3.1 drilling rigs and technologies - treccani, il portale del sapere...drilling rigs and...

3.1.1 Introduction

The term drilling indicates the whole complex ofoperations necessary to construct wells of circularsection applying excavation techniques not requiringdirect access by man. To drill a well it is necessary tocarry out simultaneously the following actions: a) toovercome the resistance of the rock, crushing it intosmall particles measuring just a few mm; b) to removethe rock particles, while still acting on fresh material;c) to maintain the stability of the walls of the hole; d)to prevent the fluids contained in the drilledformations from entering the well. This can beachieved by various drilling techniques. In this chapterrotary drilling rigs will be examined. These are, inpractice, the only ones operating today in the field ofhydrocarbons exploration and production. The drillingrigs used on land are complexes of mobile equipmentwhich can be moved in reasonably short times fromone drill site to another, drilling a series of wells. Inparticular, the typical rotary rig for drilling onshoremedium to deep wells, indicatively more than 3,000metres, will be described below. Rigs for shallowerdepths use analogous but somewhat simplertechniques because of the smaller stresses to which therig is subject. See Chapter 3.4 for offshore drilling.

In rotary drilling the rock is bored using a cuttingtool called the bit, which is rotated and simultaneouslyforced against the rock at the bottom of the hole by adrill string consisting of hollow steel pipes of circularsection screwed together. The cuttings produced by thebit are transported up to the surface by a drilling fluid,usually a liquid (mud or water), or else a gas or foam,circulated in the pipes down to the bit and thence tothe surface. The rotation is transmitted to the bit fromthe surface by a device called the rotary table (or by aparticular drive head), or by downhole motors located

directly above the bit. After having drilled a certainlength of hole, in order to guarantee its stability it hasto be cased with steel pipes, called casings, joinedtogether by threaded sleeves. The space between thecasing and the hole is then filled with cement slurry toensure a hydraulic and mechanical seal. The finaldepth of the well is accomplished by drilling holes ofdecreasing diameter, successively protected bycasings, likewise of decreasing diameter, producing astructure made up of concentric tubular elements (seeSection 3.1.9). Apart from the difficulties of drillingthe rocks encountered, the number of casings alsodepends on the depth of the well and on the reason fordrilling.

The drilling rig consists of a set of equipment andmachinery located on the so-called drilling site.Normally the rig is not owned by the oil company butby drilling service companies, which hire out the rigcomplete with operators and which construct the wellaccording to the client’s specifications. The mostimportant items of equipment are set out in Fig. 1. Ithas already been mentioned that the bit is rotated by aset of hollow pipes ending with a special pipe ofsquare or hexagonal section (the kelly) which passesthrough the rotary table and transmits the rotationalmovement. The kelly is screwed to drilling swivelwhich in turn is connected to the hook controlled andoperated by a hoist and a derrick. The drilling swivelserves to let the drilling fluid pass from the surfacehydraulic circuit to the interior of the pipes. The drillstring is operated with a hoisting system formed by ahook connected to a series of sheaves (crown andtravelling blocks) operated by a wire rope (or drillingline) and a hoist (or drawworks). The crown block islocated at the top of the derrick, which is the moststriking and characteristic feature of the drilling rig.The function of the derrick is to support the crown

303VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT

3.1

Drilling rigs and technologies

304 ENCYCLOPAEDIA OF HYDROCARBONS

DRILLING AND COMPLETION OF WELLS

1 crown block

2 mast

3 monkey board

4 traveling block

5 hook

6 swivel

7 elevators

8 kelly

9 kelly bushing

10 master bushing

11 mousehole

12 rathole

13 drawworks

14 weight indicator

15 driller's console

16 doghouse

17 rotary hose

18 accumulator unit

19 catwalk

20 pipe ramp

21 pipe rack

22 substructure

23 mud return line

24 shale shaker

25 choke manifold

26 mud gas separator

27 degasser

28 reserve pit

29 mud pits

30 desander

31 desilter

32 mud pumps

33 mud discharge lines

34 bulk mud components storage

35 mud house

36 water tank

37 fuel storage

38 engines and generators

39 drilling line

1

2

3

4

5

6

7

8

9

1011

12

13

14

1516

17

18

19

20

21

22

23

24

25

2627

28

29

29

3031

3232

33

33

34

35

3637

38

39

Fig. 1. Main components of a drilling rig.

block, and it is tall enough to permit the useful verticaloperation of the travelling block, and therefore of thedrill string in the hole. The drilling fluid circulates in aclosed circuit: it enters by way of the swivel, flowsthrough the drill string and the bit, cleans the bottomof the hole, then rises through the space between thedrill string and the hole, reaching the shale shakerwhich separates the cuttings from the fluid, and thenarrives to the mud tanks. It is subsequently conveyedto the mud pumps which circulate it to the drillingswivel once more via a rigid pipe (standpipe) and aflexible one (hose), closing the circuit. Circulation ofthe drilling fluid, commonly known as mud, is thecharacteristic element of rotary drilling, as it permitsthe continuous clearance of the cuttings from thebottom of the hole. Deepening the well calls for theperiodic addition of new drilling pipes, while replacingthe bit when it is worn down requires the extraction (ortrip-out) of the whole drill string. This operation,which takes a great deal of time, is called theroundtrip.

Nowadays, hydrocarbon exploration andproduction are based on the drilling of wells whosedepth, in a few cases, has even exceeded 10 km. In thelast few decades the need to limit the costs entailed byconsiderable technical problems has led to noteworthyprogress in optimizing drilling techniques, inknowledge of the problems connected with drillingand with the stability of rocks at great depths, and inthe formulation of muds for high pressures andtemperatures. In drilling the main concern is achievinghigh rates of penetration under safe conditions, andreducing the idle (or down) time. Indeed, it is recalledthat at depths of around 3,000 m, it takesapproximately 7 hours to trip-out the drill string fromthe hole and subsequently to run it back in (forexample, to change the bit); and this increases to some12 hours if the depth is around 4,000 m. These arerather lengthy times when it is considered that theaverage life on bottom of a bit at such depths issomething like 50-100 drilling hours, and that the hirecost (or rig rate) of a large onshore drilling rig is in therange of 25,000 euro/day, while for offshore rigs it canexceed 200,000 euro/day.

3.1.2 Rotary drilling rigs

Every drill rig is constructed in type, size and capacityaccording to the aims and the characteristics of thehole to be drilled. Operatively, the choice of the typeof rig is based on the well requirements, consideringthat the hire cost is proportional to the capacity andthe technological characteristics of the rig. Thesimplest criterion for the classification of drilling rigs

is based on the type of location (for drilling wells onland or offshore), and on their capacity, i.e. theeffective drilling depth that can be attained. Accordingto this classification, onshore drilling rigs fall into fourgroups: a) light rigs, down to 2,000 m; b) mediumrigs, to 4,000 m; c) heavy rigs, to 6,000 m; and d) ultra-heavy rigs for greater depths. Increasingcapacity is matched by increasing both maximumhook load capacity and derrick strength. Anothercriterion for classification is the power installed on therig, which for oil well drilling is in the range of at least10 HP every 100 feet in depth, equal to approximately250 W/m. According to this criterion, the precedingclassification becomes: a) light rigs, up to 650 HP; b) medium rigs, up to 1,300 HP; c) heavy rigs, up to2,000 HP; and d) ultra-heavy rigs, 3,000 HP and more.

The drilling rig is transported to and set up on alevelled area called the drilling site, which contains thederrick, the service equipment, the stores and theliving space (crew quarters). The drilling site, with asurface area of some 1 to 2 hectares is thustransformed into a full-scale operative site, which iseventually dismantled at the end of drilling operations.This period could last from just a few weeks to morethan a year in the case of exploratory wells in difficultsituations. After constructing the access road toprovide a link to the ordinary road system (if suchexists), the cellar, the foundations for the drilling rig,and the water, mud and waste pits/tanks areconstructed within the drilling site area. The spaceswhere the containers for the offices, the warehouse,the workshop, the services and the crew quarters willbe located are then organized, if the site is far awayfrom inhabited centres. It is self-evident that theseareas have to be arranged in a rational manner,occupying the least possible space, and fenced in tokeep out persons not engaged in the operations. Thesite is provided with drainage ditches to collect rainwater and any liquids accidentally spilt, and is fullywaterproofed.

Drilling site preparation entails earthworks andlevelling, with the removal of the topsoil and placing a30-40 cm thick layer of coarse gravel, a sheet of PVC(Poly Vinyl Chloride) for waterproofing purposes, andfinally a 40-50 cm thick layer of sandy gravel. Thesegranular materials must be well compacted, as it has tosupport heavy trucks bringing in personnel, materialsand utilities to the site. A rectangular or square shapedcellar is dug in the centre of the site vertically abovethe well and is lined with thrust-bearing walls and areinforced concrete slab, leaving a hole where the wellis to be positioned. This cellar serves to create a clearwork area where the future wellhead will be located,and its depth must be in keeping with the height of thesafety equipment necessary in the drilling stage. The


DRILLING RIGS AND TECHNOLOGIES

size of the cellar varies according to the type of rig andwellhead, and will be between 2 and 3 m in depth, withan area of about 10 to 15 square metres. The waste pitsare excavated with sloping sides, 2-3 m deep, andmeasure up to 100 square metres or more in area; theyare waterproofed with sheets of PVC and sometimeswith layers of bentonite. When the drilling sitepreparation works have been completed, the first well-construction operation will be carried out, i.e. theinstallation of the conductor pipe, a 10-50 m long steelpipe having a diameter of 70-100 cm. If the subsoil iscomposed of loose sediments, the conductor pipe isfixed using a piledriver analogous to the one used incivil engineering for fixing foundation piles.

The site must, by law, be large enough to storeinflammable or dangerous materials at a safe distancefrom the wellhead. Furthermore, it must enable a flareto be set up, to burn off any hydrocarbons that mightcome to the surface during drilling, and it must allowthe safety line for the derrickman to be anchored at asafe distance (see Section 3.1.3). At the end of drillingoperations, if the well turns out to be dry, the locationis restored to its pre-existing environmental state andis handed back to its owner; if instead the well isproductive, production equipment is installed on thewellhead and it is permanently fenced into a smallerarea of a few hundred square metres.

During the drilling of a well, the most importantfunction on site is supervising and verifying thedrilling operations. This job is assigned to arepresentative of the operator, known as the drillingassistant. This person must be fully qualified and ofproven technical and decision-making competence,and is assigned the task of implementing the wellproject as drawn up in the programming stage, fixingthe working sequence for site activities. The drillingassistant orders and controls the properimplementation of every operation, supervising safetymeasures and informing the central control office ofthe progress of operations. Service companies(contractors) also frequently operate on the locationfor the execution of specialist operations (cementing,logging, geological assistance, etc.). A number ofcontractors have their own team on site with arepresentative; other contractors instead operate on acall basis, for short periods. The actual handling ofdrilling operations is assigned to a special drillingcrew, whose numbers vary from rig to rig. Generallyspeaking, in onshore locations there is a foreman(crew chief), in charge of site equipment, a driller, aderrickman, three drill assistants, one site man,maintenance hands (electrician and mechanic) and oneor more watchmen. The driller works on the derrickfloor, is in control of all drilling machinery and carriesout the sequence of operations scheduled for making

the hole. The derrickman operates on a platform insidethe derrick and controls the pipes in the stem rackduring tripping operations. The drill hands, headed bythe driller, see to screwing on (break-in) andunscrewing (break-out) the joints of the pipes duringdrilling and tripping operations, and keeping thederrick floor clean. In offshore drilling rigs, the crewis more numerous and specialized, as higher standardsare set for such operations. All drilling site personnelwork in day shifts, generally of twelve hours each. Infact, drilling is never suspended, except in just a few ofthe phases, because of the high cost of renting the rig.

3.1.3 Hoisting system

The hoisting system is the set of equipment necessaryfor handling any material inside the well, in particularthe drill string and the casing. It consists of a structuralpart (derrick and substructure), the complex of thecrown and travelling block, the drawworks (hoist) andthe drilling line. The substructure is the supportingbase for the derrick, the drawworks and the rotarytable, and constitutes the working floor for operations,or drilling floor, being elevated with respect to groundlevel. The substructure is a reticular structure of steelbeams, that can easily be dismantled, and rests onconcrete foundations or on a base of wooden planksaround the cellar. Its height varies from a few metresup to 10 m in the largest rigs, and must be such as topermit the assembly of the safety equipment on thewellhead.

The derrick is an open-framework structure of steelbeams, whose function is to hold the ensemble ofsheaves at its top, known as the crown block, on whichall of the items of equipment operated in the well or onthe drilling floor are suspended. It must also containthe drill string during tripping, subdivided into lengths(i.e. 2-, 3-, or 4-piece sections of drill pipes screwedtogether called stands) depending on the height of the derrick. In fact, the height of the derrick must besuch as to permit the vertical movement of thetravelling block for a distance greater than theequivalent of one stand. For example, to handle a standof 3 drill pipes (about 27 m long) the derrick has to beabout 40 m high. The derrick is designed to resist theloads tripped in and out of the well in the operatingphases, which induce both static and dynamic stresses.Every derrick has a rated load capacity, defined byAPI (American Petroleum Institute) standards, whichestablish the maximum hook load. On the basis oftheir construction characteristics, derricks may beclassed as conventional ones (derrick) or mast type,according to the way in which they are assembled anddismantled.



A derrick (Fig. 2) is a structure of steel beams ortubes that can be completely dismantled andreassembled. The elements forming the derrick arerelatively small and can easily be handled;nevertheless, the assembly of the entire structurerequires quite a long time. Derricks, once made oftimber, were the most usual type of structures until the1930s, when they started to be replaced by mast-typestructures, which were easier to operate. Facing oneside of the derrick in the drilling site there is a pipeyard where all the tubular materials that have to belowered into the well (pipes, casing, etc.) are placed ona rack. The pipe yard is connected to the drilling floorby an inclined slide, making it easier to pick up thepipes. About two-thirds of the height of the derrick isthe derrickman’s platform, which stands out for about1 m, and on which the derrickman works duringtripping, helping to stack the pipe lengths tripped outfrom the well on a special pipe rack. The derrickman’ssafety line is hooked onto this platform; this is a cableanchored to the ground at a suitable distance, enablingthe operator to make a quick getaway with a cablewayif there is danger of a blowout. Nowadays derricks,although more stable and robust than masts, are onlyused on platforms for offshore drilling, where thestructure never has to be dismantled.

The mast (Fig. 3) is a structure of modular,preassembled steel beams, hinged with lock-pins,which can be raised or dismantled in a few hours.Obviously the mast possesses all the functionalcapacities of a derrick. Masts are generally self-elevating. After the girders of the substructure and ofthe drilling floor have been placed above the cellar(these also having been preassembled in modules), andthe various parts of the mast have been assembledhorizontally on the site, alongside the substructure, themast is raised into a vertical position using cables andthe drawworks supplied with the rig. Light andmedium rigs, with reclinable masts, can also be self-propelled (portable masts) as they are mounted ontrucks. They are used to carry out maintenance jobs onwells in production, or to drill water wells, that is,operations that do not take much time, and thattherefore require the use of a rig that can betransferred rapidly. Portable masts have less resistanceto horizontal loads (e.g. due to the wind) and so it isnecessary to guy them with steel cables. For particularsituations of difficult logistics, e.g. drilling ininaccessible or high mountain areas, block-assembledrigs are available, as they are easier to transport byhelicopter or by plane.

As has been mentioned, the sheaves of the crownblock are situated at the top of the derrick. Themechanism, with a fixed (crown) block and a mobile(travelling) one, consists of an ensemble of sheaveslinked by a wire rope, worked by the drawworks (Fig. 4 B). The crown block bears the load applied atthe hook and its function is to reduce the wire ropetension required to pull the tubular material used todrill the well. It at the top of the rig consists of a set ofsheaves (usually from 3 to 7) supported by aframework of steel beams. The travelling blockconsists of another set of sheaves (one fewer than forthe crown block), mounted on an axis connected to thehook (Fig. 4 A). The number of sheaves in the crownand travelling block is chosen on the basis of the ratedcapacity of the tower and the rate of pulling, which isinversely proportional to the number of lines of wirerope connecting the travelling block and the crownblock; the number of lines also defines the tension tobe supplied by the drawworks.The hook consists of anupper section, fixed to the travelling block, and a lowersection, which is the actual hook. The two sections arenot rigidly joined, but connected by a spring resting ona bearing, which allows the hook to rotate and dampshook load during lifting. In modern rigs the travellingblock and the hook form a single unit. The hook ischaracterized by its rated load capacity, which in thelargest rigs can even exceed 500 t.

The drawworks is the machine that transmits thepower to operate the equipment in the well. The basic



Fig. 2. Derrick type drilling rig.

Fig. 3. Mast type drilling rig.

components of the drawworks are an engine, one ormore drums containing a steel cable, and the brakes(Fig. 5). Apart from the engine, described below, thedrawworks is made up of the following elements: amain drum (hoisting drum), around which thedrilling line (used for tripping the drill string and thecasing elements and for raising and lowering themast) is wound; a fast drum, smaller in diameter thanthe hoisting drum, around which a smaller wire rope(used for the rapid manipulation of relatively lightmaterial) is wound: and the braking system,consisting of a main brake and auxiliary brakes,placed at the sides of the hoisting drum shaft. Themain brake is a strongly-built, band brake, used tostop the drill string as it is being lowered, or torelease it slowly during drilling. The band brake isthe only device that can stop the drum completely,and is used mainly for this purpose. Its use as anenergy dissipator is limited, as the ribbons wouldbecome worn out too quickly. To limit wear on theribbons, the hoist also has auxiliary brakes.Normally a hydraulic brake and an electromagneticbrake are used, although these cannot stop thehoisting drum completely and they cannot be usedalone. The advantages of using the electromagneticbrake are that there are no parts in contact andtherefore subject to wear and tear, that it is easier toadjust than the hydraulic brake and that it exerts abraking action even at slow speeds. But it must bekept in mind that lack of electric current causes theinstantaneous interruption of the braking effect.Finally, very often the drawworks is fitted with agear change and a clutch, to permit a power uptakealso at low speed. The mechanical or hydraulic gearchange serves to optimize the use of the powersupplied by the engine.

The drilling line contained in the hoist drumsconsists of helically-wound steel-wire strands arounda plastic, vegetable fibre or steel core. The first endof the drilling line (fast line) is wound around thehoist drum, after which it passes alternately over thesheaves of the travelling block and of the crownblock, while the other end (dead line) is anchored toan element of the substructure. The tension of theline is measured on this anchorage, and this makes itpossible to calculate the weight of the equipmentsuspended from the hook (e.g. drill string, casing,etc.). Through being wound around the drum andover the block sheaves, the line is subject to wear andtear, to weakening of the wires (due to localoverheating) and to fatigue due to cyclical variationsof tension in the winding over the sheaves and thedrum. One method of assessing the state of wear andtear of the drilling line is visual inspection, but this isuncommon because of the uncertainty involved, the



drillingline

crown block

travelling block

derrick

drawworks (hoist)

hook

drum brake

drawworks

drawworksdrum

fastline

drilling line

crown block

travelling block

deadline

deadline anchor

supply reel

Fig. 4. Lifting system mounted on a derrick. Here are visible the drawworks, the crown block, the travelling block, the drilling line and the hook.

A

B

practical difficulties and the time required. A moreobjective method is to associate the wear and tear ofthe drilling line with the work actually performed,which can be calculated as a function of the distancetravelled under load, and fixing a maximumadmissible limit. The work done by the line variesbetween very broad limits and depends on thenumber of operations carried out. So as to have a linethat is always new in the points of greatest wear andtear, it is periodically allowed to slip along its route,winding one section around the hoist drum andunwinding an equal section from a back-up drumcontaining new line, situated below the anchorage ofthe dead line. This operation, called slipping and cut-off, is performed when a given value of the workcarried out by the line has been reached. Afterrepeated slipping, there is no more space available onthe drum and cut-off takes place, which consists ofremoving 2 or 3 layers of the drilling line wound upin the slipping. The time required to perform aslipping is minimal, whereas that for a cut-off ismuch longer.

3.1.4 Rotation system

The system of rotation is intended to cause the drillstring to rotate, and it consists of the rotary table, thekelly and the swivel (Fig. 6). In modern rigs there isoften also a top drive which groups together the

functions of the three items of equipment mentionedabove. In particular cases it is preferred to make onlythe drill-bit rotate by means of a downhole motor (asthese motors are an integral part of the drill string,they will be described together with the othercomponents thereof).

The rotary table, located on the drilling floor (orrig floor), is composed of a fixed base whichsupports, by means of bearings, a rotating platformwith a central hole. The lower part of the rotatingplatform has a crown gear into which fits a pinion,operated by a motor. The rotary table makes the drillstring rotate and supports its weight duringoperations or during the connection of a new drillpipe, when it cannot be borne by the hook. Duringthe connection of a new drill pipe (or of a section ofcasing), the string is suspended over the central holeof the rotary table by means of slips and the entireload supported by the hook is transferred from thederrick to the drilling floor supporting beams. Therotating platform of the rotary table houses themaster bushing which can be removed to allowequipment with a large diameter to pass through. Themaster bushing, when in its normal working position,enable the slips to be lodged for hanging the drillstring during tripping or new pipe connection, andpermit the insertion of the kelly bushing whichcauses the kelly to rotate, the kelly bushing (or four-pin drive kelly bushing) being plugged into holes inthe master bushing. The rotary table, standardized toAPI regulations, is defined by the nominal diametergoing through the central hole (usually between 20''and 50'') and by the load it is able to bear. The powerof the rotary table depends on the depth of the hole(most of the power required to make the drill stringrotate is in fact dissipated in viscous friction in themud and in sliding friction against the walls of thehole) and ranges from a few tens up to a few hundredkW, while the velocity of rotation depends on thedrilling operation and can be regulated from a fewtens up to about 140 revs per minute.

The kelly is a pipe of square or hexagonal sectionthat transmits the motion of the rotary table to the drillstring. It receives this motion from the kelly bushing,to which it is joined through a sliding coupling, so thatit can move vertically also when it is engaged intransmitting the rotation. Thanks to this it is possibleto continuously regulate the weight on the bit withoutinterrupting the rotation. Until the 1940s square kellieswere used, but now hexagonal kellies have replacedthem. The latter are stronger and are also balanceddynamically so as not to vibrate during rotation. Thekelly is longer than a drill pipe, because the verticalmovement in the rotary table must allow a new pipe tobe added, at the same time keeping the bit at a safe



electricmotor

electricmotor

chain and sprocket drive

low drum clutchhigh drumclutch

sand reel clutch

sand reel

drum shaft

input shaft

output shaft

brake lever

auxiliarybrake

drillerconsole

hoisting drum

chainand sprocketdrive

Fig. 5. Components of the drawworks.

distance from the bottom of the well. Kellies arenormally 12-16 m long, to which corresponds a usefulsliding length of 11-15 m, respectively. For safetyreasons the kelly is fitted with two internal valves, oneat the bottom and the other at the top, which are usefulin the well control phase.

The kelly is screwed to the swivel, which is thepoint of connection between the rotating drill stem (ordrill string), the hook and the non-rotating mud hose.The swivel has a fixed and a mobile part, and has thetwofold function of supporting the rotating drill stingand of connecting the mud hose with the inner part ofthe pipes. The swivel is a very robust mechanism, ableto support a strong rotating axial load, through an oil-bath thrust bearing, guaranteeing, at the same time, aperfect hydraulic seal. The mud injection pressure can

in fact exceed 30 MPa and the weight of the drillstring 200 t. The swivel, suspended from the hook bymeans of a robust steel handle (or bail), follows thevertical movements of the hook and therefore must beconnected to the standpipe by a flexible pipe made ofsteel-wire reinforced rubber (mud hose).

The top drive is a relatively recent piece ofequipment, introduced towards the mid-1980s,grouping together in a single unit the equipment forconnecting the drill pipes, rotation of the drill stringand circulation of the fluid (Fig. 7). By using the topdrive, it is no longer necessary to have a kelly and aswivel, and in theory the rig could even do withoutthe rotary table. The basic parts of the top drive are asmall injector head (swivel), an electric or hydraulicmotor which enables the drill string to rotate, and anautomated pipe handling system. The top drive unit issuspended from the hook and is guided by twovertical rails fixed to the derrick, which provide thereactive torque necessary to prevent the rotation ofthe whole complex and to allow free verticalmovement.

The use of the top drive instead of the rotary tableoffers numerous advantages, including: a) thepossibility of ‘drilling by stands’ (adding the pipes bystands, and not individually), allowing greater controlof drilling; b) the reduction of the time required toconnect the pipes, with less risk of accidents fordrilling operators; c) the possibility of performing thetrip-out operation while circulating mud and rotatingthe string (back reaming), impossible with the rotarytable and useful for preventing the drill string frombecoming stuck; and d) the possibility of obtaining



rotary hose

hook

swivel

swivel coupling

(upper) kelly cock

lower kelly cock

kelly saver sub

kelly

rotary table(four pin drive)kelly bushing

master bushing

rotary table

(four pin drive)kelly bushing

master bushing

A

Fig. 6. System of rotation with rotary table: A, kelly inside the rotary table with details of the drill string; B, close-up of rotary table components.

B

longer cores, as intermediate connections areeliminated. However, the system has a number ofdisadvantages, such as the structural modificationsthat have to be made to the rig to be able to house thetop drive (the rails, strengthening the derrick towithstand torsional stresses, the greater height of thederrick due to the fact that the top drive system islonger than the swivel), the presence of superelevatedlive loads and electrical and hydraulic serviceequipment. Moreover, as the system is quite complex,the top drive is rather costly and subject to frequentmaintenance. In spite of this, the top drive representsthe major technological advance in rotary drilling inthe last half century, and its use – absolutely essentialin modern rigs – has enabled drilling times to besignificantly reduced.

Equipment for handling the drill stringOn the rig floor there are certain supplementary

items of equipment not strictly forming part of the

rotary system, but which serve for tripping the drillstring when the rotary table is in use, or for connectinga new pipe. To be able to carry out these operations, itis necessary to suspend the drill string inside themaster bushing of the rotary table using special slips.These are a sort of collar that can be opened, and arecomposed of metal segments with internal dies havinghardened steel teeth, and of external truncated coneshape. Slips of traditional type are positioned by handinside the master bushing; by slightly lowering thedrill string, the slips are forced to grip the outersurface of the pipe, enveloping it and supporting itwith a clamping effect (Fig. 8). In modern rigsautomatic slips are operated hydraulically, however, tofasten and unfasten the pipes, wrenches called tongsare needed, which is a sort of big adjustable spanner.Two tongs are necessary to fasten the pipes, one ofthem fixed to one of the derrick legs, which blocks thelower drill pipe suspended from and wedged in therotary table, and the other one mobile, operated by acable running from a winch or by a hydraulic piston.The latter grips the upper pipe and rotates it, so that it



Fig. 7. A, top drive mounted on the derrick;B, a particular of the top drive.

rotary table

slipsdrill pipe joint

tapered bowl

masterbushing

Fig. 8. Slips for hanging the string on rotary table: A, drill pipe suspended inside the rotary table; B, close-up of pipe-slips.

A

B

A B

can be screwed (break-in) and unscrewed (break-out).In modern rigs, pneumatic or hydraulic power tongsare used, these having the advantage of applyingexactly the torque required for breaking-in, limitingthe wear and tear on the thread.

3.1.5 Circulation system

The circulation system consists of mud pumps,distribution lines, and the mud cleaning andaccumulation system (Fig. 9). It is the closed hydrauliccircuit which allows the mud to flow from the surfaceto the bottom of the hole, inside the drill string, andsubsequently back to the surface, in the drillstring-borehole annulus. The mud from the hole has to havethe cuttings removed before being reinjected to thebottom of the hole.

The mud pumps supply the energy necessary forcirculation. They are generally positive-displacementpiston pumps, because of the greater head theseprovide compared with other types of pump, e.g.centrifugal pumps. Mud pumps, with 2 or 3 pistons(duplex or triplex pumps), may be single – or dual-acting, and receive their power from an electric motorindependent from other uses. The pistons are ofrubber-lined steel to obtain a good seal and to lessenthe wear and tear on the cylinders, due to the abrasivecuttings suspended in the mud. The pump cylindersand pistons are interchangeable, with differentdiameters, so as to be able to vary the flow rate andadjust it to the requirements of the well. Obviously, theflow rate is a function of the piston diameter, of thestroke and of the rate of rotation of the driving shaft,and is in the range of a few m3/min. The ever-increasing depth reached by the wells and the



bulk mud bins

mud house

mud return line

standpipe

rotary hose

kelly

drill pipe

drill collar

annulus

mud pump

dumpvalves

shaker tank

reserve tank

suction tank

suction line

mud mixinghopper

centrifugalmixing pump

chemical tank

borehole

bit

shale slide

shale shaker

Fig. 9. System of mud circulation.

introduction of new drilling equipment (downholemotors, MWD, Measurements While Drilling, etc., seeSection 3.1.7) have increased the power necessary forthe pumps. Compared with the few hundred kW of the1950s rigs, today pump power can exceed 1,500 kW.

In a rig there are always at least two mud pumps,connected in parallel, both for safety reasons (it isnecessary to have continuous mud circulation) and forflexibility of operation. Due to the reciprocating actionintrinsic to their operation, mud pumps supply acapacity and pressure that pulsate in time. Theseoscillations are harmful to the components of thecircuit and to pump efficiency, and therefore adampener is installed along the line downstream of thepumps; this consists of a vessel containing gas(generally nitrogen) under pressure, the greatercompressibility of which compared with mud enablesthe flow and pressure to be regularized.

Downstream of the pumps, the mud is conveyed tothe surface distribution lines (or drill manifold), whichis a system of pipes and valves that allows the mud tobe sent to the swivel or to be distributed for other uses.From the pumps the mud can be sent: to the swivel,through the surface manifold, the standpipe and theflexible hose; to the wellhead, under the safetyequipment, through a dedicated kill line, to be fed intothe annulus to keep the well filled during tripping, orfor special circulation during blowout control; and to asurface circuit that links up various items ofequipment and makes it possible not to send the fluidinto the well while keeping it in motion.

The items of equipment that separate the cuttings,removed by the mud at the bottom of the hole, arecalled shale shakers and hydrocyclones. The mud exitsfrom the well through a large pipe and is firstconveyed to the shale shakers which separate themajority of the cuttings. The shale shaker is a devicefitted with one or more overlapping screens of variousmesh sizes, slightly tilted and caused to vibrate byrotating shafts unbalanced by eccentric masses. Theform, amplitude and frequency of the vibrationsdepend on the characteristics of the mud to be treated,and must be easily adjustable so as to optimize theminimum time on the screen. The dimension of thecuttings removable by the shaker depends on the meshsize used, even if in practice it never goes below 100 mm.The finest particles (fine sand and silt) are removed downstream of the shakers, by means of thehydrocyclones. In the more sophisticated rigs, twobatteries of hydrocyclones in series are adopted. Thefirst series is employed for separating the fine sand(down to 70 mm); usually these are two hydrocyclones,called desanders, arranged in parallel, and are able totreat the entire circulation flow. The second seriesserves to separate the silt (down to 30 mm), and is

formed by several smaller-diameter hydrocyclones,called desilters, which perform a more accurateseparation. To eliminate even smaller solid particles(e.g. to recover the barite, the material used to increasethe density of the muds), centrifuges are used, i.e.cylinders rotating at high speed, which are alsoemployed for dehydrating the exhausted drilling mudand cuttings before they are conveyed to the dumps.The cuttings are stored in waste tanks or in a concretepit constructed under the shale shaker. They aretransported periodically to authorized dumps, possiblyafter being treated in conformity with their degree ofcontamination by chemical agents or by hydrocarbons.

During drilling the gas contained in the pores ofthe rocks might enter the well and form a solution oremulsion with the mud. The in-flow of smallquantities of gas is inevitable when drilling throughgas-saturated rocks, but there could be appreciable in-flows when the pressure of the mud at the bottom ofthe hole becomes less than that of the gas contained inthe rock pores. Small quantities of gas in muds of lowviscosity are liberated on the shaker, by simpleaeration. If this is not sufficient, the entire mud loadis sent to specific units called degassers. These arespecial vessels that operate according to two differentprinciples, either by depression with a vacuum pumpor by mechanical agitation and turbulence. Theseparated gas is then burnt in the flare installed at asafe distance from the rig.

Downstream from the mud cleaning system thereare various storage pits or tanks. The active mud pits,as they are called, contain the mud that circulates inthe well. The reserve pits contain the mud to make upany circulation losses, while other pits contain theheavy mud, ready for prompt use in the event of lossof hydraulic control of the well. These pits are robustrectangular containers of sheet steel, each with acapacity of 30-40 m3. For safety reasons the overallcapacity of the mud pits must be more than half thevolume of the well, which is in the order of somehundreds of cubic metres. Each pit is provided withmechanical or pneumatic agitators or stirrers to keepthe mud homogeneous. At the outlet of the active pitsthe mud is scooped up by a centrifugal pump whichsends it back to the mud pumps at a pressure of a fewbars, to improve the volumetric efficiency. It isrecalled that during operations the volume of the mudin the well must be compensated for the volume of thepipes removed or added so as to keep the hydraulichead at the bottom of the hole constant. A cylindricalfilling tank called possum belly, which is locatedalongside the shaker, is used for this purpose. Duringtripping-out operations, the level of the fluid in thewell sinks and is made up with the fluid contained inthe possum belly, which is fitted with a level gauge in



order to determine the correct make-up volume.Obviously the opposite is the case for tripping-inoperations.

3.1.6 Power generation and distribution system

In a drilling site power is needed to run the machinesdriving the main components of the rig, such as thedrawworks, the pumps, the rotary table and theengines of the various auxiliary facilities (compressedair, safety systems, centrifugal pumps, lighting,services, etc.). Ideally, it would be convenient to obtainelectricity from the public network, but this is rarelypossible, because of the remote location of themajority of the sites, and it is therefore necessary toproduce power on the various sites using primemovers. In the past the prime movers used in drillingsites were steam engines, which, while having certainundoubted advantages (characteristic curves suitablefor direct connection to users, robust construction,ease of use), have been abandoned due to their lowefficiency, heavy weight and huge water consumption.At present the prime movers used are Otto or dieselcycle internal combustion engines, or else turbogasunits, used only where low-cost methane is available.The disadvantage of internal combustion engines isthat they cannot be directly coupled with userfacilities, but this is offset by their easy transport, highefficiency and convenient fuel supplies. Drilling rigsare classified by the way in which power is transmittedfrom the prime movers to the main facilities,distinguishing between mechanical and electrical driverigs (diesel-electric if the prime mover is diesel).

In drilling rigs with mechanical drive the powerproduced by the prime movers is transmitted to themain users by a system of chains and sprockets, orbelts and pulleys. This transmission system iscontrolled with the help of clutches and gearboxes,which allow power to be conveyed to the requiredunit. The engines must be located close to the mainuser units, thus making the layout of the rig morecomplicated. Moreover, the characteristic curve ofinternal combustion engines is not suitable for directconnection to user units and therefore it is necessaryto insert a gearbox, which enables the characteristiccurve of the engine to be approximated to that of theuser unit. Another problem is the power take-off atlow running speed, as internal combustion engines donot supply power at a low number of revolutions. It isthus necessary to insert a clutch (only on small rigs,as beyond a certain power it is quickly burned out),or else a hydraulic joint or a torque converter. Thehydraulic joint is a component formed by two rotors

immersed in an oil bath, placed between the engineand the user unit. During start-up, the engine shaftcan supply a constant torque even if the user shaft isstopped (slippage of the joint equal to 100%,efficiency nil), hence allowing a gradual power off-take. During normal operation, however, the slippageof the clutch is low (2 to 8%) and therefore theefficiency is high. The torque converter is a sort ofhydraulic joint which, in addition to allowing agradual power take-off, makes it possible to vary thespeed and the torque, thanks to the insertion of astator between the rotors. The hydraulic torqueconverter acts in practice as a gearbox, which,however, vies against the efficiency, which duringnormal operation does not exceed 85%. Mechanical-drive rigs were very widely used in the past, butnowadays their use is limited to rigs of low andmedium potential. The mechanical transmissionefficiency varies between 75 and 85%, according towhether or not there is a torque converter.

In high-capacity rigs more flexibility in the layoutof the equipment and precise control of the powersupplied are required. For this reason more flexibleelectric (or, more precisely, diesel-electric) rigs havebeen developed, which are less bulky and lighter thanmechanical-drive rigs. In diesel-electric rigs, the mainuser units (the drawworks, the pumps and the rotary



control cabinet

electric generator

electric motor

mudpump

dieselengine

control driller'spanel

high peak load

rotary table

drawworks

lightest load

heavy load

generator 1

generator 2

generator 3

Fig. 10. Power generation and distribution system in an AC-DC plant.

table) are operated by independent electric engines.The following are therefore the components thatpermit the generation, distribution and use of power:prime movers, which transform the fuel intomechanical power, generators, which convert themechanical power into electrical energy, a powercontrol cabin, electricity lines, and lastly the DC(Direct Current) or AC (Alternating Current) motorsof the various units. Usually the motors of the mainunits are DC, and are preferred to AC motors becauseof their capacity to vary the speed continuously,supplying a high torque value whatever the runningconditions.

Two types of electric drive exist: the first with DCgeneration and DC user units (DC-DC drive), and thesecond with AC generation and DC user units (AC-DCdrive). In the case of DC-DC drive, the electric engineof each main unit is connected directly to a DCgenerator, worked by a prime mover (usually diesel).In a medium-size rig there are 4 prime movers and 3or 4 motors for the user units (one for the drawworks,one for each pump and, sometimes, one for the rotarytable). In large-size rigs there may be as many as 8motors. The advantage of the DC-DC drive system isits excellent efficiency, as the current does not have tobe rectified. The disadvantage, however, is that ofbeing a rigid system, as each DC generator isconnected to its own user unit, and passage from oneunit to another is not very flexible. In contrast, theAC-DC drive is a system formed by prime mover units(usually diesel motors) connected to AC generators,which supply all the user units without being linked toa specific one, through an power control cabin(Fig. 10). In this way the power of the prime mover canbe used rationally, stopping some units when thepower required diminishes. Moreover, AC generators,although larger in size, are less complicated and costlythan DC generators. If the main user units have DCmotors, for ease of control of the rate of rotation, it isnecessary to rectify part of the current by means of arectifier. However, nowadays DC motors are more andmore often being replaced by AC motors controlled byan inverter, which allows the rate of rotation to becontrolled very effectively.

3.1.7 The drill string

The drill string is an assemblage of hollow pipes ofcircular section, extending from the surface to thebottom of the hole. It has three functions: it takes thedrilling bit to the bottom of the hole, whiletransmitting its rotation and its vertical load to it; itpermits the circulation of the drilling fluid to thebottom of the hole; and it guides and controls the

trajectory of the hole. Starting from the surface, itconsists of a kelly, drill pipes, intermediate pipes,drill collars and a number of accessory items ofequipment (stabilizers, reamers, jars, shockabsorbers, downhole motors, etc.), and it ends withthe bit (Fig. 11).

The drill pipes are hollow steel pipes of varioustypes, with two tool joints welded at their ends(Fig. 12). They are standardized according to APIstandards and classified on the basis of their length(usually about 9 m), their outside diameter, their linearweight and their steel grade. The most common drillpipes are the following: 3.50'' (13.30 lb/ft), 4.50''(16.60 lb/ft) and 5'' (19.50 lb/ft), in which the firstfigure indicates the outside diameter of the pipe bodyand the one in brackets the linear weight. The grade ofthe steel is expressed by a letter, indicating the type ofmaterial, followed by a number which indicates theminimum yield strength. The tool joint is the elementthat enables the pipes to be joined and it has a large-pitch conical thread and a triangular profile, allowinga fast and secure connection with just a few piperotations. The tool joints are not manufactured in thebody of the pipe, but separately, and are connected byfriction welding. They can be threaded a number oftimes; in this way, having to replace pipes in good



swivel

swivel stem

swivel sub

kelly cock

upper upset

kelly

lower upset

kelly saver sub

protector rubber

tool jointbox member

drill pipe

tool jointpin member

crossover sub

drill collar

bit sub

bit

Fig. 11. Main components of drill string.

condition because of damaged threads is avoided. Thetool joints have a slightly larger outside diameter thanthat of the body of the pipes, this being necessary toguarantee an adequate wall thickness incorrespondence to the thread. They have to ensurehydraulic seal between two connected tool joints: thishydraulic seal takes place at the precision-groundannular surface at the end of the thread. The seal is ametal-to-metal type, established by the make-uptorque. The threads of the tool joints are periodicallychecked and can be reground on site.

During drilling operations the weight of the drillstring is sustained by the hook, except for a small parttransferred to the bit. The weight necessary for the bitdepends on the type of rock, the characteristics of thebit, the velocity of rotation, etc., and is in the region of10-20 kN per inch of the hole’s diameter. Operating inthis way, when the bit is drilling, the top part of thestring is in tension, while the lower part is incompression; the length of the two sections dependson the weight applied on the bit. Drill pipes, beingrelatively slender and thin-walled, are affected bybuckling and cannot withstand compression, and sothey bend and break through axial compression. It istherefore necessary to assemble the lower part of thedrill string, that subject to compression, with strongerpipes, suitable to safely withstand compression. This isachieved by using pipes of larger wall thickness, called

drill collars, which are stiffer and have more linearweight compared to drill pipes. So as not to riskcompressing the drill pipes, it is good practice tooversize the length of the string of drill collars (alsoknown as the Bottom Hole Assembly, BHA) usuallyby 30-50% compared with the length necessary toprovide the weight on the bit. In this way the neutralsection is always inside the stretch of the drill collars,at about 2/3 of the length of the BHA. The drill collarshave a thick wall, are made out of solid steel bars,rounded externally, bored on the inside and withthreaded ends directly on the body, with threadinganalogous to that used for ordinary pipes. The drillcollars are 9 to 13 m in length and their outsidediameter is between 3.125'' and 14''. They are alsostandardized (API), with the most common diametersbeing 9.50'', 8'' and 6.50''. Drill collars made of non-magnetic steel also exist, and are used in directionaldrilling so as not to influence the sensors that measurethe earth’s magnetic field. They are manufactured withstainless steels (alloys of K-Monel type) or withchrome-manganese steel alloys.

Connecting pipes having very different diametersleads to concentrations of tensions and to fatigue inthe area where the cross-section varies. This coincideswith the location of the threading, which is already aweak area. Therefore, it is not possible to join drillpipes directly with drill collars, as this would create aweak area in correspondence to the joint. To avoid thedanger of breaks in the drill string, a short stretch ofintermediate heavy-wall or heavy-weight drill pipes isinserted. These pipes, connected by long, strong tool-joints, can even withstand compressive stresses.Using heavy-wall drill pipes allows drill pipes and drillcollars to be connected without any abrupt diameterchanges. The heavy-wall drill pipes are normally madewith the same outside diameter as the drill pipes, butwith a smaller inside diameter. In practice, they aredrill pipes with thick walls, having a linear weight twoor three times greater.



pin

box

Fig. 12. Section of a tool joint.

Fig. 13. Stabilizer (courtesy of Eni).

Accessory equipmentThe drill string is very often fitted with accessory

items which serve to resolve technical problems due tothe wide variety of drilling conditions. The mostcommon accessory items of equipment are stabilizers,reamers, jars and sock-absorbers, which do not formpart of the rig facilities, but are hired from specialservice companies.

Stabilizers are placed along the BHA, in betweenthe drill collars, to make the string more rigid in thepresence of the instability due to combinedcompressive, buckling and bending stresses, and theyare fundamental for controlling the borehole trajectory,both in vertical and in directional wells (Fig. 13). Theyconsist of a body to which rib blades are applied,expanding the outside diameter of the tool to thenominal diameter of the bit. The blades are of spiralshape to help the flow of the mud. By changing thecomposition of the BHA, and in particular thepositioning of the stabilizers, the mechanicalbehaviour of the drill string can be varied, which isuseful in controlling the directional drilling operations.

Reamers are special stabilizers featuring roller-cutters instead of blades (Fig. 14). On the rollers,usually from 3 to 6 in number, steel cutters or tungstencarbide inserts are mounted. They serve the purpose ofreaming wall of the hole, taking it to the nominaldiameter of the bit, and in the process eliminating thesmall variations in diameter and any possible steppedprofile there might be in the hole, which could makethe application of the weight on the bit uncertain (thestabilizers might settle on them) or cause problemswith running-in the casing. Reamers are used chieflyin drilling through streaks of hard and abrasive rocks.

The jar is a mechanical or hydraulic piece ofequipment, positioned on the neutral point of the BHA(i.e. the point where the stress acting on the drill stringchanges from tension to compression), making itpossible to give upward bumps in the case of the drillstring getting stuck (the equipment is known as abumper if it is able to give downward bumps). Itconsists of two sliding liners ending in a hammer andan anvil. The jar is activated by pulling the drill pipe.Under tension load, the hydraulic jar becomeselongated, as between the two liners there is a systemconsisting of two oil-filled communicating chambersseparated by a piston. Because of the shape of thecylinder and the piston, the fluid flows slowly throughthe first part. After which, a change of section of thepiston causes the remaining part of the stroke to occursuddenly, giving the hammer an acceleration so that itknocks against the anvil, discharging the elastic energyaccumulated. The mechanical jar functions accordingto the same principle, but the operation is regulated bya clutch system.

The shock absorber is a device placed above the bitto reduce the axial vibrations generated duringdrilling, which are harmful for both the bit and thedrill pipes. Therefore these devices are necessary whenthe vibrations are strong enough to be visible at thesurface. In deep wells, the vibrations might not bevisible at the surface because of the damping due tocontact of the string along the walls of the hole. In thiscase other signals are observed, such as slowpenetration rate and a particular bit wear pattern. Theshock-absorber works through a series of deformableelements of rubber or steel, which act like a reinforcedspring.

Downhole motorsIn traditional rotary drilling the bit is set in

rotation, together with the whole drill string, by therotary table or by the top drive. Bottomhole motors,of relatively recent use, allow the rotation to beapplied to the bit alone. They are hydraulic machinesat the end of the string, screwed directly onto the bit,and the entire mud flow goes through them, part of



Fig. 14. A, reamers; B, examples of roller-cutters.

A B

the mud pressure being converted into rotary motionand torque. In this way, the rotation necessary foroperating the bit is supplied by the downhole motor,while the whole drill string can remain stationary, ormay be rotated, if necessary, with the rotary table orthe top drive. The use of such motors is essential bothfor directional drilling and for the application ofmodern techniques for controlling the verticaltrajectory of wells. Downhole motors, an integralpart of the BHA, are axial-flow machines of tubularshape and are similar in size to a drill collar. Thereare two types of downhole motors: turbines andPDMs (Positive Displacement Motors). These motorsdo not form part of the standard equipment of the rig,but are hired from service companies, which alsosupply the personnel specialized in using them andwhich look after their maintenance. The use of thesemotors has to be justified from the economicstandpoint.

Turbines are rotating, open-type turbo-machinesfitted with rotors and stators arranged in series in amultistage pattern (Fig. 15). The mud stream flowsthrough the entire turbine and, alternating between

a rotor vane and a stator vane, is deviated, thuscausing the motor shaft to rotate. Naturally, thepower supplied by the turbine is produced at theexpense of a decrease in the mud pressure when itleaves the turbine, and is a function of the number ofstages of the machine, which is proportional to itslength. The turbine shaft is fitted with axial andradial bearings to support the loads in the drillingphase. Turbines develop high power and above all ahigh rate of rotation, which is often incompatiblewith the use of three-cone bits; for this reasonturbines are being developed with a mechanicalspeed reducer. They have a very long bottomhole life(in the order of hundreds of hours) and can also beused in very deep wells, having no particularlimitations with regard to operating temperature.

PDMs are rotating, closed-type volumetricmachines, characterized by a drive section differentwith respect to that of the turbines (Fig. 16). Theirinternal architecture is in fact the evolution of theArchimedean screw pump. PDMs are Moineaupumps made to operate in the opposite direction,whereby the motor shaft is caused to rotate byforcing the mud through it under pressure. The drivesection of a PDM consists of two elements, the rotorand the stator. The rotor is a spiral shaft made ofsteel, with one or two lobes. The stator is a rubbertubular sheath internally shaped like a spiral but withone lobe more than the rotor. Furthermore, it housesthe rotor, and is integrated into the outer housing ofthe motor. When the rotor is inserted in the stator, thegeometrical difference between the two componentscreates a series of cavities. The mud, which is forcedpast the stator and the rotor, fills these cavities, andcauses the rotor to rotate continuously. The specialgeometry of this machine enables it to be operatedwith all drilling fluids, including gaseous ones. Ingeneral, PDMs rotate appreciably slower thanturbines (in fact, they are also compatible with three-cone bits), they are shorter than turbines (which is anadvantage in numerous applications of directionaldrilling) and they are easier to maintain, even thoughthe rubber stator can have limitations due totemperature and to its incompatibility with some oil-based muds.

3.1.8 Bits

The bit is connected on to the end of the drill string. Thebit is the tool that bores the rock, transforming it intofragments called cuttings, which are then transported tothe surface by the drilling fluid. The choice of the typeof bit depends on the hardness, abrasiveness anddrillability of the rock formation. There are three basic



flow

rotation

fig. 15. Turbine.

flow

stator

rotor

rotation

Fig. 16. PDM motor.

rock-cutting mechanisms (Fig. 17): compression(suitable for rocks with an elastic behaviour); shear(suitable for rocks with a plastic behaviour); and shearand abrasion (suitable for abrasive rocks). The bit isdesigned to drill in various ways, according to thebehaviour of the rock, which may be of elastic or plastictype, or – far more frequently – a combination of both,and according to the drillability and the abrasiveness ofthe formations. It follows from this that there is anextremely vast range of bits, all different from eachother, which are able to respond effectively to the mostvaried drilling conditions.

The first bits used in rotary drilling (which asserteditself industrially in the early part of the Twentiethcentury) were similar to those used in cable-tooldrilling, but adapted to the different drilling mechanics.They were fixed blade bits, referred to as ‘fishtail’ bitsdue to the shape of the blades, which were veryeffective in drilling soft formations, but entailedproblems related to the rate of drilling and wear andtear in hard formations. In 1909 the first roller cone bit,which proved very effective in drilling through hardrocks, was produced and tested. At the beginning of the1930s, the three-roller (or tricone) bit was introduced,and in the course of the years has undergone countlessmodifications and improvements. In the early 1950s,bits with natural diamonds were also produced. In spiteof this, the tricone bits were the most commonly usedin rotary drilling from the early 1930s until the mid-1980s. Towards the end of the 1970s, studies andexperiments started on Polycrystalline DiamondCompact (PDC) type bits, and from the beginning ofthe 1990s these became a viable alternative to triconebits. However, competition with PDC bits stimulatedintense research and technological development of thetricone bit in the 1980s and 1990s. At the start of thismillennium the PDC bit became more popular than thetricone type, at least as far as the commercial value ofthe tools produced was concerned. In spite of this,tricone bits are high technology tools, and in drillingoperations they still have a sufficient number ofapplications to indicate that their obsolescence on themarket is still a long way off.

All bits are made in API standardized nominaldiameters, from 3.75'' up to 26''. It should beobserved that beyond 17.50'' tricone bits are almostthe only existing type. It is recalled that there are also

coring bits, used in coring operations, i.e. duringdrilling to obtain cylindrical samples, commonlycalled cores. Coring bits are characterized by theirability to drill only an annular cross-section of rock,leaving intact the core. Coring operations aredescribed in Chapter 3.3.

Tricone (three-cone) bitsThe tricone bit drills the rock by means of chipping

and crushing, combined with shearing and scraping,and is also well suited to drilling hard rocks (Fig. 18).The tricone bit consists of three legs and three cones(fitted with cutters) assembled on special journalsmachined on the legs, with a bearing in between thatallows the cone to rotate freely. The three legs, oncethe cones (or roller cutters) have been mounted, arewelded together to form the bit. The legs and the conesare manufactured by a series of precision mechanicaloperations (forging, milling and grinding), in order tomake the bearing and the cutting structure accordingto the geometrical shapes of a cone and a journal,respectively, which, during use, privilege scraping tocrushing. During drilling, the weight of the bit causesthe cutter to hit the rock, while the rotation forces thecones to rotate and the cutters to scrape along thebottom, producing the cuttings.

The cutting structure of a tricone bit may be eitherof the ‘milled tooth’ or tungsten-carbide insert type. Theshape, material and pattern of the cutters on the conesdepend on the drillability of the formation. In general,soft formations are drilled with long and slim cutterswith high spacing. Hard formations, on the contrary,requiring more weight on the bit, are drilled using shortand flat cutters with a low spacing. The extension of a



A B C

Fig. 18. Tricone bit with tungsten-carbide inserts(courtesy of Smith bits).

A B C

Fig. 17. Cutting mechanisms of rocks: A, by compression (suitable for rockwith elastic behaviour); B, by shearing (suitable for rock with plastic behaviour);C, by shearing and abrasion (suitable for abrasive rock).

cutter (long or short) is defined as the distance betweenthe tip of the cutting edge and the base of the cone,while its being slim or flat is a function of the angle atthe top of the cutting edge and the spacing (or pitch) isthe distance between one cutting edge and the next one,which expresses the total number of cutters that may belocated on each row of the roller cutter. Steel teeth areproduced by milling the cones and are subsequentlyhardfaced with a hard metal deposited by fusion, whilethe tungsten-carbide inserts are pressed into specialholes bored in the cones.

The bearing is the mechanical coupling systembetween the cone and the journal, and allows the freerotation of the roller cutter. Bearings are designed torotate under conditions of very high loads, and have tostand up to the wear and heat generated by frictionwithout suffering damage (Fig. 19). If, due to excessivewear, the mobile parts of the bearing (balls, rollers orother elements) get out of position, they can cause thebearing to become blocked or even the loss of the coneat the bottom of the hole. The most critical point of thebearing is the rotating seal, a mechanical deviceconstructed from either rubber or metal parts. Recenttechnology has made available numerous engineeringvariants both in the design and in choice of materials,all covered by international patents. Tricone bits arecompatible with the typical speed of rotation of therotary table, in the region of 100-150 rpm, andsometimes do not adjust well to applications withdownhole motors.

The drilling fluid issues from the bit throughnozzles located in the space between the cones. Thesenozzles are made of tungsten-carbide with a taperedshape and with a calibrated central hole which makesit possible to accelerate the outlet velocity of the mud

(up to about 50-100 m/s) and to achieve an adequatehead loss at the bottom of the hole, according to thewell hydraulic design. The mud issuing from thenozzles is useful also to cool the bit, to remove thecuttings from the cones and from the bottom of thehole, and to increase the rate of penetration (especiallyin not well consolidated formations) thanks to thesweeping action of the high-velocity jet at the bottomof the hole.

Tricone bits are classified according to standardsfixed by the International Association of DrillingContractors (IADCs). Their purpose is to compare bitshaving similar technical features but which areproduced by different manufacturers, each of whichadopts its own nomenclature. The IADC code fortricone bits consists of three numbers. The first oneexpresses the hardness of the rock that the bit is able todrill, adopting a scale of 1 to 8, with an increasingdifficulty of drilling. The second number distinguishesa further subdivision within the class identified by thefirst number (scale of 1 to 4) according to thedrillability of the rock. The third number indicates aspecial technological feature of the bit (e.g. roller orfriction bearing, reinforced diameter, air-circulationbits, etc.). A second IADC code assesses the bit wearat the end of a run. This is particularly important, as itprovides useful indications on choosing the next bitand, generally speaking, for optimizing the bitprogramme in future wells in the same area. The typeof wear of tricone bits, by now well known, bearswitness to specific drilling problems that can beavoided with a correct bit selection. The code used inassessing wear is quite complex, and consists of aseries of 8 numbers and standard letter-codes,describing the wear mode of the cutting structure andof the bearing, as well as the general state of the bit atthe end of the run.

Natural diamond drill bitsKnown since the 1950s, the natural diamond drill

bit was for a long time the only alternative to tricone



cone

thrustbearing

rollerbearing

seal

mainbearing

nozzle retainingsystem

API pinconnection

pressureequalizer

lubricantreservoir

lubricationhole

Fig. 19. Section of a tricone bit with friction bearing (Smith bits).

Fig. 20. Natural diamond bit (Hughes Christensen).

bits in hard, abrasive formations, in which the latterwear out all too quickly, making drilling extremelycostly. Furthermore, diamond drill bits were for a longtime the only bits that could be used with the firstdownhole turbines because, not possessing parts inmotion, they can be run even at a high number of rpm.Subsequently, the use of diamond drill bits wasextended also to rocks of medium hardness, especiallyif abrasive, where they proved to be competitive withtricone bits, in view of their longer bottomhole life. Inthis type of bit the cutters are natural diamondsvarying in size between 0.1 and 3 carats, appropriatelyembedded in the matrix of radial ribbing of amonobloc tungsten-carbide head (Fig. 20). Thediamond acts on the rock only by a shearing action,removing rock fragments of thickness proportional toits depth of penetration, depending on the weightapplied to the bit. The diamonds are set in the matrixfor 2/3 of their diameter, and during drilling theypenetrate the rock for no more than 10% of theirresidual diameter, while in the remaining space themud circulates for cooling and for removing thecuttings. In practice, this type of bit functions byabrading the rock, and the cuttings produced are veryfine, almost dustlike. It is recalled that naturaldiamond, although extremely hard, is very fragile anddoes not stand well up to impacts or vibrations.Moreover, at 1,455°C it becomes transformed intographite, and it is thus necessary to keep the cuttingface well cooled. In diamond drill bits, the mud doesnot issue from calibrated nozzles, but from a centraloutlet of fixed area, and is distributed radially alongthe ribs around the cutting surface, cooling it.Nowadays, natural diamond drill bits are of relativelylimited use.

PDC bitsPDC bits are characterized by a cutting mechanism

similar to that of natural diamond drill bits, but theypossess special cutting elements made of a particular

synthetic material called polycrystalline diamondcompact. PDC cutters have a greater cutting depththan the small dimensions of a diamond. They drillsolely by shearing and are therefore suitable for rockswhich are not abrasive and have a predominantlyplastic behaviour. The first PDC bits immediatelyshowed that they could compete with tricone bits, dueabove all to their intrinsic reliability, as they have nomoving parts (which could wear out, become detachedand remain at the bottom of the hole), and due to thepossibility of running them on all downhole motorapplications. The PDC bit (Fig. 21) has a monoblocsteel or tungsten-carbide head, on which cylindricalcutters are mounted, and a threaded body in order toallow it to be connected to the drill string. The head isrounded, according to a specific profile and isequipped with protruding radial ribs also known asblades. The cutters, which are arranged along theblades, consist of a cylindrical tungsten-carbidesupport on which a few mm thick layer ofpolycrystalline diamond compact is deposited, whichconstitutes the actual cutting part (Fig. 22). The PDClayer is produced by mixing metallic cobalt withsynthetic diamond powder crystals having an averagedimension of about 100 mm. The mixture is subjectedto a pressure of approximately 104 MPa and totemperatures close to 1,350°C. These conditions,together with the catalysing effect of the cobalt, bringabout a partial sintering of the diamond grains. Thefinal product is a layer of interconnected diamond



conenoseshoulder

face cutterinterchangeablenozzle

gauge pad

weldgroove

gauge cutter

back reamingcutter

gauge insert

breaker slot

shank

make up face

shank boreAPI pin connection

Fig. 21. PDC bit (Hughes Christensen).

diamond table

tungsten carbide substrate

Fig. 22. Typical cutter for PDC bits.

crystals, in which the intergranular spaces are filledwith cobalt. The characteristics of hardness and ofresistance to abrasion of the PDC are comparable tothose of natural diamond.

The cutters of PDC bits have a diameter ofbetween 5 and over 10 mm, and they are arranged onthe blades with precise cutting angles, whichcharacterize the aggressiveness of the bit and theefficiency of cleaning the well bottom. Holes are madein the bit head for the nozzles, their functions beinganalogous to those of tricone bits. Their number variesaccording to the diameter of the bit, from a minimumof 3 to more than 8.

PDC bits show excellent performances mainly insoft and not very abrasive formations. The fact thatthey can drill at very high rates of penetration (if theright bit for a certain type of formation has beenchosen, although this is not always foreseeable),together with the long life of the cutters, has madethem extremely competitive with tricone bits inunconsolidated clayey or sandy formations. The use ofPDC bits in hard and abrasive formations howeverremains a problem not completely resolved. In fact,the cutters are very sensitive to impacts, vibrations andoverheating. Generally speaking, the energy requiredfor cutting the rock increases as hardness andabrasiveness increases. In practice, however, only asmall part of this energy is used for actually cuttingthe rock, the majority of it being converted into heaton the interface between the cutter and the rock. Thiscauses overheating of the cutters, which triggers arapid thermal degradation of the polycrystallinediamond. Indeed, whereas the crystalline structure ofthe natural diamond is transformed into graphite attemperatures close on 1,450°C, that of PDC degradeslong before this, at about 750°C. Hence the key pointin PDC design is a correct study of the hydraulic flowon the cutting face, to cool in a precise manner everysingle blade and every single cutter.

PDC bits, also, are classified with an IADC code,formed by a letter followed by three numbers: theletter indicates the material of the bit head (steel ortungsten-carbide), while the numbers indicate,respectively, the density of the cutters (in 4 classes,from low to high density), their size (again 4 classes)and the type of profile (fishtail, flat, double-cone,etc.). The criteria for assessing the bit wear follow thesame IADC procedures as above for tricone bits.

TSP bitsAs has been seen above, PDC cutters are very

sensitive to temperature, and are not suitable fordrilling hard rocks. A possible alternative to usingPDC cutters is TSP (Thermally Stable Polycrystalline)diamond. The technique for producing this type of

material is similar to that used for PDC, with thedifference that it is not constructed on a base oftungsten carbide, and that at the end of themanufacturing process the catalyst (cobalt) is removed,obtaining TSP diamond compact. Cobalt, in fact, has agreater thermal expansion than that of the diamond,and when heated it tends to destroy the polycrystallinestructure. The TSP material is thermally more stablethan PDC (it remains unchanged up to about 1,200°C),and can be produced in larger sizes than naturaldiamonds, in the range of several mm. TSP cutters areproduced in round or triangular shapes and are used toproduce tools similar in concept to natural diamondbits (Fig. 23). They are set in the ribbing of a monoblochead of tungsten carbide, and have the advantage ofmaking a deeper penetration than natural diamondbits, but shallower than PDCs. They are suitable fordrilling relatively hard formations or streaks of softand hard rocks. In soft rock their cutting action is likethat of the PDCs, while in hard rock they act likenatural diamonds. Clearly, given the small size of theircutters, the penetration rate of the TSP bits is less thanPDC bits, but they can drill for a longer time. Theirhydraulics is analogous to that of natural diamond bits.

Impregnated bitsThis type of bit has been designed to drill

particularly hard and abrasive formations, when all theother types of bit wear out in a very short time,making drilling extremely costly. The cutting structureof impregnated bits consists of shaped segments of



Fig. 23. TSP bits (Hughes Christensen).

Fig. 24. Impregnated bits (Hughes Christensen).

tungsten-carbide matrix, in which powdered syntheticdiamonds with a grain size of less than 100 mm havebeen distributed. These segments, generally with arounded profile, are welded to the body of the bit byhigh-temperature processes. Impregnated bits thus donot possess cutters in the strict sense of the word, butdestroy the rock by abrasion, because when thesegments containing powdered diamonds wear down,they guarantee the exposition of a certain quantity ofnew diamond powder (Fig. 24). From the hydraulicstandpoint, this type of bit does not have nozzleseither, but a central mud outlet. The only disadvantageof impregnated bits is that, in view of the small cuttingdepth of diamond powder, it is not always possible toattain high penetration rates.

3.1.9 Casing

Drilling a well modifies the mechanical and hydraulicequilibrium of the rocks around the borehole.Periodically this equilibrium has to be restored, byinserting a well casing. Casing is a steel tube thatstarts from the surface and goes down to the bottom ofthe hole, and is rigidly connected to the rockyformation using cement slurry, which also guaranteeshydraulic insulation. The casing transforms the wellinto a stable, permanent structure able to contain thetools for producing fluids from undergroundreservoirs. It supports the walls of the hole andprevents the migration of fluids from layers at highpressure to ones at low pressure. Furthermore, thecasing enables circulation losses to be eliminated,protects the hole against damage caused by impactsand friction of the drill string, acts as an anchorage forthe safety equipment (BOPs, Blow Out Preventers, seebelow) and, in the case of a production well, also forthe Christmas tree. At the end of drilling operations, awell consists of a series of concentric pipes ofdecreasing diameter, each of which reaches a greaterdepth than the preceding one (Fig. 25). The casing is aseamless steel tube with male threading at both ends,joined by threaded sleeve joints. The dimensions of thetubes, types of thread and joints are standardized (APIstandards). Special direct-coupling casings, without asleeve joint, also exist. The functions and names of thevarious casings vary according to the depth. Startingfrom the uppermost and largest casing, first comes theconductor pipe, then the surface casing and theintermediate casing, and finally the production casing.

As stated, the first casing is called the conductorpipe, and is driven by percussion to a depth normallyof 30 to 50 m. It permits the circulation of the mudduring the first drilling phase, protecting the surfaceunconsolidated formations against erosion due to the

mud circulation, which could compromise the stabilityof the rig foundations. The conductor pipe is notinserted in a drilled hole and is not usually cemented,and therefore it is not considered a casing in the truesense of the word. The first casing column is next, andprotects the hole drilled inside the conductor pipe. It isalso called the surface casing and its functions are toprotect the fresh water aquifers against potentialpollution by the mud, to provide anchorage for thesubsequent casing, and to support the wellhead. Toincrease its stiffness and make it capable of bearingthe compressive loads resulting from the positioningof the subsequent casings, the surface casing iscemented up to the surface. Its length depends on thedepth of the aquifers and on the calculated well-headpressure following the entry of fluids from thebottomhole into the casing. In fact, as the surfacecasing is the first casing on which the BOPs aremounted, it has to be positioned at a depth where theformation fracturing pressure is sufficiently high toallow the BOPs to be closed without any risk (seeSection 3.1.13).



surfacecasing

conductorcasing

intermediatecasing

productioncasing

cement

reservoir

casingshoe

Fig. 25. Well casing.

The successive casings are known as technical orintermediate columns and vary in number according tothe specific requirements of the well. The casing depthof the intermediate columns depends on the porepressure profile of the underground fluids. As the holegoes deeper, when the hydrostatic pressure of the mudnecessary to drill safely equals the fracturing pressureof the weakest formation present in the open hole(which would cause its hydraulic fracturing), the wellhas to be cased. The weakest formation is usually theone nearest the surface, immediately under the lastpipe of cemented casing. In this way it is possible todrill every phase of the well with drill fluids ofdifferent densities. The intermediate casings arecemented along the entire length of open hole, up toabout a hundred metres in the preceding casing.

Finally, there is the production casing, which is thelast one placed in the hole; it reaches the top of the payformation, if the completion is open-hole, or it goesright through all of it, if the completion has a casedborehole. Inside this casing is the completionequipment which enables the underground fluids toreach the surface. This is the most important casingand must not collapse since it has to remain efficientfor the entire productive life of the well. The design ofthis casing must ensure its resistance to the maximumpressure exerted by the fluids to be produced, andguarantee its resistance to any corrosion that might beinduced by the chemical composition of the fluids.

This last casing may be partial: it might not reach thesurface at the full diameter, but might end and beanchored at the lower end of the preceding casing. In this case one no longer speaks of casing, but instead,of a liner, which is fixed to the preceding casing bymeans of a liner hanger which ensures the hydraulicand mechanical seal (Fig. 26). The liner and its hangerare lowered into the well with a drill string, and itslength is such that when the operation is completed thehanger is about 100 m inside the preceding casing. Thechoice of a liner rather than a casing depends oneconomic and technical considerations, e.g. thedecrease in the weight on the hook during the running-in of the liner into the well. This factor is importantespecially in deep wells, or when the rig has a limitedhook load capacity. Moreover, the liner also leads toimproved borehole hydraulics, as the decrease inlength of the small-diameter annulus reducescirculation head losses. If necessary, the liners may bebacked up to the surface with a casing run downhole ina special seating in the head of the hanger.

3.1.10 Cementing

Cementing is the operation of pumping a cementslurry between the casing and the formation, and canbe performed by injection into the annulus from insidethe casing. As mentioned, the cementing – in this casecalled primary cementing – serves to rigidly connectthe casing to the formation and to guarantee thehydraulic insulation of the various formations,preventing the migration of the fluids from layers athigh pore pressure to those at low pressure. Thesuccess of cementing depends on the effectivedisplacement of the slurry, which has to replace thegreatest possible quantity of mud present in theannulus. This depends on numerous factors, such asthe flow regime in the annulus, the density andviscosity of the mud and of the slurry, the casingcentralization, etc. The centralization of the casing isparticularly important, as the geometry of the well isseldom regular, but tortuous and with a variablediameter. All other cementing operations carried outafter the primary operation, either to correct an earliernot very effective cementing operation, or for otherpurposes (repair of a damaged casing, setting cementplugs, squeeze operations, and so on), is calledsecondary cementing (see Chapter 3.6). From theoperative standpoint, when the casing depth of acertain section of the hole has been reached, the trueborehole diameter is determined by means of a log,from which the volume of slurry necessary forcementing can be calculated. Meanwhile the casingpipes are prepared, providing them with centralizers



intermediate casing

production liner

Fig. 26. Casing and liner.

and scratchers; the centralizers serve to keep thecasing centred in the hole while the scratchers are forremoving the mud cake from the wall of the hole,improving the setting of the cement on the formation.The cementing shoe, a pipe with the same diameter asthe casing, with a rounded end and fitted with a checkvalve which prevents the fluid contained in the annulusfrom flowing back into the casing, is mounted as thefirst pipe of casing. At a distance of one or two pipesfrom the shoe, two collars are fitted to hold the cementplugs. The lowering of the casing into the well takesplace by connecting the pipes on the rig floor andrunning them in the hole with the help of the hook, inthe same way as the drill string is run in.

Cement slurryThe material used for cementing is slurry, a

mixture of cement, water and chemical additives. Acement slurry is obtained by mixing Portland cement,obtained from appropriate mixes of lime and claymaterial roasted in special rotary kilns, with variousproportions of water. The mix gives rise to a series ofchemical reactions which cause a gradual setting andhardening of the slurry. Setting occurs in a few hoursafter mixing, while hardening is a slower processwhich can even take some months. The composition ofdrilling cements is regulated by API and ISO(International Standards Organization) standards. Theyare divided into various classes (indicated by theletters from A to H) according to the depth at whichthey are used. High sulphate resistant cements aregenerally employed and, for obvious reasons oflogistics and cost economy, one or two types areadopted (in general, classes G and H). These, with theappropriate additives, can be used in all drillingsituations. In particular, the additives serve to controlthe density, setting time, circulation losses, filtration,and viscosity. In the same way as the muds, slurry isalso subject to control of its physical and rheologicalcharacteristics, such as density, free water, consistency,setting time, etc. These controls are carried out underthe temperature and pressure conditions existing in thewell. The cement is selected to ensure that the slurrywill develop adequate mechanical properties in asufficiently short time, and so to reduce the idle timeof the rig at the end of cementing (i.e. the waiting timefor the cement to set). In contrast, it is necessary forthe slurry to remain fluid long enough to complete thepumping, which takes several hours in particularlydeep wells. It is therefore important to estimateprecisely the volume of cement slurry needed, thebottomhole temperature, and the total time requiredfor cementing. In fact, even a modest variation in thetemperature causes an appreciable reduction in thesetting time (this especially being the case with wells

having high temperatures, above 100°C), and thusnecessitates a very precise formulation and laboratorycontrol of the cement slurry. The use of retardants oraccelerators enables this to be achieved, as they allowthe slurry setting time to be regulated appropriately. Inthis way it is possible to use even a single type ofcement for the most varied drilling situations. In asimilar way to drilling fluids, the slurry must have adensity that will prevent underground fluids fromentering the well, and will not lead to fracturing of theformations.

Single-stage cementingSingle-stage cementing is carried out by pumping

the calculated volume of slurry into the casing,through a special three-way cementing head mountedon the casing, thus enabling the cementing plugs to bereleased into the casing (Fig. 27). For the displacementof the slurry, special pumps are used with greater headand smaller flow capacity than mud circulation pumps.At the start of the operation, the well is filled withmud; to improve the displacement within the annulus,where there might be cuttings and scraps of mud cake,



cementinghead

displacementfluid

displacementfluid

drillingfluid

cementslurry

cement

top plug

bottom plug

float collar

centralizer

guide shoe

Fig. 27. Cementing equipment.

a separator pillow consisting either of water plusadditives or diesel oil is first pumped into the casingfrom the lower line of the cementing head, to fluidifythe mud and separate it from the slurry pumped inafterwards. The slurry is then pumped through themiddle line of the cementing head, care being taken toseparate the water pillow from the slurry by means ofthe first cementing plug (a rubber plug with a diameterequal to the inside diameter of the casing, which ishollow and is closed by a central diaphragm that easilysplits). After the calculated volume of slurry has beenpumped, a second plug, made of solid rubber, isinserted into the casing, and pumping of ordinary mudabove the second plug continues through the upperline of the cementing head, preceded possibly by asecond water pillow. When the first plug reaches thecollar, the pumping pressure increases, indicating thatthe plug has landed on the collar and that there isslurry behind it. By increasing the pumping pressurethe diaphragm of the first plug is split open,permitting the displacement of the slurry into theannulus. Finally, when also the second plug lands onthe first one, the pressure again increases, showingthat all of the slurry has been pumped into the annulusand that the inside of the casing is filled exclusivelywith mud. This means that the primary cementing hasbeen completed, and the wait for the cement to setstarts. This takes a few tens of hours, during which thewellhead operations are completed, and after whichdrilling is resumed. Clearly, the plugs, the collar, andthe shoe have to be made of easily drillable materials,in order to continue drilling with an ordinary bit.Single-stage cementing presents some uncertainty inthe calculation of the height up to which the slurry hasbeen taken, as there may be caving formations in thewell not taken into account in calculating the volumeof slurry. With an analogous technique the liners canalso be cemented.

Double-stage cementingThe choice of single-stage cementing is linked to

the length of casing to be cemented, to the formationfracturing pressure and to the time for which the slurrycan be pumped. This method is not applicable in verydeep wells, where the pumping times are reduced bythe accelerating action of the temperature, or in wellswith long formation intervals having a low fracturegradient. In these cases multiple cementing (usuallydouble-stage) has to be applied, which involvesinjecting the slurry into the annulus through specialcementing valves located at suitable distances in thecolumn. In double-stage cementing, the deepest part ofthe casing is cemented with the single-stage technique,after which cementing is completed in the upper partby pumping in another calculated volume of slurry

through a special circulating valve (known as a‘diverter valve’) with holes that can be opened andclosed by two internal sliding sleeves. These holes,closed during the first cementing stage, are openedusing a special plug released inside the casing, whichis eventually blocked on a special landing sleeve, thusmaking a hydraulic seal. By pressurizing the inside ofthe casing, some shear pins are severed and thelanding sleeve slides, opening the circulating valve.After circulating the mud, to displace any slurry thatmight have risen above the valve, the slurry is pumpedin the same way as in single-stage cementing. The lastcementing plug also closes the holes in the circulatingvalve, concluding the operation.

At the end of the cement setting time, beforeresuming drilling, the effectiveness and quality of thecementing should be checked. It is recalled that theminimum setting time is defined as the time necessaryfor the slurry, in downhole conditions, to reach aviscosity of 10 Pa�s. A first test, conducted afterhaving drilled the plugs and the shoe, consists ofpressurizing the casing to a value equal to thehydrostatic pressure foreseen for drilling thesuccessive phase, thereby checking the seal. A secondtest assesses the rise of the cement in the annulus, byrecording a well temperature profile. If there is cementbehind the casing, the heat generated by the stronglyexothermic setting reaction, causes a temperature rise,which does not occur if mud is present. Another morereliable and more precise test for estimating thequality of the mechanical coupling between casing andhole is a sonic log performed inside the casing. Theattenuation of the sound wave is greater, the better thecementing, that is the more rigid the mechanicalcoupling between casing, cement and rock.

3.1.11 Drilling fluids

The drilling fluid, also called ‘mud’, is a water, oil orgas-based fluid. It is one of the key factors in thesuccess of a well and has a strong impact on the totalcost of the operations, above all due to regulationsgoverning its disposal once the well is completed. Thechoice of drilling fluid is dictated mainly by thecharacteristics of the formations to be drilled, by theirdrillability and reactivity to water, and by problems ofdisposing of the spent fluid. During drilling, the mudis subjected at least daily to chemical, physical andrheological analyses, and if necessary it is corrected,as contact with the cuttings can modify itscharacteristics which must always be kept withindesign limits. Drilling fluids, which circulate in thewell as shown in the schematic representation in Fig. 28, have many functions to perform, including:



The removal and transport to the surface of thecuttings produced by the bit. The transporting capacityis influenced by the characteristics of the fluid (inparticular viscosity and density) and by the geometryof the cuttings. Usually a minimum uplift velocity ofabout 0.8-1 m/s is sufficient, and has to be checked inthe section of the greatest flow area (the annulusbetween the last casing and drill pipes). The rapiditywith which the cuttings are removed from the bottomof the hole influences the rate of penetration and thelife of the bit.

The control of the formation pressure. This has thefunction of preventing underground fluids fromentering the well. This is achieved by always keepingthe hydrostatic pressure of the mud column higherthan the pore pressure, by regulating the mud density.Usually, the latter is kept 5-10% above the densitynecessary to offset the pressures foreseen, creating adifferential pressure between the hole and theformation; the hydrostatic pressure must in any casenever exceed the fracturing pressure of the formationsalready drilled.

The prevention of caving and collapse of theborehole walls. The hydrostatic pressure of the mud

acts as a sort of temporary support, as it partlybalances the stresses that existed in the surroundingrocks prior to drilling. Furthermore, in areas ofpermeable rock, the mud creates a ‘mud cake’, a sortof layer of hardened clay on the walls of the hole,which further stabilizes the well. The mud cake formsby separation of the colloidal part of the mud from theliquid (filtrate) part, which instead penetrates theformation due to the differential pressure. A good mudcake has to be tough, thin and impermeable, and mustnot reduce the hole diameter, thereby increasing therisk of the drill string getting stuck.

The slowing down of the sedimentation of thecuttings when circulation stops. A good drilling fluid,passing from a state of motion to one of rest, shouldrapidly gel, to slow down or stop the cuttings insuspension from falling back. If this does not takeplace, the drill string could become stuck due to thesedimentation of the cuttings at the bottom of the hole.The property of some fluids to form a jelly-like masswhen at rest and to return to the liquid state when inmotion, is called ‘gel strength’, and is typical ofnumerous bentonite-based muds. Unfortunately arapid gelation hinders the effective separation ofcuttings at the surface on the shale shakers.

The cooling and lubrication of the drillingequipment. Especially those of the bit and the drillstring, which can come into contact with the boreholeat many points.

The limitation of reservoir damage. During theformation of the mud cake, the filtrate penetrates theformation radially, forming an ‘invaded (or flushed)zone’, in which the relative permeability to oil or gasdiminishes; if clays are present, there can also be adecrease in the permeability of the formation. Toprevent overly extensive invasions, the properties ofthe mud can be regulated so that a thin, impermeablecake will form rapidly.

The sources of geological and stratigraphicinformation. Sampling and analysis of the cuttingsseparated by the shale shaker, monitoring the gasesdissolved in the mud, and control of its physico-chemical variations (temperature, pH, chloridecontent, etc.), form a basic part of the in situgeological survey, which supplies precious indicationson the course of drilling.

Classification of drilling fluidsDrilling fluids are subdivided into three major

classes, according to the type of continuous phase thatconstitutes them. The first class is that of water-basedmuds: the continuous phase is water (fresh or salt), towhich natural clays of the bentonite group are added,so as to form a homogeneous, viscous suspension.Water-based muds were the very first drilling fluids



surface equipmentremoves cuttings

wellbore

drill string

drilling mud

drill collars

bit

Fig. 28. Drilling fluid circuit.

used, and were called ‘muds’ because of their aspect,being composed only of water and clay. Afterwardsthis term was extended to all liquid-based drillingfluids. The physical and rheological characteristics ofmuds are adjusted by adding chemical additives andweighting materials. The filtrate of a water-based mudis water with a part of the chemical additives insolution, and is potentially capable of damaginghydrocarbon-bearing formations. The second class isthat of oil-based muds: the continuous phase is oil, bythis term meaning hydrocarbon based natural orsynthetic products. Also in this case chemicaladditives, weighting materials and viscosity enhancersare necessary to regulate the physical and rheologicalcharacteristics. The filtrate of an oil-based mud is oil,which does not damage the formations. Lastly, thethird class is that of gas-based drilling fluids, usuallyair, possibly mixed with other fluids. These arecharacterized by low density and are unable to createan adequate hydrostatic pressure to control layer andformation pressures; they are used for drilling throughformations having a low pore pressure gradient.

Apart from the base fluid, drilling fluids consist ofviscosity enhancers, weighting materials, chemicaladditives and possibly plugging materials.

The most common viscosity enhancers used inpreparing muds are particular clayey minerals or elsenatural or synthetic polymers; they are necessary toimprove the cutting transport capacity. The clayeyminerals most used are those in the bentonite group.Bentonite, dispersed in fresh water, becomes stronglyhydrated and produces muds with good viscosity andgel strength characteristics, which form an elastic,impermeable cake. Other viscosity enhancers areorganic (natural or synthetic) polymers andorganophilic oil-wettable clays.

Weighting materials are fine mineral powders (10-40 mm) dispersed in the mud to increase thedensity. They must have a high density and bechemically inert, easy to mill, not very abrasive, non-polluting and economic. The most widespread materialis barite (natural barium sulphate, density about 4,250kg/m3), which allows the mud to reach a density ofabout 2,200 kg/m3. Analogous properties are typicalalso of siderite, galena and haematite. Weighting canalso be obtained with soluble salts, such as sodium,calcium or potassium chloride, or even potassium,calcium or zinc bromide, which are used in particularfor the preparation of fluids for well completion. Theyare clear fluids, without any solids in suspension,which limit the damage to the formation.

There are numerous chemical additives. The best-known are thinning agents (fluidizers), used to controlthe viscosity and the gelling of the mud. The viscosityof a mud can in fact be reduced by means of dilution,

the mechanical removal of solids, or by the addition offluidizers (tannins, lignosulphonates, chromolignite,etc.) which modify the chemical and physicalinteractions between solids and fluids, in particularbetween clay and water. Other types of additives arethose used to reduce the volume of filtrate(carboxymethylcellulose, starches, etc.); others aresurfactants, which are used as emulsifiers, defoamingagents, which reduce the foam that forms in brackishmuds, lubricants (gas-oil, synthetic oils, asphaltcompounds) and bactericides, which limit thedevelopment of bacteria, algae and moulds. Theanticorrosives category is important, to protect thedrill string and tools. Polymers are a special class ofadditives. They are substances with a macromolecularstructure of natural origin (guar gum, xantan gum,tannins, starches, etc.) or of synthetic origin(polyacrylates, polyacrilamides, etc.), which canbehave as viscosity enhancers, flocculants,deflocculants, filtrate reducers, stabilizers, etc. Theiruse is particularly common in the preparation ofmodern drilling fluids. Another important class ofadditives is formed by materials used to stabilize thereactive clays of the formations: these are polymers,asphaltic hydrocarbons, or calcium and potassiumsalts, which are employed to make what are termed‘inhibiting’ muds, which limit clay hydration andswelling.

Lastly, there are the plugging materials, used tolimit circulation losses which can occur in fracturedformations or, more rarely, in very permeable layers.These are solid materials which are mixed with themud in massive quantities. They may be fibrous(processing waste of cotton, hemp, jute, animalbristles, sawdust), in scale or flake form (cellophanestrips, mica chips, wood shavings), or granular(crushed walnut shells).

Characteristics and use of drilling fluidsWater-based muds are the simplest drilling fluids,

in which water is the continuous phase and solids thedispersed phase. The solid phase consists mostly ofclays, possibly with the addition of polymers forcontrolling filtration and the rheological properties, ofweighting materials to control the density, and ofcaustic soda for pH control. With the use of additives,various types of water-based muds, suitable for arange of drilling conditions, can be produced.Generally, the more complex formulations try to makethe properties of water-based muds more like those ofoil-based muds. The advantages of water-based mudsare their low cost, the good cleaning of the hole, andthe low environmental impact. On the other hand,their disadvantages are linked to the interaction ofwater with the clays of the layers (which can give rise



to instability of the walls of the hole), their lowresistance to high temperatures, and the difficulty ofkeeping the percentage of solids within acceptablelimits. For this, frequent dilutions are necessary,which cause the volume of the mud in circulation toincrease considerably. Many formations lose theirmechanical stability when they come in contact with awater-based mud, and vice versa many mudsdeteriorate in the presence of clayey cuttings. For thisreason inhibiting muds were introduced; theyencapsulate the cuttings and limit the expansion ofreactive clays. The most common inhibiting materialsare potassium or calcium chloride, diethylene ortriethylene glycol, certain calcium or potassiumsilicates, formiates or acetates, or certainencapsulating polymers.

Oil-based muds consist of a base fluid that may bejust diesel oil or a mixture of water and diesel oil. Thelatter are water-in-oil emulsions, in which the oil isthe continuous phase and water the dispersed one, andthey are sometimes called inverted oil emulsion muds.The liquid phase is constituted by water and oil(diesel-oil, white oils with a low aromatic content,etc.), to which are added emulsifiers (sodium andcalcium soaps), viscosity enhancers (oil-wettableclays), filtrate reducers, and weighting materials. Themost common oil/water ratios are 80/20, 85/15 and90/10, but ratios of up to 50/50 and even beyond canbe reached. In oil-based muds the continuous phase isnot polar and does not cause any swelling in the clays.Moreover, the oil renders the system little sensitive tocontaminants (salt, anhydrite, cement, carbon dioxide,hydrogen sulphide, etc.) and the filtrate, which is onlyoil, does not damage the productive formations. Theadvantages of oil-based muds are the greater stabilityof the hole (because of the lack of interaction withclays), the formation of a thin cake, and its greaterlubricating and anticorrosive action on steel. Incontrast, its disadvantages are the high initial cost ofthe base fluid, the greater environmental impact ofpossible spills or circulation losses in surfaceformations, and the cost of disposing of the spentfluid and the cuttings. Lastly, it is recalled that thereare also muds that use non-polluting synthetic fluidsas the continuous phase, but these are still extremelycostly.

Gas-based drilling fluids consist of compressed airor inert gases, possibly mixed with foam agents, andare used when it is wished to reduce bottomholepressure, to avoid circulation losses in surface layers,or to limit damage to productive formations. Gas-based drilling fluids, due to their low density, areunable to create the hydrostatic pressure necessary tocounterbalance the pore pressure and to support theborehole walls. In order to be able to use them, it is

necessary to install costly and complex compressionunits on the rig site. The advantage of gas-based fluidsis however the increase in the rate of penetration, dueto the ease of removing the cuttings created by the bit,thanks to the negative pressure differential(underbalance drilling). However, air-based drillinghas the disadvantage of the difficult handling of thecuttings at the surface (which is, in practice,pulverized rock dispersed in air), wich induce a greatdeal of abrasion on the drill string: in fact, the annularvelocity necessary to lift up the cuttings can be asmuch as 900 m/min. To overcome this problem, asmall quantity of mud with a foam agent can beinjected into the compressed air flow; this creates acompact, stable foam which has better a transportcapacity. The annular velocity necessary for the foamis about 90 m/min. The application of foam isconvenient down to moderate depths, between 1,000and 2,000 m. In fact, as the system cannot be recycled,the extent of its use is determined by the increasedvolume of foam to be disposed of. If the entry offormation fluids prevents the use of air or foam,aerated mud can be used, but this is not strictlyspeaking a gas-based fluid, being a common mudmixed with compressed air to reduce its density. It hasadvantages both in the rate of penetration and inreducing circulation losses. Aerated mud can be usedin a continuous cycle, like an ordinary mud, and iswidely used in underbalanced drilling, i.e. a drillingtechnique based on the use of a fluid that maintains, atthe bottom of the hole, a lower pressure than that ofthe formation fluids, thus provoking the reservoir intoa regime of slow fluid production. This techniquemakes it possible both to have greater rates ofpenetration and to avoid damage to the productionformations, which is the most important aspect.

The current trend in developing innovative systemsin the field of drilling fluids is mainly aimed atmeeting the requisites of the regulations to safeguardthe environment, of safety and of reducing damage toproduction formations. In fact, while traditionalsystems (especially oil-based muds, which are oftenextremely toxic) perform excellently in manyoperative conditions, the restrictions linked withenvironmental impact and safety make it necessary todevelop base fluids and additives having little impactand which can equal the performances of traditionalsystems at acceptable cost. Moreover, research today isalso very active in the field of non-damaging fluids,formulated for drilling inside the reservoir, andcharacterized by a limited interaction between fluidand formation. In the sector of oil-based muds, theinnovations tend instead to focus on using less toxicbase fluids than traditional oils such as olefins,synthetic oils, esters, etc.



3.1.12 The wellhead

The wellhead and the safety equipment are the valveunits that allow the well to be insulated from theoutside environment. In this way it is possible tocontrol effectively and safely the pressures thatdevelop in the well when it is in hydrauliccommunication with the subsurface formations. Infact, the pressure of the fluids contained in theseformations is very often greater than normalhydrostatic pressure. The wellhead is a fixed unit thatconnects the various casings set inside the well. If it isa producing well, this unit remains there until the endof drilling, and is completed with the production heador Christmas tree. The safety equipment consists ofdevices mounted directly on the wellhead and are usedonly during drilling.

Traditionally, wellheads are classified in twogeneral categories: surface wellhead and subseawellhead. The feature of the surface wellhead is that itis accessible. In onshore wells it is located at thebottom of the cellar, and is integrated into the surfacecasing. In offshore drilling it is used in all rigsstanding on the seabed (e.g. fixed or jack-up

platforms). The subsea wellhead, on the other hand, islocated on the seabed and is used in wells drilledoffshore in deep waters (by semisubmersible platformsor drilling ships), and is designed to be without directaccess by man either in the assembly stage or duringoperation (see Chapter 3.4). The elements comprisinga surface wellhead are the base flange, intermediatebodies, the anchorage slips, the seal units, and theupper body (Fig. 29). The base flange is the lowestelement of the wellhead. It stands on the ground of thecellar and is welded or screwed onto the surfacecasing. The intermediate bodies are cylindricalelements with flanged ends, used to cover the head ofthe preceding casing and to bear the weight of thesubsequent casing. The intermediate body contains thesealing unit, a truncated cone-shaped part in which theslips for hanging the casing string are housed, and theseat for the seal gaskets. The mechanical coupling oftwo overlapping intermediate bodies takes place withbolted flanges or with clamps, ensuring a hydraulicseal with a round metal gasket. The base flange andthe intermediate bodies have lateral outlets fitted witha double valve for control of pressure in the annulus



casinghead

intermediatespool

tubinghanger

casingslips

rubber sealpacking

rubber sealpacking

Fig. 29. Surface wellhead.

Christmastree

tubinghead

casinghead

Fig. 30. Wellhead complete with Christmas tree.

spaces and if necessary for pumping fluid into thewell. The hanging slips are the elements that enablethe end of the casing string to be anchored to thewellhead. The internal profile of the slips iscylindrical, while the external profile takes the form ofa truncated cone, and wedges into the correspondingtruncated-conical part of the intermediate body. On theinternal cylindrical surface of the slips there are teeththat hold the external part of the casing, firmlyhanging it to the wellhead. The sealing units, usually aprimary and a secondary unit, are formed by steelrings with rubber gaskets: when the rings arecompressed, the rubber dilates and guarantees ahydraulic seal. The setting of the casing into theintermediate body takes place after the casing has beensubjected to suitably calculated tension, which isrendered permanent by the hanging. The purpose ofthis pre-tensioning is to prevent the buckling of thestring during the productive life of the well, whichcould be caused by increased temperature in theproduction phase. In fact, in view of the depthsreached today in developing hydrocarbon fields, theunderground fluids can be very hot even in areashaving a normal geothermal gradient. As the casing isrestrained in two points, at the bottom of the hole (atthe cementing end) and at the wellhead, the thermalexpansion resulting from bringing fluids with a hightemperature into production tends to subject the casingto combined compressive and bending stress and couldcause a breakage due to buckling. In the case of aproductive well, it is necessary to install equipment inits interior (known as ‘well completion’) to producesubsurface fluids, and to connect the Christmas tree(Fig. 30) to the wellhead. After running-in theproduction casing, the last upper body is connectedwith a flange; this enables the production tubing to behanged and the annulus between tubing andproduction casing to be isolated. Finally the Christmastree – a system of valves allowing the flow of fluidsproduced at the wellhead to be regulated – is mountedon the wellhead.

3.1.13 Safety equipment

The safety equipment, otherwise known as Blow OutPreventers (BOPs), are large valves located on thewellhead during drilling operations (Fig. 31), able tofully shut-in the well in just a few tens of seconds,whatever the working conditions. BOPs on onshorerigs and fixed offshore rigs (platforms, jack-ups) areinstalled on the surface wellhead, while for floatingrigs they are located on the seabed, on the subseawellhead; this means that the floating rig can alwaysbe removed from the wellhead, under safe conditions,

e.g. following marine and weather emergencies, due todamage to the mooring lines, etc. The overlapping ofvarious BOPs constitutes the BOP stack, which is theassembly of equipment for shutting-in the well in anemergency situation, and then reopening it under safeconditions. The shut-in of the well is necessary whenhydraulic control is lost, i.e. when the pressure of theunderground fluids is greater than that of thebottomhole mud. In this case, the underground fluidscan enter the hole without control. It could benecessary to shut-in the well in any drilling situation,even when the drill string, a casing, a cable, etc., ispresent. For this reason it is necessary to have a valveavailable that can shut the well at any time. A standardBOP stack consists, starting from below, of: a) one ormore spools for connection to the wellhead; b) a dual-function ram preventer; c) a single-function rampreventer; d) an annular blowout preventer; e) a lateraltube, which conveys the outgoing mud from the wellto the shaker. There are also a number of lateralconnections (kill line and choke line), necessary foroperations to restore hydraulic balance after wellcontrol problems. The BOP stack has the followingfunctions: to shut-in the well around any type ofequipment; to permit pumping of the mud, with thewell closed by means of the kill line; to dischargethrough the choke line any fluids that might haveaccidentally entered the well; and to allow the verticalmovement of the string, upwards or downwards, whenthe well is closed (i.e. stripping of drill pipes).

The composition of the BOP stack, or the choice ofthe single elements, depends on the maximumestimated pressure at the wellhead, as established bythe geological investigations conducted during the



remote control panel

annularpreventer

rampreventers

Fig. 31. Safety equipments (BOPs).

well-design phase. The single BOPs are characterizedby the maximum working pressure, the insidediameter, the type of section on which they form aseal, and the presence of acid gases. There are twomain types, annular and ram, described below.

The annular BOP, also known as a ‘bag-type’blowout preventer due to the geometrical shape of thesealing element, is always installed at the top of thestack (Fig. 32), and has a toroidal rubber sealingelement, reinforced with steel inserts. The sealingelement is activated by a piston controlledhydraulically, which compresses it, forcing it toexpand radially, in such a way as to squeeze aroundany tool that happens to be in its way. If there isnothing in the well space, the annular BOP permits thefull closure of the hole, although this is notrecommended as it puts an anomalous stress on therubber of the sealing element. It may also be activatedat low shut-in pressure, to carry out strippingoperations, necessary for certain particular

well-control procedures. In the well shut-in procedurethe annular BOP is normally first activated, as itsclosure mechanism allows the mud flow to begradually stopped, avoiding a ‘water hammer’.

Ram blowout preventers (Fig. 33) consist of valveswith two symmetrically opposed rams, which close thewell with a horizontal movement. They may be offixed or variable diameter; in the latter case the sealingelement is contained in a segmented ring which forcesit to conform around the section on which it makes theseals. There are also shearing rams, designed to shut-inthe well in emergency situations, shearing through anytubular materials that might be contained in the well.Lastly, there are also ‘blind’ rams, i.e. not shaped,which shut in the well when no tubular material ispresent. The special features of ram blowoutpreventers are: their rapidity of shutting-in, performedhydraulically in just a few seconds; the possibility ofoperating them manually in emergency situations; andthe presence of a device that keeps the rams closedunder pressure, even in the case of loss of pressure inthe operating circuit. The body of a ram blowoutpreventer can house one or else two overlapping rams(double BOP), permitting various shut-in functions.

BOPs are controlled and operated hydraulically,through an oleodynamic system that receives energyfrom a pressure accumulator unit located at a distancefrom the wellhead. Each BOP can be operatedseparately. The BOP drive and control system isarranged so as to function independently of the energyavailable in the rig, to guarantee that it will operateeven in emergency situations. The accumulator systemconsists of a series of vessels under pressure in whichhydraulic oil and inert gas (nitrogen) are stored atworking pressures of around 20 MPa. There are alsoreservoirs for storage of reserve fluid and fluidreturning from the BOPs, a pump unit for pressurizingthe hydraulic oil, and the distribution lines for the



sealingelement

drill pipe

lower housing

closing chamber

piston

opening chamber

Fig. 32. Annular BOP: A, the sealing element seals the annulus between the kelly, the drill pipes or the drill collars; B, with no pipe in the hole, the sealing element closes on the open hole.

Fig. 33. Ram preventer.

A B

pressurized oil. BOPs can be operated via two controlpanels, a main one on the rig floor and a panel at adistance, located near the accumulator. A third panelmight sometimes be installed, in the office area. TheBOPs, as all safety equipment, have to be tested atregular intervals to make sure they are workingproperly.

Mention should lastly be made of the diverter,another safety device used when it is not possible toinstall the BOP unit. This occurs only in the surfacedrilling phase, when the surface casing has not yetbeen cemented. The diverter guarantees a system ofcontrol of the gas from shallow formations, normallycharacterized by low pressure and high discharge rate.The diverter does not stop the gas flow but safetydirects it away from the rig floor, until it becomesexhausted naturally, which usually takes place quitequickly in view of the small volume of theseformations. The use of a traditional BOP, whichcompletely closes the well, is not recommended duringthe drilling of the surface phase, as the back pressuretransmitted to the bottom, in case of well shut-in,could lead to the fracturing of the surface formations,which have a low fracture gradient and could cause anuncontrolled flow of gas behind the well. This isparticularly dangerous in offshore drilling, when theuncontrolled flow of gas in the water column below afloating rig could lead to a loss of buoyancy, withdangerous consequences for the vessel’s stability.

3.1.14 Well control

During drilling it is necessary to carefully monitor theexecution of any operation, above all to avoidblowouts. Blowouts are uncontrolled discharges ofunderground fluids (oil, water, gas) from the wellhead,after such fluids have entered the hole through one ofthe drilled formations. Blowouts are fairly uncommonoccurrences, but when they do happen they are bothspectacular, and harmful to personnel, the surroundingenvironment, the drill rig and have negative effects onpublic opinion, and so they have to be carefullyprevented. For this purpose, all drilling personnel arespecifically trained to spot the beginning of possibleproblems, and to decide what measures to adopt ineach specific case. The key to well control isunderstanding the mechanisms that regulate thedownhole pressures. The hydrostatic pressure of themud along the depth of the hole depends directly on itsdensity: light muds exerting less pressure along thewalls and at the bottom of the hole than a heavy mud.The well is under hydraulic control when the mudpressure is greater than the pore pressure exerted bythe fluids contained in the porous and permeable

formations drilled (in this case the differential pressureis positive, and the well is in a condition ofoverbalance). In this way, the mud keeps theunderground fluids confined within the formations,exercising what is called primary or hydraulic control.The pore pressure depends on the density of theformation fluids, and on the depth and geology of thesubsoil. There is said to be a drilling kick, or that thewell is discharging, when formation fluids startentering the well due to a decrease in hydrostaticpressure (i.e. when the differential pressure is negative,and the well is in a condition of underbalance). One ofthe basic tasks of the drilling personnel is to ascertainthat during any operation the well is always full of amud whose density is such as to exert a hydrostatichead at the bottom that will avoid a kick. Sometimes,however, in spite of all the measures taken, the wellmight start kicking for natural or operational reasons.The causes that can initiate a kick are: a) insufficientdensity of the mud; b) drilling a formation inoverpressure not promptly recognized; c) swabbing,namely the underpressure due to the piston effectduring a rapid trip-out operation; d) not filling the wellwhen tripping out; and e) circulation losses, which canlead to a sudden lowering of the mud level in the welland therefore of the hydrostatic pressure on bottom.The formations that can cause circulation losses arefractured, karst formations or those with less pressurethan foreseen. It is recalled that a rapid trip-in cancause an increase in the bottomhole pressure (surging),with the possibility of fracturing the formation, whichcauses circulation losses, lowering of the head of mud,and therefore the triggering of a kick.

A kick can be recognized in various ways. Themost reliable method is monitoring the behaviour ofthe mud coming out of the well. The commonest kickindicators are an increase in the mud flow rate, anincrease in level of the mud pit, an increase in the rateof penetration, mud outflow from the well when thepumps are switched off, the anomalous presence ofgas in the mud outflow, etc. Whatever the reason, in allof these cases the drilling personnel must rapidly takethe appropriate actions to halt the kick, stopping itfrom developing into a full-scale blowout. All drillingrigs are provided with systems of detection and crosscontrol, which help in recognizing the build-up of akick. These systems, often automated in such a way asto set off an alarm, are always under the surveillanceof the driller on the rig floor and are often replicated inthe geological control cabin and in the offices of therig supervisor and of the drilling assistant.

When a kick occurs, the drilling personnel executethe safety procedures so as to bring the well undercontrol, known as secondary control. The firstoperation is to shut-in the well through the BOPs,



preventing any further formation fluids from enteringthe well. Once the well has been closed, there is atransitory stage in which the formation fluid goes onentering the well. During this stage, at the surface agradual increase is observed in the pressures inside thedrill pipes and the annulus, until the transitory stagehas ended and the pressures have become stabilized,indicating the hydraulic rebalancing of the well. Thevalue of the stabilized pressure in the drill pipes and inthe annulus is used to calculate the density of the mudwhich, when pumped into the well, will succeed incontrolling the new formation pressure. Furthermore,based on considerations of the hydraulic balance,using the stabilized pressures it is also possible toestimate the density of the fluid that had entered thewell, and thus its nature. In this situation, i.e. with thewell closed, it is not possible to continue drilling, asthe wellhead is under pressure. Procedures then haveto be initiated with the following two objectives:bringing to the surface, in safe working conditions, thefluids under pressure that have entered the hole, bymeans of controlled mud circulation; restoring theconditions of hydrostatic balance in the well, replacingthe original mud with new mud of such density as tobring the well back under hydraulic control. The twobest-known and used standard methods are theDriller’s method and the Wait and Weight method,which differ chiefly in the ways in which theobjectives described above are achieved.

3.1.15 Drilling problems

The generic expression drilling problems refers to aseries of anomalous operative situations that have tobe adequately resolved in order to be able to carry ondrilling in safe conditions. In particular, problemsrelating to circulation losses and to drill strings gettingstuck will be examined, and in conclusion a briefmention will be made of ‘fishing’ and milling ofdrilling material that has been lost, by falling into or insome way remaining at the bottom of the hole.

Circulation losses indicate anomalous absorptionor complete losses of mud circulation. They may bepartial, if mud does in any case return to the surface,or total, when the circulating mud no longer returns.Circulation losses can occur in rocks of considerablepermeability, in formations of abnormally lowpressure, in fractured or karst formations, or informations fractured by excessive mud density. Thereare many negative effects of circulation losses. Themost dangerous one is certainly linked with thelowering of the mud level in the well, which cantrigger a kick. Moreover, if the circulation does notreturn to the surface, it is not possible to analyze the

cuttings, with loss of stratigraphic information, whileappreciable circulation losses in shallow formationscan contaminate the aquifers. Lastly, it is recalled thatcirculation losses also strongly influence the wellcosts, as the average price for a water-based mud is inthe range of 1,000 euro/m3, and can increase to thedouble or the triple of this for synthetic oil-basedmuds. To stop circulation losses, mud mixed withplugging material is injected into the hole, and usuallysucceeds in closing small fractures measuring in theorder of a millimetre. The use of this technique ishowever not always possible, because of restrictionspresent in the string (downhole motors, MWD, bitnozzles); in this case it is necessary to trip-out the drillstring and to pump in plugging material through astring without a bit, or with a bit without nozzles. Ifsuch a measure should be insufficient, a cement plughas to be set corresponding to the thief formation.

‘Drill strings getting stuck’ refers to any type ofpipe string which, for various reasons, is stuck in thewell, and which cannot be rotated, pushed down orpulled up. In other terms, the string is stuck when themaximum pull exerted by the drawworks is no longerable to pull out the string, due to friction or tojamming of the tubular material in the hole. One of thecommonest jamming mechanisms is the one called‘key seating’: the rotation of the drill pipes undertension, which rub against the wall where there arevariations in hole curvature, can create a recess havinga diameter less than that of the hole, in which the drillcollars can get stuck during trip-out operations.Another such mechanism is when the string gets stuckbecause of differential pressure. This can occur whendrill collars remain stationary for a long time at adepth corresponding to permeable formations. In sucha case, under conditions of strong overbalance, a mudcake can accumulate between the pipe and theborehole wall that is so thick that it can block thestring. The string can also get stuck when running in anew bit into a section of hole drilled using a worn(undergauge) bit. It is recalled that the reduction inhole diameter can also be caused by the swelling ofplastic formations (clay, salt, etc.). Finally, otherpossible reasons for jamming are the collapse of thehole in unstable formations, the sedimentation of thecuttings or large cavings; the latter are particularlypernicious because they block the drill string andinterrupt circulation.

In case of stuck pipe, the first operation is applyinga strong pull by means of the drawworks and operatingthe jar, if present. Moreover, if circulation is notinterrupted, a lubricating fluid can be pumped in, orelse an acid solution, in order to remove the mud cake.Such measures, which can even take several hours, areoften successful when the pipe is not completely stuck.



If it is not possible to free the string in this way, to beable to resume drilling it is first necessary todisconnect the pipes at the tool joint closest to thestuck point. This point is determined by the method ofdifferential pulling, or with a specific log recordedinside the pipes. There are three methods ofdisconnecting the string: by unscrewing anti-clockwise; by unscrewing anti-clockwise and firing asmall explosive charge inside the last free joint (back-off); by severing the pipe using mechanical orchemical systems. Once the free string has beendisconnected, an attempt is made to recover the partremaining in the hole (called the ‘fish’) using ‘fishing’techniques, which are not always effective. If the fishremains in the well it is milled, or, if it is too long, asidetrack is made, that is, a new hole is drilledalongside the preceding one, using techniques typicalof directional drilling. During drilling, fishing iscarried out quite rarely. In fact, whereas it is easy toestimate the times of execution (and hence the costs)of a sidetrack, it is much harder to estimate the timerequired for fishing, which might or might not besuccessful.

The term fishing indicates in general all thetechniques used to recover metal items lost or stuck inthe hole. It is carried out with a series of toolsmanipulated by a pipe string possessing mechanicalparts formed in such a way as to grasp the variouspossible shapes of the fish in the well. Typical casesare fishing up the drill string when it has broken off or

has become accidentally unscrewed during drilling.Fishing tubular items is carried out with die collars ortaper taps, or with more refined tools, called theovershot and the releasing spear (Fig. 34). The overshotis a sort of die collar that grasps the outside of avertical tubular fish, permitting circulation. It consistsof an upper part for connection to the string and acentral sleeve shaped inside to contain the grapple,which is shaped like a steel spiral or dilatable basket.The fish, on entering the overshot, widens the grapplewhich then grasps it by means of a wedge-shapedmechanism, and holds it firmly when the tool ispulled. The releasing spear has the opposite sort ofmechanism, gripping the internal diameter of a tubularfish. Its use is limited to material having a largeinternal diameter. If instead the fish is a long stringstuck due to a large caving, it is possible to clean theannulus with special washover pipes, which are verymuch like long, strong core barrels. The operation iscarried out in two stages, cleaning about a hundredmetres of pipes at a time, and subsequently lowering afishing string fitted with an overshot. Recovery ofmetal fragments (normally difficult to mill), whichhave been lost or which have fallen into the well, iscarried out using magnetic fishing tools or specialcore barrels known as junk baskets. There are fishingtools equipped with permanent magnets, lowered bycable or by means of pipes (which therefore allowcirculation for cleaning of the fish head), or withelectromagnetic fishing tool, lowered together with anelectric cable, and activated only at the bottom of thehole. The latter have a greater force of attraction thanpermanent magnets, but they cannot be rotatedbecause of the electric cable, and they do not allowcirculation. The junk basket, with direct or reversecirculation, serves to fish junks of all types. However,it can be used only in easily drillable formations. It hasan upper part for connection to the string, a centralbody and terminal cutting shoe, whose purpose is tocut and collect a rock sample. The core barrel shoecuts the formation, forming a core 60-80 cm in length.After this, on pulling the string, a wedge mechanism(called a ‘core catcher’) grasps the core and detaches itfrom the bottom, so that both the core and the fishtrapped above it can be recovered.

If the fishing operations are not successful, inorder to free the hole milling can be carried out, that isdestroying the fish, by reducing it to chips usingspecial mills with cutting faces. The key point forsuccessful milling is a study of the hydraulic transportcharacteristics of the chips using mud. In fact, themilled steel chips are of thin, smooth laminar shape,more or less curled, and very heavy. Hence, they tendto drop and form heaps at the points where the sectionof the annulus broadens, thus forming inextricable



grapple

fish

overshot

released set

fish

releasingspear

fish

Fig. 34. Fishing equipment: A, overshot;B, releasing spear.

A B

tangles. Mills are tools very similar to diamond bits,possessing a head shaped in various forms, dependingon the fish to be milled. The cutting face of a millcontains large sintered tungsten-carbide grainsconnected by a metal matrix and acting as real cutters.Naturally, there are holes in the cutting face of themill, allowing the mud to circulate.

Bibliography

Bourgoyne A.T. Jr. et al. (1986) Applied drilling engineering,Richardson (TX), Society of Petroleum Engineers.

Bradley H.B. (1992) Petroleum engineering handbook,Richardson (TX), Society of Petroleum Engineers.

Chambre syndicale de la recherche et de la productiondu pétrole et du gaz naturel, Comité des Tech-niciens, Commission exploitation, Sous-commissionforage (1981) Blowout prevention and well control, Paris,Technip.

Chilingarian G.V., Vorabutr P. (1981) Drilling and drillingfluids, Amsterdam, Elsevier.

Chugh C.P. (1992) High technology in drilling and exploration,Rotterdam, Balkema.

Economides M.J. et al. (edited by) (1998) Petroleum wellconstruction, Chichester-New York, John Wiley.

Hartley J.S. (1994) Drilling. Tools and programmemanagement, Rotterdam, Balkema.

Lummus J.L., Azar J.J. (1986) Drilling fluid optimization. A practical field approach, Tulsa (OK), PennWell.

Lynch P.F. (1981) A primer in drilling and productionequipment, Houston (TX), Gulf, 3v.; v.II: Rig equipment.

Nelson E.B. (1990) Well cementing, Amsterdam, Elsevier.Nguyen J.P. (1996) Drilling, Paris, Technip.Rabia H. (1985) Oilwell drilling engineering, London, Graham

& Trotman.Short J.A. (1981) Fishing and casing repairs, Tulsa (OK),

PennWell.

Paolo MaciniDipartimento di Ingegneria Chimica,

Mineraria e delle Tecnologie AmbientaliUniversità degli Studi di Bologna

Bologna, Italy



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