drilling a Well onLand3

23 ®

Figure 3.3. Surface casing being run

pumps are started and the drilling fluid, usually waterfor surface hole, is circulated down through the bit, backup the annulus, through the mud return flowline andthen back to the suction pit.

The rotary table drive is then engaged and the kelly bushings are rotated by the rotary table as the kellystarts to turn to the right. The drawworks brakingsystem is then let off slowly to lower the rotating drillingassembly until the bit starts to take weight on the bottom

of the hole.

Drilling proceeds until the kelly has been drilled downto the top of the kelly bushings. The hole is circulated toclear the cuttings and the mud pumps and rotary arestopped. The kelly, with attached drilling assembly, ispulled out of the hole until the kelly bushings lift out of the rotary table exposing the connection between thekelly and the short length of drill collars. Slips and asafety collar will be set to suspend the drilling assembly.

This connection is broken (unscrewed) and the kelly isthen stabbed and made up to the next length of drillcollar which has been placed in the mouse hole. Thekelly and the additional length of drill collar are thenmade up to the drill collar joint sitting in the rotary table.

The kelly is then picked up so that the downward loadon the slips is relieved. This enables the slips to beremoved and the drilling assembly, once again, be low-ered back into the hole and drilling will be started upagain.

The process of drilling off the kelly and adding singlesto the drill string proceeds until the hole reaches therequired depth (or casing point). The depth of the holewill be recorded as a measurement in feet below thekelly bushings (KB). When the casing point is reached,the bit is pulled a few feet off of the bottom and the holeis circulated to remove all cuttings from the hole. When

CELLAR

RISER

SURFACE

CASING

STARTING

HEAD

ROTARY

TABLERIG

FLOOR


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the hole is declared clear of cuttings, the drilling assembly ispulled out of the hole and the sections of drill pipe or drillcollars will be stood back in the derrick or mast as triples(occasionally as doubles in small drilling masts). If the drillcollars and drill pipe sizes need changing for the next sectionof hole, they will be broken down into singles and put out onthe pipe racks.

Running CasingThe next step in drilling the well is to run steel casing into the

hole and cement it in place (Figure 3.3). The purpose of thesteel casing is to provide a protective sleeve in the section of hole just completed. When cemented, it prevents the rockformations and fluids from entering the well bore during thenext drilling stage. The size, grade of steel and wall thicknessof the casing will also be selected to contain the higher forma-tion pressures expected as the hole is drilled deeper.

Running the successive strings of casing and production tub-ing in and out of the hole during these operations is called

"tripping in" and "tripping out". This is accomplished by usingelevators as referenced in the equipment section of the manual.These elevators latch around the casing or tubing and providea landing shoulder for the casing coupling or the tubing upset.The elevator attaches to the hook on the traveling block bymeans of bails. As each joint is lowered into or pulled from thehole, slips are set around the pipe in the rotary, or in a portableslip bowl called a "spider", allowing the elevator to be re-moved and used to pick up the next joint of pipe to be made upor removed from the string. This process is repeated until allthe pipe is in or out of the hole.

The lengths of casing used are generally 30' long, and equippedwith a threaded pin end and a threaded box end or coupling.The normal method of running threaded casing is box up/pindown. The first joint of casing run is the shoe joint, so named because it has a casing shoe or guide shoe at the lower endwhich is rounded to form a smooth guide for the casing as it islowered into the hole. Sometimes, the casing shoe has a one

Figure 3.4. Setup for Cementingcasing into place

A B

TOP WIPER PLUG

BOTTOMWIPER PLUG

STARTING HEAD

BELL NIPPLE

FLOAT COLLAR

FLOAT SHOE

CEMENTING HEAD

DRILLING FLUID

CASING SLIPS


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way float valve in its body which allows fluid to pass downthrough the center part of the shoe, but does not allow fluid tocome back the other way.This float valve becomes im-portant during the cement-ing process. If the hole has been drilled through a seriesof swelling or sloughing shalesections, the float shoe canget plugged and not function

correctly. In areas where thisproblem is anticipated, thefloat valve may be includedin a float collar which is runin the casing string one ortwo joints above the guideshoe. All of the joints of cas-ing are measured on the piperacks before they go into thehole. The measurements are

totalled to ensure that the cas-ing shoe ends up a few feetfrom the bottom of the hole.As the casing is being run, itis normal practice to fill upthe inside of the casing everyfew joints with drilling fluid.If this is not done, the casingtends to “float” as the floatvalve prevents entry of drill-ing fluid into the casing.

1. Setting Up to CementCasing.Figure 3.4 shows the cementhead (with top and bottomcementing plugs in place) anda simple manifold with two

Figure 3.5. Cementing operation in progress

A B

TOP WIPER PLUG

CEMENT

FLOAT COLLAR

FLOAT SHOE

CEMENTING HEAD

BOTTOM

WIPER PLUG

DRILLING FLUID

Figure 3.6. Cement being displaced

A B

FLOAT SHOE

CEMENTING HEAD

TOP WIPER PLUG

BOTTOM

WIPER PLUG

FLOAT COLLAR

CEMENT

DRILLING FLUID


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valves (A & B) attached to the cement head. Two manuallyoperated release bars release the cement plugs as required.

2. Cementing in Progress.The cement slurry, in it's most basic form, is simply powderedcement and water mixed to a pre-determined density that has been pumped into the cement head with valve A open andvalve B closed. The release bar for the bottom cementing plughas been pulled back and the plug is shown moving down thecasing at the interface between the drilling fluid and the

cement slurry. The purpose of the rubber-finned cement plugis to ensure that the usually denser cement slurry does notchannel down through the drilling fluid, which could ulti-mately cause poor quality cement to end up in the annulus.The ball float valve in the float collar is open and the drillingfluid is being forced down the casing, through the casing shoe,up the annulus, and return to the mud pits through the returnflowline (Figure 3.5).

3. Displacement in Progress.

The bottom cement plug has reached the float collar and anincrease in pump pressure will have sheared out the centersection of the plug allowing cement slurry to bypass the plug.The cement slurry is shown passing through the casing shoeand up into the annulus. The less dense drilling fluid is shown being displaced out of the annulus. Also, the top cementingplug has been released and drilling fluid is being pumped intothe cement head and casing through the open valve B withvalve A now closed. The volume of cement slurry used on thecement job will have been calculated to ensure that goodquality cement completely fills the annulus and the casing

below the float collar. The top rubber-finned cement plug isused to ensure that there is no mixing at the drilling fluid andcement slurry interface, as this could possibly cause poorcement to get positioned around the casing shoe (Figure 3.6).

4. Cement in Place.The displacement of the cement slurry has been completedand the top plug has bumped and sealed on the bottom plug.

Figure 3.7. Cement in place aroundthe casing

A B

FLOAT SHOE

CEMENTING HEAD

FLOAT COLLAR

BOTTOMWIPER PLUG

CEMENT

CEMENT

DRILLING FLUID

TOP WIPER PLUG


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An immediate rise in pump pressure would have signifiedthis event and the pumps would have been shut down. Theexpected volume of displacement fluid would also have beencalculated before the cement job and a very close watch wouldhave been kept on the volume of drilling fluid taken from thedisplacement pit at the surface and/or the pump strokes of thedisplacing pump. With the pumps shut off, a valve in thedisplacement line would be opened to see if there was anyflow-back from the casing. If there is no flow-back, it wouldsignify a successful cement job as the float valve in the float

collar is holding the heavier cement slurry in the annulus fromU-tubing back into the casing. This means that the cementhead and cementing lines can be removed; the excess cementslurry from the starting head up to the bell nipple can bewashed out; and the next step of setting the casing hanger cantake place before the cement slurry hardens. Four hours isabout the normal setting time for cement slurry after it ismixed. However, various additives to the cement can acceler-ate or retard the setting time (Figure 3.7).

The cement job just described is fairly typical of all cement jobsperformed to cement casing in a hole. There are innumerablevariations to the methods used and it is not unusual to seecement jobs performed with only one plug or without anycement plugs. On occasion, triple cement plugs might be used,particularly on long casing strings where the cementing may be done in stages. The choice of method used depends onmany factors; the ability of the formation to accept the in-creased hydrostatic head from a column of cement slurry; therequirements of local regulatory bodies requiring the com-plete shut-off of particular formations (usually fresh water

aquifers); the particular policies of the oil company drilling thewell; etc.

When the cement hardens, it seals off the annulus in the wellwhich prevents migration of fluids or gases from one forma-tion to another. The hardened cement also provides protec-tion to the casing string from potentially corrosive subsurface

Figure 3.8. Illustration of a typicalslip type hanger

Casing Hanger opened

Casing Hanger


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water. A good cement job will also enhance the burst strengthcapacity of the casing.

Installing the Casing HangerThe next step in drilling the well is to install a casing hangerinto the starting head so that the suspended casing load can betaken in the starting head. The casing hangers used for landdrilling are normally split or hinged so that they can be“wrapped around” the casing and slid down the casing to thelanding shoulder in the starting head (Figure 3.8). Before this

can be done, the riser must be disconnected from the startinghead and lifted up to expose the casing suspended from therotary table above. The “wraparound” type hanger is in-stalled into the starting head. The casing hanger will beequipped with a bulk type seal that seals against the casingand against the prepared profile of the starting head. Thecasing hanger will also have internal slips to grip the casing.The slips are set on a taper so that the downward load forcesthe slip elements to grip the casing more firmly. Most casinghanger designs rely on the weight of the suspended casingacting through the slips to activate the seal between the casing

and housing. Other designs have the seals independent of the“weight set” action. These seals are mechanically activated bylockdown screws.

After the casing hanger is correctly positioned in the startinghead, the casing load is picked up by the hook, or drawworks,and the casing slips and the safety clamp (if used) would beremoved. The casing load would then be slowly lowered sothat the slips in the casing hanger start to take a grip andsupport the casing load. When this has been successfully

achieved and the casing hanger packoff seal has been set(either by the weight of the suspended load or mechanically),the excess casing above the hanger will be carefully cut off.The precise cut off point will be dictated by the manufacturerof the equipment, as the casing stub has to fit into the nextcasing spool which will be bolted or clamped to the startinghead. The casing stub usually has to interface and seal with theintermediate packoff bushings installed with the next casing

BELL

NIPPLE

DRILLING BIT

TOP WIPER

PLUGFLOAT

COLLAR

FLOATSHOE

BLOWOUT

PREVENTER

Figure 3.9. Preparing to drill out of surface casing with the BOP Stack installed


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spool. With this operation completed, the well now has its

primary conductor and surface casing string in place. The nextstage in drilling the well is to install the blowout preventer(BOP) stack directly on the casing spool, adapter or drillingspool attached to the casing spool.

This next section of hole is drilled with the blowout preventerstack in place as shown in Figure 3.9. Therefore, the followingtext is devoted to a brief discussion on the main elements of theBOP stack and its functions.

Blowout Prevention and ControlWhat is a blowout? It can be described as “an uncontrolledflow of fluids and/or gases from the wellbore to the atmo-sphere”.

How does a blowout occur? As mentioned in earlier discus-sions on drilling fluids, the hydrostatic pressure exerted by thecolumn of drilling fluid must always exceed the pressure of the fluids and/or gases contained in the formations being

penetrated. If this positive pressure differential is not main-tained, the formation fluids and gases can enter the wellboreand displace the drilling fluid which can lead to a blowoutcondition if corrective action is not taken.The most common reasons for a blowout to occur in open holesections of the well are:

• The drilling fluid column density is lowered by gas bubblesescaping from drilled cuttings or the formation.

• Formation fluids or gases enter the wellbore as the drilling

assembly, acting as a plunger or swab, is pulled out of the hole.

• Loss of drilling fluid due to a lost circulation zone in thewellbore which reduces the hydrostatic column which, inturn, can allow formation fluids or gases from another zone inthe well to enter the wellbore.

• Failure to fill the hole when pulling out drilling assemblies

Figure 3.11. Dual Ram-type preventers

Figure 3.10. Illustration of the BOP

Stack


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from the hole. This permits the fluid column to drop in thewell, thereby reducing the hydrostatic pressure on the forma-tion penetrated.

• An unusually high pressure zone is encountered and thehydrostatic head of the drilling fluid is simply insufficient tocontain the formation fluids or gases.

When any of the above conditions occur, the drilling fluidcolumn will be pushed back out of the well slowly at first, butgaining speed rapidly as the column gets lighter and lighter

with the entry of more and more formation fluids or gases. Themain flow will be out of the annulus, but flow will also comeout of the drill pipe if there is no means to shut it off.

The blowout preventer is used to close the annular spacetherefore preventing further loss of fluid from the annulus.There are two main types of blowout preventers. These aredescribed below.

Ram Type Preventers

The illustration in Figure 3.11 shows two ram type preventers.The ram type preventer contains two pistons that drive tworubber packers, or rams, to meet and seal at the center of theBOP stack bore. The shape of the rams would have beenselected to either close and seal on drill pipe (drill-pipe rams),close and seal on casing (casing rams) or close and seal on openhole (blind rams). The rubber elements of the rams aresheathed in shaped steel plates, or fingers, and used for ananti-extrusion device as well as provide additional strength.Some blind rams are designed specifically to cut drill pipe ortubing and seal off the well bore. These rams are known as

blind, or shear, rams. The normal operating pressure tohydraulically open and close these rams is 1500 psi. Shearrams need additional force to cut drill pipe or tubing and thisis achieved by putting on a larger operating piston and cylin-der while still using the normal 1500 psi operating pressure.Ram-type preventer bodies can have pressure ratings thatcover up to 15,000 psi.The construction of the rams in the ram-type preventers is

Figure 3.12. Annular preventer


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such that a string of drill pipe can be hung from them, if necessary.

Annular PreventersThe illustration in Figure 3.12 shows the annular preventer,typically installed at the top of the BOP stack on the dual ramtype preventer. As shown in the cross-section, the rubberpacking element is a complete annular ring that is driveninwards by the upward movement of the annular pistonacting on the tapered interface between the two parts. Therubber element can close and seal on any size of tubular as wellas on open hole. The rubber packing element is reinforcedwith radial steel fingers to give the element additional strengthand reduce the extrusion of the rubber when activated. Theannular preventer is always installed at the top of the BOPstack. The flexibility of the annular preventer's rubber elementis such that the drill pipe and it's tool joints can be stripped into, or out of, the well with pressure contained under the rubberelement. This practice is only used in emergencies and, as onewould expect, this type of use causes very high wear on therubber element. Other names used for annular preventers are

bag-type preventers and spherical preventers.

The normal operating pressure to hydraulically close theannular preventer is 1500 psi, but this may be reduced if thewellbore pressure is assisting the closure of the preventer ona tubular in the wellbore (there is concern about the collapserating of the tubular, particularly if it is casing). The annularpreventer returns to its open position as the annular piston ishydraulically moved downwards. The rubber element re-turns to it's fully open position with a considerable naturalspring force in the element itself. However, in old and worn

elements, this natural spring force is sometimes insufficientand this part of the BOP stack can often be a restriction todrilling tools being lowered into, or pulled out of, a well. Inorder to overcome this problem, the industry has adopted thepractice of cutting the rubber packing elements in two so thatthe two halves can easily move back to their fully openposition.


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Controlling a Potential Blowout ConditionOne of the early signs that formation fluids or gases areentering the wellbore is that the level of drilling fluid inthe mud pit is rising quite rapidly as the drilling fluid is

being forced out of thehole. A continuous re-cording pit level indica-tor will provide this evi-dence to the driller orrig supervisor. Many pitlevel indicator systems

have built-in alarm sys-tems just in case the im-portance of the event hasescaped the vigilant eyeof those concerned. If itis quickly determinedthat the flow is indeed

uncontrolled, then the next action would be to close aram, or rams, on the BOP stack so that they close on thetubular in the wellbore. The closure of any ram or

annular preventer must take place very rapidly. Thereason for this is that escaping fluids can be extremelyabrasive and the rubber elements can be destroyed if they move to the fully closed position too slowly. Thefast closure of preventers is accomplished by having alarge pre-charged reservoir or accumulator of hydraulicfluid that will instantly provide several gallons of hy-draulic fluid at the 1500 psi operating pressure.

The next thing that will happen is that pressure will startto increase under the closed preventer and in the drill

pipe, or tubular, in the wellbore. Assuming that the drillpipe is in the hole and the kelly is attached, a means tocirculate the well still exists. However, circulation willonly be re-established when heavier drilling fluid is

prepared in sufficient quantities to completely circulatethe old drilling fluid out of the drill pipe and annulus.

Figure 3.13. Circulating the wellthrough the choke and kill manifold

ANNULARPREVENTER

RAM

PREVENTERS

GAS OR OIL

CHOKE & KILL MANIFOLD


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Choke and Kill LinesIn this case, the drill pipe becomes the kill line as it isdelivering the heavier fluid to kill the flow of fluids and/or gases from the wellbore. Obviously, the returns fromthe annulus will be under pressure. These are takenthrough a choke and kill manifold which will be con-nected to the side outlet of the casing spool, or drillingspool, directly below the BOP stack. The line from theside outlet to the choke and kill manifold is known as thechoke line (Figure 3.13).The back pressure maintained by the adjustable choke

in the choke and kill manifold on the annulus returns. Itensures that the effective hydrostatic head in the annu-lus is sufficiently high to contain the formation fluidand/or gases that have been entering the wellbore.

As the heavier drilling fluid is forced down the drill pipeand up the annulus, the pressure gauge reading on thechoke and kill manifold will gradually decrease indicat-ing that the annulus pressure is dropping. When thepressure reading has dropped sufficiently, the adjust-

able choke is opened to it's fully open position or it is bypassed by opening an alternative flow-path in thechoke and kill manifold. When full circulation has beenre-established with the heavier drilling fluid, the mudpumps will be shut down and the annulus pressure andflow will be observed to see if the “well killing” opera-tion has been successful. If there is no pressure increaseor flow, the closed preventers in the BOP stack will beopened and the normal circulation path, by way of the bell nipple and mud return flowline, will be re-estab-lished and drilling operations can proceed.


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This brief and simplified description of blowoutpreventers and their functions is merely an introductionto a very complex and important area of pressure con-trol in drilling wells. There are many variations in thetheories and practices used in controlling potential blow-out conditions. The regular functional and pressuretests required for BOP stacks, BOP stack control systemsand choke and kill manifolds are among the most im-portant tests in drilling wells. One leak in the fluid pathwhen trying to control a formation flow or “kick” canlead to total destruction of the drilling rig, loss of thewell and extreme danger to human life. Definitely not asubject to be taken lightly.


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4 Completing the Wellfor Production

® Table of Contents

4

Completing the Well for

Production

Pressure Testing the BOP Stack & Casing Hanger Seals ..... 35

Drilling the Hole for the Production Casing String ............... 36

Logging the Hole ....................................................................... 36

Completing the Well for Production ....................................... 38

Running the Downhole Tubing Assembly .............................. 39

The Production Tubing String................................................. 40

Dual Zone Completions through the

Production Annulus .................................................................. 44

Dual Zone Completions with a Second Tubing String .......... 44


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4

Pressure Testing the BOP Stack and Casing Hanger SealsAfter the BOP Stack has been installed, the next step is topressure test the packoff seals on the casing hanger previouslylanded and the BOP stack and connectors.

This series of pressure tests can be done by lowering a cup

tester, or special packer, on the drill pipe so that the test toolseals in the casing below the casing hanger. One of the piperams can then be closed onto the drill pipe. Hydraulicpressure applied through the side outlet of the drilling spoolwill test the BOP ram seal on the drill pipe, the metal ringgasket seal between the BOP stack and the drilling spool, theupper casing hanger packoff seal, and the seal between the testtool and the casing string.

The pressure tests will be done to a specified pressure, usually80% of the collapse rating of the suspended casing, not exceed-

ing the working pressure of the BOP stack for a specifiedperiod of time. Any leaks would be noted as significantpressure drops and the leak, or leaks, would be investigatedto determine their location.

Assuming a successful series of pressure tests, including theupper pipe rams and the annular preventer, has been achieved,the rams would be opened and the test tool would be re

Completing the Well forProduction


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Completing the Wellfor Production 4

36 ®

trieved. A bore protector may then be installed on the nextcasing hanger seat to protect the sealing surfaces for the nextcasing hanger packoff and to protect the landing shoulder inthe casing spool.

Many land wellhead systems are equipped with small testports in the casing spools to allow a pressure test to beconducted on the casing hanger packoffs without a full BOPstack test. Regular BOP stack tests will be conducted on aregular basis (once a week or more) depending on local

regulations and company procedures.

Drilling the Hole for the Production Casing StringWith all of the pressure tests successfully concluded and the bore protector in place, the next drilling assembly is made upand lowered down into the cement plugs in the casing. Usingthe drilling fluid used to drill the previous section of hole, thecement plugs, float collar, hardened cement and casing shoewill be drilled out and a few feet of new hole may be made. Atthis point, the old drilling fluid may be displaced from the hole

by new drilling fluid specially prepared and weighted for thenext section of hole.

As this section of hole is projected to penetrate the producingformation, the conditioning of the drilling fluid is of greatimportance. The drilling fluid properties such as weight,viscosity and fluid loss will be checked regularly.

The on-site geologist will be monitoring the cuttings comingover the shale shaker as the producing formations are ap-proached. Once the expected formation or formations have

been drilled through, the hole will have reached total depthand no further drilling will take place. The hole will becirculated to clear the last cuttings from the annulus, thedrilling fluid will be conditioned and the drilling assemblywill be pulled out of the hole.

Logging the HoleThe next operation will be to run a series of logging tools on


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TUBINGSTRING

multiple core, armored electric cable, into the hole and con-tinuously record the formation characteristics measured bythe logging tools as they are slowly pulled out of the hole at aconstant speed. There are a variety of logging tools or sondesused, but essentially the logging tool has a source of energy(electrical, radio-active or sonic) that is transmitted into theformation by means of contact pads on spring loaded arms. Asthe logging tool is pulled slowly out of the hole, receivers in thelogging tool monitor the amount of energy returning to thelogging tool and the continuous recording of these return

signals makes up what becomes the well log.

Interpretation of these well logs can tell the well-site geologistmany characteristics of the formations penetrated, such asporosity, permeability, if it is water bearing or oil bearing andif it provides an internal caliper log of the well bore. Fromthese logs and the geologist's analysis and correlation of cuttings from the well, the subsequent decisions on how tocomplete or abandon the well are made.

If the well being drilled was an exploration well, the decisionto drill the hole deeper would also hinge on the interpretationsmade from these logs.

For our purposes, this well is a development well being drilledinto known formations and therefore our next step is tocomplete the well.

After the logging operation has been completed and the lastlogging tool is out of the hole, the next step will be to run a“wiper trip” with the drilling assembly. This “wiper trip” is

merely running the drilling assembly to the bottom of the hole,watching for any tight spots in the open hole section. Once onthe bottom, the drilling fluid will be circulated and condi-tioned prior to running casing. Any tight spots in the openhole section will be “reamed” by the drilling assembly. Inother words, the drilling assembly will be rotated, raised andlowered through the tight spots.

PRODUCTIONCASING SETTHROUGH THEPRODUCTIONZONE

PRODUCTIONCASING SET ABOVETHE PRODUCTIONZONE

OPEN HOLE PRODUCTIONZONE

PRODUCTION

ZONE

Figure 4.2. Set ThroughCompletion

Figure 4.1. Top Set or Open HoleCompletion

TUBINGSTRING


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After the hole has been cleaned up, the drilling assembly ispulled from the hole, the bore protector is removed from thecasing spool and the rig is prepared to run casing and cementit in place.

There are generally two methods for completing a producingzone: top set, or open hole, completions and set throughcompletions (Figure 4.1 and Figure 4.2). In an open holecompletion, the production casing is run and set above theproducing zone. A packer is then set inside the production

casing on the tubing. A tubing stinger, located below thepacker, allows the producing fluid to enter the tubing stringand flow to the surface.

The cementing procedure will follow the same pattern asshown in the previous chapter. Once the final displacement of cement is completed and the float valve in the casing string isholding, the next step is to install the casing hanger and casinghanger packoffs for the casing string. Again, this has beendescribed in an earlier chapter and is depicted in Figure 4.3.

Completing the Well for ProductionA Set through completion is generally the most commonmethod used for completing a producing zone and will beused as a completion example.

When the production casing string has been landed andtested, a cement bond log (CBL) may be run to confirm thequality of the cement job. If no remedial work is required, theBOP stack will be removed and the tubing head will beinstalled and packed off against the prepared stub of the last

casing string. The tubing head looks very similar to a casinghead, having side outlets and an internal landing profile forthe tubing hanger.

Tubing heads are often equipped with test ports to test thepackoff seal with the last casing string as well as to test themetal ring gasket seal between the tubing head and the casinghead. The tubing head will most likely be equipped with

WORK-OVERBOP STACK

CASING HEAD

TUBING HEAD

DRILLINGFLUID

PRODUCTIONCASING

PRODUCING

ZONE

Figure 4.3. Cased Hole, Preparingto drill out cement plug

CEMENT PLUG


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radial bolts, positioned in theupper part of the tubing head,that will subsequently be usedto lock down the tubing hangerwhen it is landed in the tubinghead.

Running the Downhole Tub-ing AssemblyA small bore BOP stack will be

installed on the tubing head. Thedrilling assembly will then belowered into the casing and rundown to tag the top of the ce-ment on the top cementing plug.The cement and top plug would be drilled out leaving severalfeet of good quality cementabove the production casingguide shoe (Figure 4.4). This

drilled depth is noted in the welllog as the “plugged back", or PB,depth.

Next, the drilling fluid will beconditioned for perforating thecasing and the drilling assemblywill be pulled out. The casing and cement is then perforatedall the way through to the producing formation (Figure 4.5).These perforations are made with a perforating gun, whichcarries shaped charges, or bullets. The perforating gun is

lowered into the hole on an armored, multi-core electric cable.When the perforating gun is positioned at the correct depth,the shaped charges are electrically detonated and a knowninterval of casing and cement will be fully penetrated with 4shots, or holes, per foot. The vertical length of perforationsmade will depend on the length of perforating gun, or guns,used.

Figure 4.4. Drilling outcement plug

Figure 4.5. Perforatingcasing


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When the perforating operation is complete and the last

perforating gun is removed, the drilling assembly, completewith casing reamer, is run to bottom. Any tight spots arereamed by rotating the drilling assembly as it moves up and

down through the tight spots that may have resulted fromdistortion of the casing during the perforating operation.After this operation, the drilling assembly is carefully pulledout taking care not to “swab“ the well in as the producingformation is now able to flow into the casing through the

perforations.

The Production Tubing StringThe rig is then set up to run the production tubing anddownhole production assembly into the casing. The illustra-tion in Figure 4.6 shows completion using a single tubingstring. In this case, the bottom of the tubing is equipped witha tubing plug nipple, with internal profile, to receive a tubingplug or tool. These tubing plug profiles are used extensivelyin down hole completion assemblies, especially as the comple-

tion becomes more complex. The plugs and tools set in theseinternal tubing profiles are run on wireline, usually by awireline service company.

The next item up in the tubing string is a blast joint. Blast jointsare used, in lengths, to overlap the perforated interval andresist the potentially erosive wear that might result from avery productive zone, either oil or gas, as it enters the well bore.

The next part of the downhole assembly is a hydraulically-set

packer. The packer is set by applying pressure to the tubingstring when it is in place and a tubing plug has been set in the bottom tubing plug nipple. The increase in pressure drivestapered segments together which, in turn, force the slip seg-ments outwards to the bit into the production casing. At thesame time, the synthetic rubber sealing elements are squeezedtogether to seal off the tubing casing annulus. The energy inthe seals and slips are maintained after the hydraulic pressure

PACKER

DRILLING FLUID

Figure 4.6. Installing TubingString

CIRCULATINGJOINT ORSLIDING SLEEVE

SEALINGOVERSHOTOR BLAST JOINT

BLAST JOINT

PRODUCING

FORAMTION

PRODUCTIONCASING

TUBING PLUGNIPPLE

BLAST JOINT


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is released by a ratchet or wicker preparation within thepacker body. Mechanically set packers are commonly used inthis type of downhole completion.

The next item of equipment shown in the illustration is an-other blast joint, again placed to overlap the upper perforatedinterval.

The next piece of equipment shown is a tubing overshot thatenables the lower part of the completion assembly to be left inplace so that the tubing can be pulled for inspection or modi-

fication. These tubing overshots are equipped with recover-able seals in the overshot section and are usually designed torelease with right-hand or left-hand rotation, as required. Themandrel section of the tubing overshot is usually equippedwith an internal plug profile.

The next item up is a circulating joint, or sliding sleeve. Thecirculating joint has an internal sleeve that can be moved up ordown to open or shut circulating ports. The internal sleeve hasa tubing plug profile so that a shifting tool can be set, and

locked into the sleeve. This operation is done on wireline.After the shifting operation is complete, the shifting tool will be recovered.

The rest of the tubing assembly shown consists of tubingterminating at the tubing plug bushing which is threaded ontothe last joint of tubing. The upper end of the tubing plug bushing is equipped with internal tubing threads so that a“landing joint” of tubing can be installed.

The assembly just described constitutes the entire tubing

assembly for our example. It by no means describes all of theequipment found in downhole completion assemblies and has been used only to illustrate typical components in our theo-retical well. All of the components and tubing are carefullymeasured prior to running to ensure their correct positioninside the production casing.

Figure 4.7. Illustration of atypical completion tubingstring

BLAST JOINT

CIRCULATING JOINT ORSLIDING SLEEVE

SEALING OVERSHOTBLAST JOINT

TUBING

TUBING PLUGNIPPLE

BLAST JOINT

PACKER

SLIPS

PACKER SEALINGELEMENT


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After the tubing assembly has been run, a “slick joint” tubinghanger will be installed on the last joint of tubing. The tubingplug bushing and the tubing landing joint will then be added.Next, the entire assembly is slowly lowered into place until thetubing hanger seats and seals in the internal profile of thetubing head.

A tubing plug will then be run on wireline and set in the bottom tubing plug nipple. The tubing hanger seals will be

externally pressure tested and, assuming tests were success-ful, the hydraulic packer will be set by applying sufficientinternal hydraulic pressure to the tubing string. These settingpressures can range from 1,000 psi or more. The setting of thepacker can usually be noted by a sudden jolt in the tubingstring. If a shear out plug has been used in the bottom of thetubing string instead of a tubing plug, then a sudden drop inpressure will be noted after the setting pressure has beenreached and the plug shears out of the bottom of the tubing.After the hydraulic packer is set, the landing joint of tubing is

removed. The BOP stack is removed and the tubing bonnet is bolted to the tubing head spool (Figure 4.8). This traps andseals the tubing plug bushing.

The production tree, or christmas tree, can then be bolted to thetubing bonnet. The next step is to displace the drilling fluidfrom the tubing and the tubing casing annulus. This is done by first mounting a wireline lubricator on top of the produc-tion tree. The wireline service company will then open theswab valve and two production valves on the tree and thenlower the shifting tool down to the circulating sleeve. The

sleeve will be moved to the open position so that the circulat-ing ports are open. The drilling fluid is displaced by water orcrude oil by pumping down the tubing by way of the upperwing valve and taking the annulus returns through the annu-lus wing outlets.

Next, the wireline operator will shift the sleeve in the circulat-ing joint to the closed position and retrieve the shifting tool. A

TREE CAP

Figure 4.8. Nipple down BOP Stack

142559179 drillin manual drill quip

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