completion engineering - best chapter

3.7.1 Introduction

Well completion is an upstream petroleum activitywhose aim is to furnish the well, once it has beendrilled and cased, with all of the equipment neededto bring the hydrocarbons to the surface, bothin the case of natural flow (Fig. 1) and artificial lift(Fig. 2). A completed well is therefore equippedwith the basic components needed for production:production tubing, safety and interception systems(packer, downhole valve, christmas trees) and

accessories (nipples, circulating valves, artificiallift systems).

Completion engineering has the following aims: a) to meet the requested targets of production/injectionrates; b) to choose the simplest layout from thepossibilities available for a given level of functionalityand results; c) to meet the needs of safety and respectfor the environment; d) to provide enough flexibilityfor any changes during the working life of the well; e)to meet all of the above needs at the lowest capital andoperating costs.

3.7

Completion engineering

425VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT

christmas tree composedof manual and automaticgate valves

Surface ControlledSubsurface Safety Valve (SCSSV)

packer fluid

tubing

casing

cement

packer

accessories seating nipples

perforated casing

Fig. 1. Single completed well in natural flowing.

christmas tree composed ofmanual and automatic valves andpenetrators for electrical cables

Surface Controlled SubsurfaceSafety Valves (SCSSV)

packer with penetrators

tubing

electrical cable

cementelectric submersiblepumpelectrical motor

perforated casing

Fig. 2. Well completed with artificial lift with Electric Submersible Pump (ESP).

All of the above is not always possible, particularlyas far as low cost is concerned. Therefore, even in the presence of high capital costs, it is importantto consider the benefits deriving from more complexand costly layouts in terms of greater production(early or increased production) and in terms of theireffectiveness over time (less workover, simplermanagement). The role of a completion is therefore tolink the reservoir to the surface in order to producehydrocarbons. Other equally important aims are toprotect the production casing from pressure effects andfrom the composition of the produced fluids(corrosion), to monitor the reservoir production data,to prevent the formation of deposits that could obstructthe pipes, to prevent the deposit of salts and thecorrosion of the production tubing, and to optimizeexploitation of the reservoir.

Depending on whether the field is onshore oroffshore, the development strategy controls to avarying extent the drilling and well completionoperations, with respect to equipment to be used,techniques to be selected and the environmentalimpact.

Onshore development systems

Development with individual wellsOnshore development by means of individual wells

is the simplest from the point of view of thecompletion with respect to the interface with thesurface facilities since these wells are generally drilledand completed individually, then connected byindividual flow lines to the manifold headers andsubsequently to the gathering points. This wellconfiguration makes it possible to place the well sitein the location defined by the reservoir study and thendrill the well ‘vertical’ to the top of the reservoir(unless there is a need for multidrain or horizontalwells, or there are logistics problems such as thepresence of residential areas, parks, etc.).

The advantage of vertical wells is their lowerdrilling costs and lower completion costs in terms ofmaterials (reduced length and volume of wells) andassociated services (directional drilling is not usedand since the levels are crossed vertically,perforations are less expensive). This system islogistically less efficient from the point of view ofmonitoring and control since a control network isneeded to connect the wells to a central system aswell as to local safety systems. Furthermore, thistype of system is subject to a greater number ofexternal risks and is therefore a very vulnerablesystem. It is however the simplest system to managein the case of simultaneous operations, since eachwell can host dedicated rigs.

Development with clustersThe development of an onshore field by using

clusters of wells leads to some complicationsregarding both well location and drilling. The cluster(see Chapter 5.1) is usually constituted by a singlecellar (a cellar is a ditch dug at the site toaccommodate the wellhead in order to limit theenvironmental impact, leaving only the productionchristmas tree above ground level) in which the wellsevenly spaced. The drilling and management of acluster must take different needs into account: thecellar must be deep enough for the highest wellhead, ina production/injection configuration, so that a drillingand/or workover rig can be skidded over it withoutdismantling either the rig and/or the christmas trees. Itmust also be wide enough to allow safe access duringdrilling, production and workover. The spacing, i.e. thedistance between the vertical axes of the wells, mustbe large enough to allow for drilling and completion insequence, with the possibility of operatingsimultaneously on adjacent wells with different typesof rigs. For example, it must be possible, to use adrilling rig at the same time as a workover rig orrigless equipment. Developments using clusters can becompared, with fewer space limitations, to offshoreplatform developments, with respect to the proximityof the flow lines, to the management of the safetysystem and to the well trajectory, which must bedeviated to reach targets that are some kilometresaway from the vertical of the cluster. The possibility ofconcentrating control and protection systems is adistinct advantage since it reduces the environmentalimpact.

Offshore development systems

Surface wellhead systemsThe types of offshore development systems differ

depending on water depth (see Chapter 5.2). In orderof increasing water depth, the main developmentschemes are: a) barges or artificial islands (less than10 m of water); b) monopods (one-leg platforms) ortripods (three-legs) for shallow water (35-40 m at themost); c) multi-leg jacket or gravity structures wherethe number of legs generally varies according to thedepth of the water (maximum of 150 m) and thepayload they have support; d ) platforms withconcrete structures (up to a depth of 350 m); e)Tension Leg Platforms (TLP), i.e. floating platformsthat are anchored to the sea floor with metal tendons(350-400 m); f ) floating systems (semisubmersibleor ships) connected to various subsea productionnetworks.

In the case of surface wellheads, the problem isreduced to the consideration of all surface interfaces,

426 ENCYCLOPAEDIA OF HYDROCARBONS

DRILLING AND COMPLETION OF WELLS

together with problems due to the limitations of spaceand safety related to the execution of simultaneousoperations in restricted space. The aspects to considerare: a) the selection of rigs and their use; b) the wellstructural interface with surface facilities (spacing ofthe wellheads and wells at each platform leveldepending on the well system size); c) the installationof the conductor pipes (environmental protection tubesconnecting subsea wellhead with the platformwellhead) and their centralisation within the platformstructure (jacket); d ) the tieback system design, i.e. theconnection of the production casings of wells duringthe pre-drilling phase, from the sea floor (see Section3.7.2), and the drilling wellhead; e) the well movementin relation to the fixed structures (design of wellheadinstalling system; f ) determination of wellheadvertical movements with respect to the conductor pipedue to temperature variations during production andthe relevant movements of flow lines with respect tothe platform structure); g) the integration of controland safety systems.

Subsea wellhead systemsIn this case, in addition to normal well problems,

there are other needs related to the design andinstallation of the subsea production system,including: a) the selection of the rigs (either moored ordynamic position rigs); b) the completion running; c)the level perforating phase (opening communication ofproduction levels with the wellbore); d ) the productionphase for clean-up; e) the wellhead installation phase;f ) the flow line installation phase; g) control umbilicalinstallation phase for subsea wellhead control duringproduction; h) the transfer of the control system to aremote station; i) the well workover phases during itsproductive life performed by means of a rig similar tothat used for initial installation or by means ofdedicated rigs.

Completion designStudies for completion design are divided into:

pre-feasibility, feasibility and detailed studies.Normally, pre-feasibility and feasibility studies areaimed at supplying management with accurateeconomic data to approve the start of the developmentproject. The detailed study is aimed at preparingspecifications for the purchase of materials and theservices needed for the development plan.

Data needed for the development projectThis is a summary of the data needed to prepare

the document defining the basic prerequisites andgoals of field development in which the wells are anintegral part (statement of requirement). These datainclude: a) the PVT (Pressure, Volume, Temperature)

characteristics of the fluids to be produced, i.e. thedensity, viscosity (variable according to pressure andtemperature) and related phase diagrams; b) reservoirdata regarding the number of productive levels; c) theproduction sequence planned; d ) the volumes ofhydrocarbons in-place for each level; e) the type ofdrive mechanism (water drive, solution-gas or gas-capdrive); f ) the forecast of the well flow rates and thecontribution of each level in the case of commingledproduction; g) the forecast of the evolution of the flowrate and of the fractions of the fluid produced; h) thepressure behaviour forecast (SBHP, Static BottomHolePressure) with respect to the original reservoirpressure; and i) the minimum flowing pressure (i.e.abandonment pressure) for each well. In addition, inorder to more accurately define the drilling profile, thefollowing must be determined: a) the positioning ofthe wells on the reservoir top; b) the geological datadefining the petrophysical characteristics as well astheir spatial distribution; c) the mechanical strength ofthe rocks penetrated; d ) the reservoir structure map; e)the contacts between the fluids; f ) the depth ofproduction levels and relative pressure gradients; g)drilling data from exploration/appraisal drilling, thatallow the determination of the pressure andtemperature gradients; h) any discontinuities; i)overpressures and potential problems.

3.7.2 Completion layout

The completion design follows the flow diagram ofFig. 3, which first identifies the logic sequence for theborehole-formation interface, then that related to theinterface between the production tubing and casingand, finally, the number of levels to be put intoproduction, the production sequence and/or thepossibility of commingled production from two ormore levels.

Borehole-formation interfaceThe borehole-formation interface differs according

to whether the wells are vertical, deviated (up to anangle of 60°-70°), sub-horizontal or horizontal (anglegreater than 70°). Traditionally wells have a telescopiccasing profile and involve the use of a greater numberof casing sizes the deeper the well while maintaining afixed production casing size. Horizontal wellsgenerally have a borehole that navigates inside thereservoir itself.

Vertical wellsThe interface options for vertical wells can be

divided into three main categories: open hole, openhole with non-cemented liners, and cased hole.


COMPLETION ENGINEERING

In the case of an open hole, the production casingshoe is set to the top of the production reservoir whichis later drilled and left as an open hole. Generally, thisoption is chosen in the presence of a singlehydrocarbon bearing reservoir when it is constitutedby secondary porosity rock. The principal limitation ofthis type of completion is that it is impossible toselectively produce more than one level or to excludethe presence of undesired fluids (water or gas).

In the case of an open hole with non-cementedliner, there are three possibilities:• Non-cemented slotted liner: this choice is

implemented in consolidated formations(carbonate, sandstone) that produce through anetwork of fractures or formations characterized bythin layers which are difficult to identify by meansof the logs. Productive intervals are drilled afterhaving set and cemented the productioncasing/liner to the reservoir top. Completion caninclude a slotted liner (tubing with longitudinalslots) when there is a risk of borehole collapse dueto mechanical instability of the rock as aconsequence of the reduction of the pore pressure.

• Sand control with screens in open holes (open holescreens): this option is used in the presence of anon-consolidated formation to mitigate thetransport of sand and any interstitial clays by thefluids produced. If such material were to

accumulate in the wellbore, they would reduceproduction until ultimately stopping it completely.Sand control can be managed by reducing the flowrates (thus tolerating the production of minimalamounts of sand), or by filtering it withmechanical tools (dual screens) around which thesand sets during production.

• Sand control with open hole gravel pack: thissystem is used when sand movement inside theformation must be avoided. Sand control takesplace by pumping sand with a controlled grain sizeinto the well, which acts as a natural filter for theformation sand. This action is coupled to that ofsimple mechanical filters (gravel pack). In order toensure an adequate volume of sand betweenformation and screens, the borehole is generallyunderreamed below the end of the last casing.Cased holes are the most common because they

allow better well management. In this case, for thepurposes of level selection and ease of control andsafety it is necessary to: a) determine the number ofintervals to open to production, using guns andexplosive charges to perforate the productioncasing/cement by following the relevant underbalanceor overbalance procedures; b) choose completionfluids suitable for minimising formation damage andtherefore to evaluate the need for stimulation; c) define the cementing quality through interpretation



open holegravel pack

completionlayout

borehole-formationinterface

tubing-casinginterface

polished borereceptaclepackerpackerless

liner hangersshallow setanchored

casingdeep setfree moving

tubingless

cased holegravel pack

open holescreens

formationfracturing

conventionalslotted liner

horizontalwells

cased holeopen hole

with uncementedliner

open hole

vertical/deviated

wells

number of levels

Fig. 3. Completion layout.

of the logs of specific wells (cementation log); d) ensure true isolation of the levels. Cased holecompletions can be subdivided as follows: • Conventional: this completion scheme is used

when the formations are stable. The casingperforation is carried out using suitable explosivecharges, which are high-penetration in the event ofheavy formation damage induced by drilling fluids,and possibly, with the use of underbalancetechniques to remove the effects of damage.

• With formation fracturing: in this case, given thevery low permeability of the formation,productivity is improved by creation of inducedfractures. To do so a high pressure acid solution isinjected into the formation and a small part of thelevel is perforated in order to concentrate the effectof the pressure. High penetration explosive chargesare necessary and excellent cementing is requiredso as to limit the fracture.

• Sand control by means of cased hole gravel pack:this scheme is used for sand production control incased holes. Explosive charges are used that canperforate holes of a certain size (ID, InternalDiameter�0.7'') in the casing in order to facilitatethe passage of controlled grain size sand pumpedinto the formation. The technique of sand pumpingis very effective in the presence of fractures (frac-pack).

Horizontal wellsCompletion schemes in horizontal wells are similar

to those of vertical wells but, in this case, there arefactors that complicate their management. Normally,horizontal wells have very long sections inside theproduction level (since the well trajectory isintentionally navigated inside the hydrocarbon bearingzone) and are difficult to manage during the injectionand production phases in terms of pressure losses. It isalso extremely difficult to carry out good cementbonding even in consolidated formations. Theborehole’s mechanical stability is therefore moresensitive to geostatic loads in the case of an importantdrop in the static pressure of the reservoir during theproduction life. The most common completion schemesare therefore comparable to those used in open holevertical wells. Still, the length of the horizontalsegment and the effect of gravity complicateinstallation procedures of the equipment (there is, forexample, a great deal of friction in the lower part of theborehole, and difficulty in transferring any rotation tothe bottom) and the pumping of the sized sand for sandcontrol. To this end, specific sand control techniqueshave been developed for horizontal wells as well as insitu expandable mechanical screens to avoid the needfor fluid pumping with the transport of solids.

Multilevel productionWith vertical wells that cross reservoirs consisting

of more than one production level with differentpetrophysical characteristics or containing differenttypes of fluids, the number of levels to be completedmust be decided. In horizontal wells, there are similarconfigurations when step-well trajectories are used inmultilayer reservoirs. Multilayer horizontal reservoircompletion configuration is rare and is carried out bysubdividing a horizontal well into step sections,managed more or less individually with valvescontrolled from the surface, both during production (to guarantee optimum drainage of the reservoir) andinjection (to ensure stimulation and/or injectivity inthe case of water injection wells).

The types of multilevel completion are listedbelow.

Completion for commingled production. In thiscase, a number of productive levels are put intoproduction at the same time, thus mixing the output.The completions are very simple and used when all ofthe levels have the same pressure regime, similarproduction indexes and contain similar hydrocarbons.Otherwise, the most permeable levels would tend toproduce more efficiently than the others which mayresult in cross flow from one level to an adjacent one(when the well is closed and the pressure at the bottomtends to be balanced).

Completion for sequential production. Sequentiallevel production is implemented either by interventionon the well by opening the sliding sleeves, or throughrecompletion, i.e. first opening to production on onelevel (generally the deepest), pulling out theproduction string and then recompleting the well in anupper level.

Single completions with segregated production. Inthis case, a single production tubing is used but levelsare kept separate by packers. When it is envisaged thatthe lower levels will be invaded by water before theothers and their exclusion is incorporated in thedesign, plans can be made for initial simultaneousproduction and later segregated production by meansof sliding sleeves or plugs set in the tubing (Fig. 4 A),or a sequential production from bottom to top; oralternating production producing each level separatelyin sequence (Fig. 4 B). Sometimes, more productivelevels are opened for production first in order to createconditions compatible with the other levels (i.e. todeplete them), after which simultaneous productioncan be implemented.

Multiple completions with segregated production.As in the above case, the levels are separated bypackers, however, two or more production tubings areused for simultaneous but segregated production of anumber of levels. Parallel tubing (Fig. 4 C) or



concentric tubing (Fig. 4 D) may be used. Thesecompletion schemes are generally chosen when it isnot desirable or possible mix the flows of the singleproduction strings.

The schemes shown in Fig. 4 A and 4 B allow bothsimultaneous (commingled) production and segregatedproduction for each individual level but not at thesame time. They also make it possible to segregatelevels that might produce water or gas in undesiredvolumes. These types of completions can also be used‘creatively’, for example by installing flow regulatorsor exploiting gas levels to lift oil levels. The schemesshown in Fig. 4 C and 4 D are used primarily inoffshore reservoirs where single string productionwould not be economical since it would require a largenumber of wells.

Tubing-casing interfaceExcept in completions with tubing alone

(packerless), which occur less frequently due totheir lack of safety, the tubing-casing interface ischaracterized by the packer system. This systemsupplies a mechanical tubing anchorage to thewalls of the casing and a hydraulic seal to separatethe fluids above and below the packer from eachother. In essence, the packer consists of slips andcounter-slips (with high surface hardness)anchored mechanically to the wall of theproduction casing by biting into it. In themovement between the two slips, during the packersetting, the elastomeric seal is compressed andexpanded against the casing, isolating the areabelow the packer – which contains thehydrocarbons – from the area above the packerwhich contains the packer fluid (Fig. 5). Dependingon the working conditions, various types of packersare used:• Permanent packers (retainers), used in hostile

environments, i.e. in the presence of high pressure,

high temperature and corrosive environments forlong-term completions and in recompletionsplanned above the packer depth where they can beused as plugs to separate the lower zones.

• Retrievable packers, generally used in relativelyless hostile environments. They are used in short-term completions, in multilayer completionsto separate the various levels and in plannedrecompletions after workover requiring completeaccess to the production casing below.

• Permanent-retrievable packers, a hybrid of theprevious layouts which, as technology has evolved,tend to substitute permanent packers inparticularly complex applications. This happens inparticular when using special alloy steels (whichwould require long milling times if permanentpackers are used).



single completion dual completionFig. 4. Completions withsegregated production: A, initial commingledproduction; B, sequential or alternating production; C, parallel tubing; D, concentric tubing.

DA B C

annuluswith packer fluid

connectiontubing/packer

packingelements

volumeunderneathpacker

mechanicalanchoring

slips

Fig. 5. Packer system.

Tubing-wellhead interface

Onshore or platform wellsThe drilling wellhead supports and transfers to

the ground, through surface casing, the loads on thewells. On the other hand, the tubing spool supportsthe tubing by means of the tubing hanger and at thesurface separates the flow in the tubing from theannulus (the space between the tubing and thecasing) of the production casing. The wellhead canbe of the composite type (Fig. 6) with flanges (a lessexpensive but bulkier solution), generally used foronshore installations, or of the compact type,typical used for platforms or clusters. Theconstruction and types of steels used are regulatedby API (American Petroleum Institute) 6Astandards (API, 2004). The tubing spool supportsthe christmas tree whose goal is to avoid theleakage of fluids into the environment and tocontrol their flow. The christmas tree can, in turn,be composite, made of individual flanged valves, orintegral (Fig. 7), with one or a series of monoblocks.The conventional wellhead (see again Fig. 6) can beshaped as a cross or horizontal. It must ensure safeclosure of the live well in all the phases of its

production life and safe access to the live well forworkovers through tubing even during production,for example in the case of installation ofbottomhole devices for the measurement of data.

Subsea wellsIn subsea wells, the wellhead and christmas tree

are located on the sea floor. During installation, thewellhead is connected to the rig through a subsea BOP(Blow Out Preventer) stack – BOPs are joined in astack group to facilitate installation operations – and aconnecting pipe (riser) to the rig by means of thetensioning and heave compensation (motioncompensator) system. Depending on the water depth,the BOP can be run on guide lines (Fig. 8) connectedto the equipment from the guide base. Otherwise,when used without guide lines, they are installed usingacoustic transponders and video localizers (ROV,Remote Operated Vehicle) during the running. Thedrilling wellhead, which is run all at once at the startof drilling, is a monoblock with a constant internaldiameter. The casing hangers are located on top ofeach other or one inside the other. There is a specialhousing for the tubing hanger. For further details, seeChapter 3.7.



top adapter forwire line lubricator

swab valve

wing valve

christmas tree cross

tie down

primary packing

slip

working valve

carrier with metalto metal seal

tubing hanger

tubing spool

casing spool

braden head

secondary packingprimary packing

BSB slip

dril

ling

sec

tion

com

plet

ion

sect

ion

master valve

secondary packing

Fig. 6. Composite wellhead.

Offshore tie-back systems with platform wellheads.Pre-drilling phase

The exploratory wells drilled with jack-up rigs,where the BOPs are onboard the rig and connected tothe well by means of a marine riser, have casings thatterminate on a special drilling wellhead placed on thesea floor. After the drilling and testing phase, the wellis suspended and completely shutoff on the sea floor.Should the well be recovered, the necessary casings (atleast the production casing and the conductor pipe toprotect against sea and weather) must be reconnectedto the surface, and the structure (jacket) wellhead,

complete with christmas tree, is placed on theproduction structure (monopod or platform). Thisprocess is known as tie-back. In reservoirdevelopment with platforms, this system is generallyadopted when the wells are predrilled, and performedwith semisub or jack-up rigs, before the jacket andplatform are available, even though the platform willbe equipped with a drilling rig. This process is lesscostly since it makes it possible to drill thedevelopment wells in parallel to the construction of theproduction structures (jackets and top-sided). Thisallows production to start in advance in comparison toa sequential development which first requires platformconstruction and then drilling and completion of thewells. During predrilling the rig is positioned on thevertical of the axis of the slots in the templateanchored to the sea floor, which is a protectionstructure of a series of wellheads, similar to anonshore cluster. The wells are drilled in sequence andthe same casings are installed in all of the wells(phases) so as to reduce logistic problems andoptimize drilling times. Drilling of each well issuspended when the last casing is cemented to thereservoir top. To do so, the BOP stack is moved fromone well slot to another on the template. The wells arethus temporarily abandoned on the sea floor. Once the jacket and topsides are installed, each well is tied-back to the surface by the conductor pipe(for environmental protection of the well), and by thecasing (to support the wellhead installed on theplatform). The drilling phase of the productioninterval, the completion and the production start-upare carried out using the drilling rig constructed forthe platform.



swab gate valve

wing gate valve

wing gate valve

control line port

master gate valvewith actuator

master gate valve

top adapter

Fig. 7. Integral christmas tree.

cover

plug

tubing hanger

tubing spool

annulus linewith control valves

production linewith control valvescontrol pod

housing

base frame

Fig. 8. Wellhead and subsea christmastree, system with guidelines (courtesy of Cooper CameronCorporation, CameronDivision).

Criteria for wellhead designWellhead characteristics are defined on the basis of

the pressure rating, the Product Specification Level(PSL), i.e. the type of steel used and the TemperatureClass (TC), according the 6A standards of the API andISO 10423:2003 (ISO, 2003).

Pressure rating. Working Pressure (WP) is definedas the highest pressure to which a single component,the wellhead in this case, may be subjected during itsworking life. API has conventionally divided wellheadoperating pressure ratings into six classes: a) 1st classto work up to 2,000 psi (13.8 MPa); b) 2nd class up to3,000 psi (20.7 MPa); c) 3rd class up to 5,000 psi(34.5 MPa); d) 4th class up to 10,000 psi (69.0 MPa);e) 5th class up to 15,000 psi (103.5 MPa); f ) 6th classup to 20,000 psi (138.0 MPa).

An increase in the rating is reflected in a rise in thecosts, this is why an accurate determination of therating is of the utmost importance. Given the lack ofmeasurements of the maximum wellhead pressure, theStatic Bottom Hole Pressure (SBHP) is used as theworking pressure, i.e. it is assumed that WP�SBHP.This approach is obviously cautionary and leads tosystem oversizing, critical when approaching thetechnological limits of construction (today around20,000 psi, 138 MPa), and with a heavy impact oncosts. It is therefore advisable to measure the wellheadpressure during exploratory well tests and to useWP�STHPmax � SF, where STHPmax is the maximumStatic Tubing Head Pressure measured and SF is aSafety Factor - chosen on the basis of the uncertaintyof the measurement, defined by the company (forexample, SF�1.1 for natural gas wells and SF�1.3 foroil wells). This criterion takes into consideration thestatic tubing head pressure, measured during a testafter the well has been shut-in for a certain period oftime, which is the equivalent of the static bottomholepressure minus the hydrostatic pressure generated bythe fluid column contained in the tubing (Phyd), i.e.STHP�SBHP–Phyd. If the fluid in the tubing is a drygas, and therefore not subject to further phase changesduring the measuring period (normally 48 hours), it ispossible to assume a safety coefficient value (1.1)lower than that assumed in the case of oil (1.3). Oil,which liberates gas in the well and thus develops into atwo-phase state, tends to segregate in the tubing whenthe well is closed (with the heavy components on thebottom and the lighter components on top). Since thedynamics of this phenomenon might not be completeat the moment of measurement, the static pressuremeasured during a shut-in may be lower than theactual shut-in pressure. For this reason, it is preferableto assume a higher SF to determine the rating and toassume an average estimated density of the two-phasefluid in the tubing.

Product Specification Level (PSL). This consists of a range of values (from 1 to 4) which defines all ofthe quality controls to which the materials must besubjected during design, construction and testing. Thehighest value is that applied for the most severeinstallation conditions. The PSL of the equipment isbased on a logical process that evaluates the predictedworking pressure and the hydrogen sulphide (H2S)content, since this compound is highly corrosive forsteels and lethal to humans. If H2S is present, the PSLalso accounts for environmental conditions in terms ofthe vicinity of civilian structures and the applicabilityof the NACE (National Association of CorrosionEngineering) standard specifications for the selectionof materials (MR 01-75 standard; NACE, 2001). The aim of this environmental evaluation is to providethe constructor with design and construction criteria(the PSL) suitable for the different installations,according to the actual working conditions, on thebasis of risk evaluation.

Temperature class. This defines the applicationlimits within a class to which corresponds the choiceof steel grades. A wellhead must commonly meet anumber of temperature classes simultaneously andtherefore the relevant materials must be chosen withgreat care (for example, in sub-arctic conditions withtemperature variations between �40°C and �40°C).

3.7.3 Fluids present in the well

Completion fluidThe completion fluid is present in the well during

completion installation or removal. A good completionfluid must be dense enough to ensure a hydrostaticpressure greater than that of the formation (at least 300 psi), contain a minimum amount of solids and, if itdoes contain solids, generate a filtrate that will notdamage hydrocarbon bearing levels. Furthermore, itmust also be viscous enough to ensure the solidstransport capacity. Oil-based drilling muds are rarelyused. Brine, heavy brine or foams are more common.For more details, see Chapter 3.5.

Annulus filling fluid (packer fluid)The packer fluid is the static fluid present in the

annulus between the tubing and the production casingthroughout completion life. It can be the same as thecompletion fluid or any appropriate fluid that ensuresthat its density is maintained over time to balance thestatic reservoir pressure at the bottom of the hole (killfluids). In other words, it must be able to kill the wellin the case of loss, breakage or release of the barriercreated by the packer and tubing. In high pressure andhigh temperature wells, where the tubing and casing



sizing criteria are near the acceptability limits of thesafety factors, it may be advisable not to use a killweight fluid. In fact, in such wells, the highhydrostatic load a fluid with the density characteristicsdefined above (i.e. with a pressure gradient greaterthan 1.8-2 bar/10 m), together with the accumulationof high pressure at the head of the production annuluscaused by a possible leak in the tubing, could lead tocasing failure or tubing collapse. The consequences ofsuch an event would be more critical than those to beavoided by means of the counterpressure due to thepacker fluid. The latter however is never to beconsidered a safety barrier.

3.7.4 Impact of safety on the completion scheme

Whatever the type of completion to be designed, thereare minimum prerequisites that must be respected toensure the safety of the installation with respect to thesurrounding environment and the safety of thepersonnel working directly on the well site duringinstallation, production and workover as well as toprotect the people and objects in the vicinity. There areactive and passive safety measures during the variousphases. Active safety measures are those actually orpotentially manageable during operation (dynamicbarrier). Passive safety measures are those intended toensure that fluids are contained whatever the externalevent (static barrier; Fig. 9). The criterion normally

accepted in order to achieve a safe design, is that ofhaving two independent barriers that can be testedseparately.

Static (primary) barrierThe static barrier contains the fluid and isolates it

from the surrounding environment without the needfor outside intervention. The activation of the barrieroccurs for example with a fail safe valve when thebarrier assumes the safe (i.e. closed) positionwhenever the control element (the hydraulic controlpressure) fails, either by choice or design.

The barrier only acts as such in the direction of theflow it is supposed to prevent. For example, the tubingalone is not a barrier, but becomes one when linkedwith a bottomhole packer and if check valves areinstalled at its ends (bottomhole wireline plugs,christmas tree valve). It can be tested both withpositive (over pressure) and negative pressures (underpressure). The downhole safety valve installed in thetubing is not normally considered a barrier as itoperates as a safety valve only in one direction, whilein the other direction it allows the passage of fluidwhich is to be pumped into the well. It does howeveract as a supplementary emergency safety devicerequired by the company’s safety policy since it isdesigned to act in the case of accidental leaks from thewellhead and therefore when there is the possibility ofescape of hydrocarbons into the environment. It istherefore not taken into consideration as one of thetwo independent barriers.



well during completion well producing well after killingbefore BOP installation

static barrierannulus 1(B)�4�5�6

tubing A�4�5�6

dynamic barrierA�4�5�7

static barrierB�3(2)�8(6)�4�5

static barrierC�3(2)�8(6)�4�5

A BOP

B wellhead

C plug inside hanger

1 valve

2 safety valve

3 tubing

4 casing

5 cement

6 packer fluid

7 completion fluid

8 packer

Fig. 9. Safety barriers.

Dynamic (secondary) barrierThe dynamic barrier contains the fluid and

isolates it from the surrounding environment in acontrolled environment. It is not a classic barriersince the open/closed concept cannot be applied to itand testing its effectiveness is difficult. For example,the denser completion fluid is a ‘dynamic’ barriersince it stops the reservoir fluid from flowing thanksto the differential pressure generated by the differentdensities of the fluids. In an interval open toproduction, it only guarantees this containmentwhen the two fluids are in static equilibrium. In theopposite case, i.e. when the formation absorbs thecompletion fluid, the weight balance becomesunstable and, if not controlled by reintegratingabsorbed fluids, the well may start to flow. This isbecause the level in the tubing is lowered followingabsorption. If not compensated, it in turn causes adrop of hydrostatic pressure on the formation, thusallowing hydrocarbons to enter the well. Thecompletion fluid can be considered a dynamicbarrier since, for short periods and under closecontrol and observation, its effects can be exploitedduring tubing substitution operations, in thepresence of the static barrier supplied by the BOP.On the other hand, the packer fluid remains staticduring the well’s production life from the time whenit is installed until the first workover. Nonetheless, itcannot be considered a barrier because, even if itsdensity is high enough to control the well, itsrheological characteristics may deteriorate with timeand its density thus be altered.

Selection of safety systemsThe above considerations related to barrier

definitions aside, a well’s safety configuration dependson the policy of the country where the well is operatedand of the company operating it. Generalization istherefore absolutely impossible. For example, Table 1and 2 show the minimum criteria that the designershould respect independently of the geographic area of



Table 1. Selection of safety valves: applications

Type of valve Application

Tubing retrievable flapper valve Wells in offshore platformsSubsea wellsWells with presence of H2S or CO2Wells with surface flowing temperature greater than 130°C

Wireline Retrievable Surface controlled flapper Valve As on insert valve for tubing retrievable SCSSVs(WRSV)

Storm chokes As a backup to the WRSV when there is a control linefailure. Set in the lower wireline nipple

Annular safety system Gas lift wellsESP wells with gas dischargeJet pump wells (under the pumps)

Wireline retrievable injection valves All injection wells (water, waste water, cuttings)

Table 2. Selection criteria for safety valves

Type of well Criteria

Oil production All new offshore developmentsAll onshore naturally

flowing wellsAll wells to be recompletedAll isolated wells

Gas production All new offshore developmentsAll wells to be recompleted

Gas storage All wells

Gas injection All wells

Water injection All wells

Artificial lift All gas lift wells in, tubing annulus

ESP wells with tubing,including annulus in the caseof gas discharge

H2S in produced fluids All wells

the world where operations take place. Theseminimum criteria require the use of downhole safetyvalves to form an emergency barrier in the case ofuncontrolled production from the well. Such valvesmust be of the fail safe type, they must be controlledfrom the surface and are normally installed in theproduction tubing. They must also have the samepressure rating as that defined for the tubing and thechristmas tree.

3.7.5 Selection of materials

Once the fluid corrosivity characteristics are known,the types of steel must be selected. This activity has tobe started very early because, if it is thought to benecessary to perform control tests on the existingmaterials and qualification tests for new materials,long times are required. Material selection isfundamental for the life of the well because, asidefrom hydrocarbons, H

2S and/or CO

2, chlorides (Cl–),

oxygen (O2), aerobic or anaerobic bacteria flora may

also be present. Therefore, the tubing, liner andchristmas tree, as well as production casing and thewellhead must be resistant to corrosion. A carefulchoice of steels must take into account the predictedduration of completion, whether there will beworkover during its production life and relative capitaland operating costs.

Methods to control well corrosionMethods for controlling corrosion include one or

more of the following options, depending on theirimpact on the project cost and development strategies:a) use of tubulars with extra thickness (corrosionallowance) and carefully planned substitutions; b)choice of appropriate corrosion resistant alloys; c)reduction of tensions; d ) elimination of sharp bends;e) elimination of impulsive loads and/or vibrations; f )chemical inhibition through use of a scavengers for O2and/or H2S, control of the pH and use of inhibitors; g)application of an internal coating; h) use of carbonsteel with non-metallic inserts.

The strategy of using corrosion allowance isapplied where there is generalized corrosion in thecarbon steels, and thicker tubing is chosen. In thatcase, substitution of the tubing at set times isplanned, for example when workover on the well dueto reservoir problems is already planned. Options c, dand e are aimed at eliminating stress in situations ofSulphide Stress Cracking (SSC). They are related tothe well profile and are not always attainable. Theycan however lead to the adoption of mixed sections orsections of tubing in Corrosion Resistant Alloys(CRA) in the zones under greatest stress, limiting

carbon steel to the zones under less stress. The use ofthese methods requires an adequate evaluation of thestates of stress throughout the length of the tubing.Chemical inhibition with sequestering agents istypical of processes limited in time, for exampleduring drilling, or is applied to fluids in a staticconditions – the packer fluids for instance – in orderto avoid damage over time due to action of oxygenand bacterial flora. On the other hand, corrosioninhibitors are used for production/injection fluids.These are generally amine-based substances (seeChapter 5.4) that limit or slow corrosion, coating thetubing wall with a thin film and are generallycomplementary to the use of corrosion allowance.Inhibitors are normally added in small quantities(ppm) to the produced fluids, and in differentconcentrations in all injected fluids. There arevarious methods for using inhibitors in theproduction well: injected into the well in cushions(batch treatment), injected into the formation(squeeze treatment), left at bottomhole so that theycan transported by the fluid produced over time, orby continuous injection. In the last case, theirtransport to the bottomhole requires the installationof small diameter chemical injection lines banded tothe production tubing. The injection of inhibitorsmust be combined with a detection system on thesurface to evaluate their effectiveness during thewell’s production life, for example, by means of teststo evaluate the weight loss. The cost of inhibitors andtheir management must be carefully evaluated duringdesign because on a long-term basis they may becomparable with apparently more expensive systemssuch as the use of corrosion resistant alloys. Theinternal coating method consists of covering theinternal walls of the production tubing with an in situcured epoxy bicomponent resin. To this end, there areresins that are resistant to aggressive well chemicalsas well as to high temperatures (130°C) which offeradequate protection to corrosion as long as there isnot excessive wear due to wireline and coiled tubingtrips (see below) in the wells. In fact, such tripsdamage the surface of the walls by friction, thusuncovering metallic areas that are then subjected to apreferential corrosive attack. The resins used aresensitive to permeation of gas and, in the case ofextremely violent decompression, can blister, swelland lose adhesion. For this reason, their applicationmust be carefully analysed. They involve a costroughly 20% higher with respect to carbon steel andthe bonus is a reduction of the flow frictioncoefficient. Furthermore, they require specialconnections (CB rings, Corrosion Barrier rings) toisolate metal to metal seals and avoid damage duringmake-up. The tubing with non-metallic liners is



manufactured with tubular material in carbon steel,with internal liners of composite materials (fibreglass). They have the same function as the internalcoating described above, however they reduce theinternal diameter by at least 5 mm instead of a fewtenths of a millimetre in the case of coatings. Variouscompositions and types of filling between the tubingand liner (cement, resins) have been identified, andhave various applications both in water injectionwells and natural gas wells. For aramidic resins thatare resistant to high temperatures, the cost iscomparable to that of martensitic steel.

Tubular materialsThe tubular materials for wells is collectively

indicated as OCTG (Oil Country Tubular Goods) andclassified according to API standards based on: theOutside Diameter (OD) of the tubing (OD 1.05''-4.5'')and of the casing (OD >4.5''); the range of the lengthof each element e.g. for the tubing in terms of range 1(20-24 ft), range 2 (24-32 ft), and range 3 (32-48 ft)and for the casing in terms of range 1 (16-25 ft), range2 (25-34 ft) and range 3 (34-48 ft); the linear weight(lbs/ft or kg/m) for which, once the outer diameters areset, both the thickness and the inner diameters of thetubing (the diameter used for fluidodynamiccalculations) can be determined. Another parameter tobe considered is the drift, a conventional measurementthat defines the maximum diameter of any piece ofequipment that can run inside the pipes (tubing orcasing) without it getting stuck. OD-connection is theouter diameter of the collar or of the upset of thethreaded pipe end, i.e. the maximum tubing diameter.Finally, the grade indicates the steel’s characteristics.

Premium or gas tight connections are used at mostfor production tubing. It is recommended that theseconnections also be used for the casing and productionliners, particularly when the annulus is used for gaslifts or when the packer fluid gradient is lower thanthat of the reservoir (underbalanced). Connections canalso be of the collared or integral type. The substantialdifference between upset or integral connections andcollar connections lies in the fact that the latter requirecutting of an extra thread on each tubing and thereforeintroduce an additional potential point of leakage. Forthis reason, upset connections are preferred inexploration wells. The fact remains that the use ofupset connections is limited in time, if they are usedrepeatedly and then tested, because the number ofrecuts is limited due to exhaustion of the upset part.Tubing made from corrosion resistant alloy cannot beupset. They are cold worked and upsetting wouldimpair their resistance and require after forging attemperature and heat treatment that would render thepipe inhomogeneous at its extremities.

Seal elementsThese normally consist of elastomers

(components with high elastic properties) for the gasseal and non-elastomers for anti-extrusion.Elastomers that are used as seal units can bedistinguished into the following configurationsaccording to the function which they must fulfil. O-rings are designed to bear pressure under staticconditions and can also support variations in pressurefor a limited number of cycles; in any case, they tendto be extruded out of their grooves, and thereforethey need rigid support. They are generally usedeither statically as internal seals for completionequipment or in components that are subject to asingle cycle (pressure equalization systems). The T-seals/moulded seals are designed as dynamic sealsand are harder than the O-rings. They work withhigher interference and can incorporate anti-extrusion metallic reinforcing elements during hotmoulding. In the form of T-seals, they are often usedin tubing hanger seals, while in the form of mouldedseals, they are used as dynamic seal packs inside SealBore Extensions (SBEs) of the packer or PolishedBore Receptacles (PBRs). The PBRs are used if largetubing elongations are foreseen. V-packings areobtained by moulding and mounted as seal units thatperform their task inside the packer seal bore. Theywithstand pressure rises inside the V-shape, whilethey collapse when pressure is applied in the oppositedirection. The packing units thus consists of twopacks of single V elements facing in oppositedirections. This characteristic renders them suitableto bear some dynamic pressure, or sudden pressurereversals. Given the fragility of each unit, the V-shaped elements are always installed in pack (sealunits) and never individually. Given the reducedthickness of the rubber lip, they withstand poorly,extended and repeated movements inside the sealsurfaces in which they are installed. The packingelements of packers are large in comparison to theother seals. They work, not by diametral interference,but by compression transmitted during the packersetting movement directly from the anti-extrusionelements of the packer itself. In order to meet thecompression setting criteria, the elastomer needs acertain elasticity; for that reason, only rubbers withthese characteristics – NBR (Nitrile ButadieneRubber), HNBR (Hydrogenated Nitrile ButadieneRubber), Aflas – are suitable, while harder rubbers(Kalrez, Chemraz) are not appropriate for this type ofapplication (packer elements) despite their greaterresistance to aggressive chemicals. Metal To Metal(MTM) seals are used when well conditions are soextreme due to pressure, temperatures and aggressivechemicals that the use of elastomer materials is



impossible. The seal is usually supplied byelastoplastic deformation and interference of a softmetal element on the structural component made ofalloy steel (Incoloy 825 on Inconel 718). In thesecases, it is important to carefully evaluate the designof the seal – which requires accurate machining –and the installation conditions and procedures –which require extremely clean conditions in thesealing area. The change from elastomers to metal tometal seals means a considerable increase ofequipment cost and therefore must not be extensivelyused if not strictly required.

3.7.6 Determining the size of the tubing

The determination of the size of production tubingrequires both an analysis of fluid flow, in order tochoose the optimal diameter to attain production at thedesired flow rate, and a mechanical analysis, todetermine steel grade and thickness. All of this isneeded to ensure an installation which is in line withthe safety criteria that each company adopts. There issoftware for the first type of analysis that calculatesthe tubing diameter (nodal analysis) and the frictionlosses along the tubing, using fluidodynamic data asinput. For the second type of analysis, stress analysissoftware is used to simulate all of the possible loads onthe tubing during the different phases of the well’sproduction life. The resistance criteria determine thedesign acceptability via the verification of the designfactors.

Nodal analysisA broad estimate of the oil and gas tubing flow rate

range is provided in Table 3. These are average valuesthat do not take into account the real length of the welland the fluid composition and are therefore onlyindicative. The actual determination of the sizerequires more precise estimates. The process followed,summarised below, is called nodal analysis because it

calculates and supplies the fluidodynamiccharacteristics in every node in the system (Fig. 10).From a comparison of the energy available from thereservoir and the energy required by the well systemup to the surface, the optimum diameter of theproduction tubing over time can be determined; it willbe a compromise between the requirement of theinitial hydrocarbon flow rate and its variation overtime, both as flow rate and as composition (ratiosbetween the gas/oil, water/oil and gas/water phases).The objectives of nodal analysis are to examine thesystem to predict the flow rate, and to optimize thediameters of the system components. In order to do so,the following key operations are necessary:• Selection of the most appropriate equation

describing the resistance to the flow movementinside the reservoir and the wellbore (IPR, InflowPerformance Relationship) as a function of theflow rate and selection of the deliverability curve(VLP, Vertical Lift Performance) which describes(again as a function of the flow rate) the energyrequired to lift the hydrocarbons to the surface.

• Analysis and definition of reservoir performancein proximity to the well, based either on geometricor induced damage to the formation, caused bydifferent operations and/or by the natural reductionof reservoir pressure over time.

• Analysis of the multi-phase flow in the tubing.• Calculation of the working limit for natural flow

and assessment of the possible need for artificiallifting.

Curve of available bottomhole energy The simplest curve of available energy (IPR,

Inflow Performance Relationship) is linear, in whichthe Productivity Index (PI) is proportional to thedifference in pressure between the reservoir and thewell (i.e. the more the flowing pressure is reduced withrespect to the static pressure of the reservoir, thehigher the quantity of fluid that is produced). This istrue for non-compressible, single-phase fluids thatflow above the bubble-point pressure. The equation



Table 3. Flow rate range as a function of the tubing diameter

Tubing Tubing Tubing ID Range of oil Range of dry gas size weight (inches) flow rate flow rate

(inches) (lb/ft) (m3/d) (km3/d)

2.375 4.6 1.995 <150 <502.875 6.4 2.441 150-500 50-250

3.5 9.2 2.992 300-1,000 80-4004.5 12.6 3.958 500-1,600 180-1,0005.5 17.0 4.892 800-2,700 250-1,5007.0 29.0 6.184 >1,200 400-4,000

that supplies a linear IPR in the p-Q diagram is thefollowing: PI�Q/(pr�pwf ) where pr is the averagereservoir static pressure in the area surrounding thewell (SBHP), pwf is the flowing pressure at the samedepth to which pr is referred, and Q is the total flowrate of the fluids produced at the surface at standardconditions (101 kPa, 15°C). The linear IPR curve isnot valid when dealing with two-phase reservoir fluids.When the flowing pressure drops below the bubble-point pressure (pb), the gas saturation around the wellrises causing a reduction of relative permeability toliquids and therefore a reduction of the flow rate. Inthis case, the real IPR is curved downwards in the p-Qdiagram. For this section of the curve, Vogel (Vogel,1968) found a numeric model for this part of the curvedefined by the equation Q/Qmax�1�0.2·(pwf /pr)�0.8·(pwf /pr)

2 where pr is less than pb, Q is the liquidflow rate, and Qmax is the maximum liquid flow ratewhen pwf � 0. The complete curve of the IPR whichincludes the bubble-point pressure consists of astraight line for p�pb and of a non-linear sectionwhich acts according to Vogel’s equation for p�pb.This curve is modified to take into account theresidual damage around the well after removal.

Energy curve to lift the fluid to the surface The curve expressing the energy needed to lift the

fluid to the surface (VLP, Vertical Lift Performance)takes into account all of the pressure losses in thetubing for a certain diameter and requires numericalintegration of the fluid gradient curve in steady stateflow along the entire length of the tubing. This curve isdetermined by three factors: pressure loss due to achange in the potential energy (DpPE), pressure lossdue to variations of kinetic energy (DpKE), andpressure loss due to friction (DpF), thusDp�DpPE�DpKE�DpF. Each term is determined bymeans of empirical correlations validated bylaboratory tests carried out by varying the flowparameters. The point of intersection between the IPR(curve of available energy) and the VLP (curve ofenergy needed for the diameter considered) gives thenaturally flowing well flow rate at the givenconditions. Varying the different system parameters(WHFP, Well Head Flowing Pressure) and the tubingdiameter, it is possible to determine the variousproduction flow rates. The best choice of tubingdiameter is that which produces the requested flowrate with minimal completion costs. Given parity of



gas

psep

Dp8�(pwh�psep)

Dp 7

�(p

wf�

p wh)

Dp7�(pwf�pwh)

Dp2�(pwfs�pwf)

Dp2�(pwfs�pwf)

Dp1�(pr�pwfs)

Dp1�(pr�pwfs)

Dp5�(pwh�pDSC)

Dp�(pwh�psep)

Dp5�(pwh�pDSC)

Dp4�(pUSV�pDSV)

Dp4�(pUSV�pDSV)

Dp3�(pUR�pDR)

Dp3�(pUR�pDR)

Dp6�(pDSC�psep)

Dp6�(pDSC�psep)

pDSC

pwh

pDSV

pUSV

pDR

pUR

pwfs pr pepwfs

liquid

separator

choke-regulator stock tank

total friction losses in surface linestotal friction losses inside tubing

friction losses at wellborefriction losses in reservoir

friction losses at surface chokefriction losses at safety valvefriction losses in Inside Diameter restriction

friction losses in surface lines

Inside Diameterreduction

safety valve

Inside Diameterreduction

bottom hole

Fig. 10. Pressure lossesscheme to calculate tubingdiameter.

the flow rate, when the tubing diameter is increased,the pressure losses diminish or given an equalbottomhole Dp, the well produces at higher flow rates.If the IPR and the VLP never meet, for the flow rateand pressure requested, the reservoir will not havesufficient energy for natural flow and thus an artificiallift system must be installed in order to produce ateconomically viable flow rates. All of the correlationsused in calculations for both the fluids’ PVTcharacteristics and the equations used to determinepressure losses give valid estimates for different typesof fluids. For this reason, proper adjustment have to bemade, although too many attempts to make thecorrelations coincide with the actual data can bedetrimental. To avoid this, the data must correspond tothe measured conditions at the extremities of thesystem, i.e. at the wellhead and bottomhole.

Tubing stress analysisOnce the optimum diameter for production tubing

has been defined and the type of steel to use has beenchosen on the basis of the environment conditions, it isnecessary to verify whether the tubing can be installedin the type of well to be drilled. In other words, thecompatibility with the production casing diameter mustbe verified. Then, the thickness and grade (mechanicalcharacteristics) must be defined so that they can meetthe stress conditions calculated in the various loadhypotheses, and the Safety Factor (SF) set by the oilcompany. The Tubing Stress Analysis (TSA) is carriedout both for safety in design, i.e. by defining theminimum strength needed for well equipment(breakage of part of the completion can be harmful topeople and objects, not to mention the loss of the wellproduction itself), and to optimise capital costs. In fact,a sizeable percentage of the well capital costs, up to 20-30% in the case of special alloys, is due to the tubularmaterial. Therefore, by calculating the real loads, it ispossible to optimize safety factors, thicknesses andtherefore costs. The TSA must be applied to all tubularmaterial in the well and to the interaction betweentubing and casing. Generally, the tubing has theminimum critical cross section and is therefore theelement most subjected to limit loads. In reality, giventhe complexity of the downhole equipment, there maybe weakness in other completion components. In orderto take this possibility into account, once the nominaldiameter, grade and thickness of the tubing are set, thespecifications of the Down Hole Equipment (DHE)require that this equipment supports at least the samelimit loads as the tubing itself.

Material propertiesIt is presumed that metals follow an elastic

behaviour and that their yield and tensile strengths are

indicated by the symbols Ys and Ts, respectively. Itshould be remembered that, aside from causingexpansion and contraction of the metal, variations intemperature determine the variation of the Ys of thematerial, which decreases as the temperature increases(in particular for CRAs and cold worked steels) andthis decrease becomes larger as the number ofelements in the alloy increases. The value of thethermal expansion coefficient generally used for steeltubes is: 12·10�6 m/(m·°C) for carbon steel, 16·10�6

m/(m·°C) per austenitic steel, 13·10�6 m/(m·°C) forferritic-austenitic steel (coefficients valid fromambient temperature up to approximately 150°C).

The mechanical properties of Premium connectionsare normally higher than the characteristics of theassociated pipe body. They are generally not a problemfor the overall resistance of the system if – for that givenload situation – only the tubing strength is considered.There are however some limitations, such as forexample compression strength. While the tube behavesin an axially symmetric manner to tension andcompression, the connections often have less resistanceto compression than to tension and therefore leaks candevelop at the metal to metal seals in the case of heavycompression on the tubing.

Verification of stress is independent of thecompletion scheme, since the well, whose predominantdimension is length, requires that only the stress alongthe axis of the tube be taken into consideration. Thesections under stress are those included from thewellhead to the packer, which at setting fixes the lengthon which stress variations occur. Sections of tubingbelow the packer are subjected to stress due only totheir own weight, unless they are bound between twopackers. In dual completions, the tubing sections are tobe sized individually and then, according to theprinciple of the superposition of effects, the congruencyof the movements at the dual packer is imposed. Thereare four possible ways that tubing in the well can break:by axial load, by internal pressure or bursting, bycollapse due to external (outer) pressure or by acombination of loads (triaxial stress). In order to verifywhether the completion string can support the stresses,it is necessary to: identify and determine the loads towhich the string will be subjected; compare the loadswith the pipe strength (defined by API standards); andcompare the real loads with the certified metal strengthvalues in combination with an adequate safety factor.This comparison is made by first defining the designfactors for the types of breakage outlined above: a) adesign coefficient for axial load (ratio between the yieldstress and total calculated axial load); b) a designcoefficient for bursting (ratio between maximum burstpressure leading to yielding and the difference betweeninternal and external pressure); c) a design factor for



collapse (ratio between the maximum collapse pressureand the difference between external and inner pressure);d) a design factor for triaxial load (ratio between theyield strength of the materials and triaxial stress).

Load modelsThe completion scheme of a well is subject to

various loads during the working life of the well, i.e.during installation, production and pull-out. Thus, forevery case, a ‘basic case’ is defined which is generallythe situation created – in terms of pressure,temperature, associated loads and related deformations– when the completion is run down hole. Then, thevarious cases of load as variations of the basic casehave to be examined in sequence. It may be necessaryto take into account particular situations that may ariseover time (i.e. stimulation with acid solutions,formation fracturing, wellhead shut-in, etc.).

The logical sequence of calculation requiresstarting with a completion with the tubing anchored tothe packer and that this layout, the absolute safest, isprogressively modified only if the calculation fails,eventually arriving to a solution in which the tubing ispartially or totally free to move with respect to thepacker.

Definition of loadsOnce the system geometry (depth, deviations,

diameters) has been determined, it is not onlynecessary to define the pressure and temperature ofthe initial case – for which direct measurements aregenerally available – but also to generate load casesfor the entire well production life. It is thereforeimportant to list the operations that will be carried outin the well, to generate pressure and temperaturesprofiles along the entire length of the production string(by nodal analysis) and to use these profiles tocalculate the stress induced on the tubing.

The main load situation that may arise are:Completion installation. The loads exerted in this

phase are due to pressure tests and tubing’s ownweight. The basic case predicts the condition of thetubing run in hole with the packer at its lower end.During completion installation, the tubing is heated tothe ambient well temperature according to the welltemperature profile. As such the tubing is not affectedby temperature but only by pressure. The firstvariation during the running is thus pressurization atthe packer setting; the packer, once set to the casingwall, stops any further lengthening of the tubing.

Acid stimulation, fracturing. Stimulations arecarried out to remove damage or improve formationpermeability. Acid stimulation consists of the injectionof a known quantity of liquid (acid solutions) withhigh flow rate and high pressure (with variations of

friction and cooling of the string). Hydraulic fracturingleads to the exasperation of stress due to thestimulation: the volumes injected, the injection rates,the times and pressure reached during fracturing, inparticular before fracture formation, are thusincreased.

Wellhead shut-in. This operation involves a rise inwellhead pressure, since bottomhole pressure tends toreturn to the values of reservoir static pressure and –since the fluid pressure gradient is certainly lower thanone (presence of two phases or only gas) – a residualincrease in shut-in pressure is generated at thewellhead. This load condition must be consideredsince the temperature reached at the wellhead duringproduction does not fall immediately, as aconsequence of the thermal inertia in the well, andtherefore the load condition relevant to thetemperature is similar to that during production, butwith greater wellhead pressure.

Completion pull-out. This is the condition thatexpresses the pull tension that must be applied to thetubing to release it from the packer itself or to releasethe packer during the pulling out for workover andwhich depend on the type of packer installed.

Considering installation of the completion andpacker setting as the basic case, the other typical loadsituations to production wells are: a) opening of thewell for production (test and stimulation); b) long-termproduction; c) shut-in; d ) completion pull-out(releasing tubing from the packer or releasing thepacker); e) other planned operations (artificial lift,successive stimulations, etc.); f ) stress on theproduction casing due to temperature variations (if notcompletely cemented). For injection wells, in additionto completion installation and packer setting, the otherload situations are: a) beginning of injection (test andstimulations); b) long-term injection; c) reopening ofthe well to injection after a shut-in; d ) stress on theproduction casing due to temperature variations (if notcompletely cemented); e) completion pull-out. Asstated above, stress must be verified in axial, radialand tangential directions (API standards only giveindications on the individual loads applied and do notconsider combinations of loads). The typical approachis thus both to determine the stresses in the threedirections (axial, radial and tangential) and to comparethem with the values indicated by API, as well as toverify the composite stress (triaxial stress).

While the formulae used in determining stress arenot given here, it is worth highlighting the effect ofaxial loads. If the tube is free to move, pressure andtemperature variations only give rise to variations inlength. If, instead, the tube is fixed, the axial force isthe sum of the forces that would exist if the tube werefree and the forces generated by the resistance of the



anchorage to deformation. Generally, the movement isfirst calculated as though the tube were free and thenthe forces to bring it back to the initial position aredetermined (or at least to the position of anchorage),also taking any instability due to buckling intoaccount. This method makes it possible to evaluate themovement of a mobile seal within the packer when thetubing-packer connection is free and thus to determinethe length of the seal elements to install or, in the caseof an anchored tubing-packer connection, to establishthe pull that the contracting/elongating tubing exertson the packer and therefore on the casing. At thispoint, it is worth mentioning the curving of the tubinginto a helix due to buckling load, because of the factthat in this case the deformation is limited by thepresence of the casing. This makes it possible to reacha higher grade of instability (Fig. 11). The buckling ofthe production string can be tolerated in many casesfrom a static point of view if the tensions areacceptable. Still, it should be verified that this does notlead to other problems, such as those related to:blockage of the passage of equipment lowered

downhole by wireline; or metal to metal connectionseal loss if the bending is excessive. There are specificformulae to determine the maximum diameters of theinstruments and the length of the equipment that cango through a section of tubing under bucklingconditions. It is however possible to mitigate oreliminate the effects of buckling by increasing thepressure in the production annulus, since this tends tostraighten the tubes.

Design tensions and maximum admissible tensionsThe so-called Design Factor (DF) is the ratio

between yield tension and real tension (calculated)in one section of the structure, while the SafetyFactor (SF) is the ratio between yield tension andmaximum admissible tension (normally set by theoil company). The result of the TSA of a tubingstring is the evaluation of the design factors in all ofthe completion sections for all load conditionspredicted throughout the life of the well (includingabandonment or workover). The process may requirerepeated calculations in the event of unsatisfactoryresults (the DF must be greater than or equal to theSF) or when various alternatives are analysed inorder to establish the most advantageousconfiguration in terms of cost/benefits. From acomparison of the DF, the SF and the acceptance ofthe values calculated for all tubing sections, it ispossible to determine: the forces exchanged betweenthe tubing and the packer; the forces exchangedbetween the packer and the casing; and the packerstrength, verifying the loads calculated on itscharacteristic curve that indicates the maximum loadsupported by the packer (this characteristic curve issupplied by the manufacturers and/or determinedexperimentally). The SFs normally acceptable arefixed by the oil company. Should the calculationresult in a DF less than the minimum required SF,modifications of the configuration must beintroduced and the calculations repeated.Modifications may involve: a) a higher grade ofsteel (verifying the limitations of use in the presenceof H2S when grades of over 80,000 psi or 655 MPa(L80) are required); b) an increase in the pipethickness (section increase, noting however that inthis case, the pipe weight and pressure also increaseand the temperatures of the fluid produced/injectedchanges, thus making it necessary to repeat thefluidodynamical calculations); c) use a pull or astack off of the tubing on the packer or change thepacker (or the packer setting mechanism); d ) the useof a smaller production casing in the case of largebuckling of the tubing. On the other hand, should theproblems of the system only be caused by particularoperations like stimulation or fracturing, which



F

Mf

Mt

F

a

neutral point

Fig. 11. Helical buckling of the tubing. Mf, moment of flexion; Mt, moment of torsion; a, angle of the helix of deformation.

cause high contraction due to cooling, action can betaken by heating the injected fluid or increasing thepressure in the production annulus.

3.7.7 Choosing packer type,setting method and tubing-packer connection

The integral type tubing-packer connection providesthe greatest structural and seal guarantees. However,the selection of the type of packer, having taken intoaccount tension analysis results, is the result of severalcompromise solutions. In order to select the type ofpacker to be used, the type of well where it is to beinstalled is evaluated. A distinction is made between;a) very critical wells, those with True Vertical Depths(TVDs) of over 4,500 m, with high temperatures(SBHT, Static Bottom Hole Temperature, of over130°C) and high pressure (SBHP, Static Bottom HolePressure, greater than 700 atm), subsea wells, thosewith platforms on shipping lines (transit lines ofcommercial maritime traffic) and high-pressure gas-injection wells (over 210 atm); b) very critical andcorrosive wells, those with the characteristics definedin point a but producing highly corrosive fluids; c)critical wells, those with a SBHT of between 100°Cand 130°C and a depth between 3,000 and 4,000 m(TVD); d ) non-critical wells, those with a SBHT ofbelow 100°C and a depth lower than 3,000 m (TVD).

The general approach is to use simple completionschemes in the more complex and critical situations,and then, in very corrosive and critical wells, to usetested equipment of guaranteed reliability withoutalternative daring operating solutions that may failduring the working life of the well.

The selection criteria also take into consideration aseries of parameters for each well category. Suchparameters can be related to: the procedure (forexample, the use of perforation systems, by means ofguns run downhole and activated once productionpackers are set, provoke mechanical shock); the typeof completion fluid used (if a completion fluidcontaining solids in suspension is used, the use ofretrieval packers is critical since their releasemechanisms can be blocked over time by the depositof solids); or the life of the completion because offrequent pulling out of the tubing and the productionstring with the packer.

The design scheme followed in very critical wellsis as follows: first, choice of the packer, then thechoice of the tubing-packer connection and finally ofthe method of packer setting. The criterion is similar tothat for other well categories where the installationoperations and the type of fluid used are different.

Single completionsIn very critical wells, a permanent packer is chosen

because it supplies the best mechanical and sealperformance. In very corrosive wells, a permanent-retrievable packer is used because the corrosivity ofthe system may require its removal during theproduction life. If a permanent-retrievable packermade of the adequate CRA steels is chosen, theretrieval can be planned without milling, consideringthat the milling for permanent packers is timeconsuming when they are made of chrome-nickel steelalloys. For critical and very critical wells, the hydraulicpacker setting method is the best solution. The reasonfor this choice lies in the fact that the packer isgenerally run downhole with the production tubingand therefore, in order to avoid problems related todeposit in the annulus, a filtered fluid not containingsolids in suspension and of adequate density iscirculated in the annulus before setting. At this point,the system is ready for hydraulic setting which iscarried out after the installation of a wireline plugbelow the packer. The two aspects that need to betaken into consideration for the tubing-packerconnection are the choice of the tubing-packerconnection and the predicted tensions. In very criticalor corrosive wells, first the anchored tubing is chosen:the choice is made between an anchored system and asnap latch system capable of separating at a pre-determined load. If the TSA shows that DF�SF, i.e. ifthe connection holds in all load situations, acompletely anchored system is chosen. If, instead, theanalysis indicates that DF�SF and the connectiontends to release, for example during stimulation, asnap latch system is used with a mobile seal element(PBR) that only starts functioning in critical cases (forexample, cooling and contraction due to stimulation).The entire process must be re-verified and should theproduction still indicate DF�SF, a totally mobilesystem with mobile seals must be chosen. In this lastcase, since there is a free connection, the packerrunning and setting methods must also beenreconsidered. If this choice is made, there are no otherverification problems since a free connection is alwaysverified. The analysis is also used to determine thetubing elongation/contraction and therefore the lengthof the seals to be chosen. Other well categories requiresimilar considerations – ranging from packer settingmethods to methods for level perforation – to take intoaccount how the guns are run downhole and the loadsthey employ, as well as the composition of fluids andtheir solids content.

Selective completionsThe considerations outlined below can be applied

to selective completions with two or more productive



levels and give an indication of the various possibilitiesin selecting the packers and their setting methods,based on the critical elements described in the wellclassification. The case of a dual completion has beenillustrated, but it is clear that in the presence ofmultiple levels, the lower packer is the first startingfrom the bottom while the upper packers are all thesame. When conditions of criticality are not applied,selection is based on the predicted setting depth. Infact, the greater the depth, the less suitable the use ofmechanical packer setting methods that requiremanipulation of the tubing string as well as multipleruns for multiple completions. The setting methoddepends mainly on the distance between packers.Wireline set mechanical packers (with explosivecharges) are generally placed very precisely since thedepth is controlled by the depth recordings whilerunning. They are only used as bottom packers becausethey require a dedicated run, followed subsequently bythe tubing running with all upper packers. Ifpermanent packers are used, hydraulic setting for allthe packers is preferable. When the lower packer ispermanent, the upper packers are retrievable and brineis the completion fluid, the safest method is hydraulicsetting for all the upper packers, while the lowerpacker is set by means of a wireline. When all of thepackers are retrievable, hydraulic setting is advisableand, in this case, the distance between the packers mustbe at least 50 m. This distance takes into account theelasticity required by the relative movements betweenthe packer components that generally tend to scrapethe section of tubing above the packer during setting

(with shorter distances, the mechanical anchoring andthe sealing can be compromised because of anincomplete setting stroke). As regards the tubing-packer connection scheme, the choice of the upperconnection is based on calculation of the tensionsapplied to the single completion, while the subsequentconnections are chosen on the basis of differentcriteria. In general, anchored connections are usedwhen all of multiple packers are run-in hole together,while mobile connections are used when each packer isrun individually, and then reintegrates the packeralready in the well.

3.7.8 Tubing hanger selection

Together with the tubing spool, the tubing hanger isthe element that joins the drilling wellhead and thechristmas tree (Fig. 12). The vertical crossrun of thechristmas tree has the same dimensions as theproduction tubing since the connection size of thetubing and the tubing hanger Inside Diameter must becompatible. In particular, the inside of the tubinghanger must be larger than the production tubingInside Diameter because it contains the first nipple forwireline equipment, generally dedicated to the backpressure valve. This valve is installed as a primarysafety barrier during the BOP installation and removalphases when the well is completed. The choice of steelfor the tubing hanger is consistent with that of thetubing, in particular, since it is made from a forgedbar, it is normally of nobler material than the



gate valve

tubing hangermetal seal

metal seal

swagelock

new vam

test port

autoclave valve 15,000 psi

test port

vent port

back pressure valvetubing head adaptertubing head spooltie down

gate valvecontrol line

Fig. 12. Tubing hanger.

corresponding tubing. The tubing hanger is located inthe tubing spool, which has special shoulders ofsufficient size to support the maximum weight andpressure loads of the tubing string. Here, it is blockedmechanically inside the tubing spool by radial means(tie-down) or, more recently, with elastic snap rings.

The connection to the production tubing involvesthe premium thread of the production tubing itselfwith metal to metal seals, while the link with thechristmas tree requires metal to metal seals that can bea transition type carrier (Laurent carrier). Tubinghanger to tubing spool seals are normally elastomeric,while only in the case of high pressure andtemperature wells (15,000-20,000 psi, T�100°C)metal to metal seals are used. The tubing hanger isalso used to support and provide outside links to thehydraulic control lines of the Surface ControlledSubsurface Safety Valve (SCSSV). In the case ofhorizontal wellheads, the tubing hanger has a differentlayout with the flow outlets in a horizontalconfiguration, while on the vertical run, above the sideexit, there are wireline profiles which support themetal-to-metal seal wireline plugs that act as primarybarriers. In the case of wells which are pumped byElectric Submersible Pumps (ESPs), the tubing hangermust also support the electric mandrel that interruptsthe electric cable to facilitate assembly duringcompletion installation and which works as a safetybarrier during production. As far as the choice ofaccessories is concerned, see Chapter 3.5.

3.7.9 Subsea completions

Subsea completions use downhole equipment that issimilar to that used on land/offshore wells, but differwith respect to the equipment placed on the sea floor.The hydrocarbons produced by isolated and/orgrouped wells are conveyed to a manifold system,designed to handle different flows from productionwells or destined to injection wells.

In a production system with a riser (see Chapter5.2), the latter is used to transport hydrocarbonsfrom the manifold system to a surface structure thatmay be a fixed platform, a semi-submersibleplatform or an anchored ship, modified to receivefluids on board and possibly serve as a loadingterminal for oil tankers. As mentioned elsewhere(see Chapters 5.2 and 5.4), the hydrocarbonsundergo treatment at the surface in order to achievethe transport specifications (degassing, waterremoval, desulphurisation, etc.). Subsequently, theyare transferred into tankers, in the case of oil, or sentback to the sea floor, being pumped into subseapipelines.

The conventional subsea wellhead system(Fig. 13) involves the use of a christmas tree with avalve configuration similar to that of a surfacechristmas tree for dual completion. The verticalpenetration with larger diameter (production bore) isdedicated to the tubing, while the other verticalpenetration is used to control the production annulus.During the completion phase, the well is linked to thesurface rig by means of an environmental productiontube that isolates it from the sea (marine riser). Theriser is tensioned between the rig and the subseaBlow Out Preventer group (BOP stack) which is usedto guarantee the continuity of the well from the seafloor to the surface. When the tubing hanger –containing two vertical holes – is installed at the endof completion, it is run downhole with the tubinghanger running tool and the production riser andplaced inside the drilling wellhead, in its dedicatedrecess. The production riser consists of sectionsjoined to each other with rapid connectors and eachsection includes two lines of tubes: the actual tubingand the annulus line. This allows control of thecirculation between the annulus and the tubing fromthe surface, even with the hanger landed in its restingposition. A flexible, umbilical line is banded to theproduction riser during running and contains a seriesof lines for passage of the fluid for hydraulic control,fluid allowing remote control of the setting andtesting functions of the tubing hanger and of therelease of the production riser from the tubinghanger. After running, setting and testing of thetubing hanger, the next step is the installation andsetting of the wireline plugs placed inside the tubinghanger inside each line of tubing of the productionriser. These wireline plugs, together with the wellsafety system, act as the safety barrier duringremoval of the BOP and drilling riser system until theinstallation of the subsea christmas tree is completed.One of the functions of the umbilical is the release ofthe tubing hanger running tool from the tubinghanger when at the surface and this will allow thesubsequent pull out of the production riser, which isretrieved section by section. The BOP stack is thendisconnected from the wellhead and pulled outtogether with the drilling riser. At the surface, thesubsea christmas tree and workover control packageare assembled and tested, and the entire group isagain run using the production riser and theumbilical. Once the equipment has reached the seafloor and is aligned with the christmas tree, it islanded and connected to the drilling wellhead, thehydraulic connectors are closed and all the pressureand functionality tests are performed. At this point,the christmas tree is ready for working. The wirelineplugs are extracted from the two profiles in the



tubing hanger and the vertical swab valves of thechristmas tree are closed; the workover controlpackage is released and everything is retrieved withthe production riser. The last component to beinstalled is the tree cap which, in the case ofconventional subsea christmas trees, links all of thetree’s hydraulic controls to the production controlpod, so that the tree can be controlled by theproduction system when the production flow lineshave been linked to the christmas tree. A different,less costly system is the horizontal subsea wellhead,which allows the use of the drilling riser both forcompletion and workover, thus reducing capital costsfor service material.

A simpler control system for a subsea wellhead isthat based on direct hydraulic control operated with aremote station from the surface. The reaction time ofsuch a control system is however unacceptable forlengths of over a few hundred metres. For greaterlengths, the most common systems are pilotedhydraulic systems (sensitive to variations in feedingpressure) and electro-hydraulic systems. The controlsystems are divided into: workover control systemsand production control systems. During the runningphase and christmas tree testing, the workovercontrol system operates the hydraulic function of thetubing hanger running tool and the valves, activatesall of the closing and opening systems of thehydraulic connectors, allows hydraulic testing of thesystem seals, and provides continuity to the hydrauliccontrol lines from the bottomhole safety electric linesof the valves, pressure and temperatures transducersand any operated bottomhole valves (smartcompletions). It is a safety system that ensures

closure of the Emergency Shut Down (ESD) valvesand controls rapid disconnection from the bottomshould the rig move off the well vertical by a distancegreater than that allowed, due to adverse weatherconditions.

The production control system controls the subseawellhead from the production unit and thus has all thevalve control functions. It also transfers the monitoringsignals of the wellhead and bottomhole tools.

3.7.10 Notes on artificial lift

As highlighted in the discussion on the determinationof the size of the production tubing diameter, when theinflow performance relationship (IPR) and vertical liftperformance (VLP) curves for the fluid in question donot intersect and there are therefore no operatingconditions for natural flow, in order to produce the oil,it is necessary to install an artificial lift system thatgives the fluid the energy it needs to reach the surface.In the following, the various systems of artificial lift,the concepts on which they are based and the limits oftheir application that must be examined beforeselection will be illustrated. This is partly based on theenvironment where operations will take place(onshore, offshore), the energy systems available(electricity, gas, hydraulic fluids), and relevant costs.For further details on artificial lift systems, seeChapter 6.2.

There are about a million oil wells in production inthe world today, 90% of which use artificial lift. Themost common systems are: sucker rod or beampumping, gas lifts, and electric submersible pumps.



master valve blocks

production chokesfor commingling flowfrom multiple treespre-engineered valveassemblies for everyapplication

mechanical treeconnectoruses hydraulic powerfrom tree running tool

gas lift configurationwith choke

flowbase with bothproduction and annulus

connections

Fig. 13. Subseacompletions (courtesy of Cooper CameronCorporation, CameronDivision).

Other systems include: hydraulic piston pumping,hydraulic jet pumping and Moineau pumps (PCP,Progressive Cavity Pumping; Fig. 14).

The selection criteria include the followingfactors: production conditions, reservoir data, fluidproperties, and economic parameters, e.g. capitalcosts and operating costs. Moreover, the type of well(single or multiple completion) must be considered inorder to determine the possibility of commingledproduction and any geometric interference of eitherthe tubing or other equipment. Other considerationsare whether the wells are onshore or offshore andwhat type of profile they involve (vertical ordeviated). Additional factors to consider are theenergy systems available, the logistics of transport,storage and treatment facilities for the fluids, and theenvironmental impact. Other important elements arethe climatic conditions, fluid corrosivity, anyproduction of solids (sand, clay), the presence ofparaffins, the type of reservoir drive mechanism andthe variation of pressure and percentage of water andgas produced over time.

3.7.11 Final design

The final well completion design is therefore the resultof an interactive process which may or may notcoincide with the original scheme. Whatever the casemay be, the final scheme must be crosschecked withthe operating procedures of equipment running andretrieval and with potential emergency situations atvarious levels to ensure overall safety. Clearly, thedesigner must work to meet the well productivity andsafety objectives set at the beginning of the project.When this is impossible, even after modifying thesystem parameters where possible and acceptable, thedesigner must inform the oil company of possiblelimitations in production or operations. As mentionedearlier, the design must include technical drawings,sizing calculations, a list of components and productspecifications to prepare the call to tender formaterials purchasing. Moreover, the design mustinclude estimates of the cost of materials, plants andservices and installation and management timing(including forecasts for workover timetable), to allowthe project managers to draw up the budget (CAPEX,CAPital EXpenditure, and OPEX, OPeratingEXpenditure) and to obtain approval for purchasing.

3.7.12 Workovers

Workover is defined as any intervention carried out inthe well after completion, for any reason, whether this

includes use of a drilling rig or other systems such asservice rigs, snubbing units, coiled tubing or wirelineunits. Workover makes it possible to act on formation(washing, stimulation, cement squeezing, etc.) or onthe well itself (bottomhole cleaning, level change,substitution of packer or tubing, substitution of thechristmas tree, etc.).

The main operations carried out during workoverconcern:• Mechanical problems, including tubing and packer

repairs, elimination of obstructions caused by sand,paraffin, asphaltenes and scales (salt deposits),repairs of the gravel pack damaged by sand,cement squeezing, cement plugs and sand plugs,fishing out of equipment lost in the well, milling ofpackers and damaged equipment that cannot befished out, and complete well shutoff.

• Reservoir problems, including level change,perforation extension, elimination of undesiredgas or water production, opening of obstructedholes, reduction of productivity due to emulsionor water blocking, level partialization, acidizing,fracturing, etc.

• Conversion of the well, including installation of anartificial lift system, injection of gas and water,and the conversion to a gas storage well.

Equipment used

Workover rigsThe main difference between a drilling rig and a

workover or service rig lies in the smaller size of thelatter due to different operating purposes. As a resultthey entail lower daily costs, greater rapidity ofrigging-up/rigging-down/transport and less bulk. Onthe other hand, a workover rig has less hoisting power,less installed hydraulic power and less stowagecapacity of tubular material on the derrick. Inparticular situations, the use of a drilling rig may berequired to carry out workovers. This may occur in thecase of deep wells, a first completion at the end of the



Progressive Cavity Pump, PCP

centrifugal pump

others

rod pump

hydraulic pump

gas lift

Fig. 14. Artificial lift: world wide distribution.

drilling phase, subsea wells, isolated offshore wells,and offshore wells (even on platforms) where it isimpossible to operate with a workover rig or if none isavailable.

Snubbing unitSnubbing is the technique of lowering tubings of

conventional length and diameter that are connectedone to the other and pushed (stripped) into the wellunder pressure by means of a system of hydraulicpistons with the use of two BOPs to guarantee safety.The technique allows rotation of the string andinjection of fluids for possible mechanical repairs ofthe well or for reservoir pressure support. The unit ismounted directly on the christmas tree and allows thetubing string to be pulled out by use of a hydraulicpiston. It has the advantage of being able to operatewhen the well is under pressure and allows heavyworkover (for example, dismantling of the completion)without having to shut-in the well. On the other hand,it has the disadvantage of a low pull-out speed due tothe reduced hydraulic piston stroke. To avoid thisproblem, in countries where it is most commonly used(Canada, USA), the unit is combined with a servicerig, i.e. a unit equipped with a rotary table, and thuswith rotating capacity. It can normally be used forlight workovers and is often employed for the purposesof well control for blowout remedial.

ETU operating unitThe Endless Tubing Unit (ETU) or coiled tubing

is a technique that uses a continuous tube of smalldiameter coiled around a drum and run/pushed intothe well through the injection head, thus making itpossible to pump treatment/circulation fluids without

rotating the tube itself (Fig. 15). The ETU isessentially composed of coiled tubing, a gooseneckinjection head, a control house, a power pack andpressure control equipment. It is equipment typicallyused without a workover rig (rigless) and can bemoved rapidly (by lorry on land, or barge at sea),with significantly reduced operating costs withrespect to a conventional rig. Since it consists of acontinuous tube (diameter 1''-3.5'') unwrapped from adrum kept under pressure, it avoids the possibility ofrotation of the equipment in the well or to slack offweights or pull heavy loads. For that reason, it ismainly used to circulate fluids and/or clean thebottomhole. However, by means of fluid pumping itcan operate bottomhole motors and turbines.Recently, this type of equipment has been used fordirectional drilling where the deviation of thebottomhole equipment is achieved using hydrauliccontrol lines run inside the coil.

Wireline unitThe wireline unit is a system that allows

intervention inside the production tubing using aharmonic steel cable that transports, essentially usingthe payload force of gravity, equipment to thebottomhole. It allows numerous well operations (e.g. setting plugs, opening/closing of valves, andopening/closing of sliding sleeves) to be performedfrom the surface using a slick line or a wire rope withan electrical wireline that activates instruments, gunsor allows data collection. The advantages of this unitare that it works even on a live well, the unit is small,it requires little maintenance and is cost effective. The limitations are essentially related to the wireresistance.



control cabin coiled tubing reel power skidBOP

christmas tree

lubricator/riser

goose neck

hydraulic hose

stripper/stuffing box

quad BOPs

injector head

Fig. 15. Coiled tubing unit.

Bibliography

API (American Petroleum Institute) (1994) Bulletin on formulasand calculation for casing, tubing, drill pipe & line pipeproperties, API Bul 5C3.

API (American Petroleum Institute) (2000) Specification forsubsurface safety valve equipment, API Spec 14A.

API (American Petroleum Institute) (2001) Specification forcasing & tubing, API Spec 5CT.

ASTM (American Society for Testing and Materials) (2002)Specification for mechanical testings of steel products,ASTM A 370.

Harper C.A. (2002) Handbook of plastics, elastomers andcomposites, New York, McGraw-Hill.

ISO (International Organization for Standardization) (2000)Petroleum and natural gas industries. Corrosion resistantalloys seamless tubes for use as casing, tubing and couplingstock, ISO 13680.

ISO (International Organization for Standardization) (2001)Petroleum and natural gas industries. Downhole equipment.Packers and bridge plugs, ISO 14310.

ISO (International Organization for Standardization) (2002)Petroleum and natural gas industries. Procedures for testingcasing and tubing connections, ISO 13679.

ISO (International Organization for Standardization) (2004)Petroleum and natural gas industries. Subsurface safetyvalve systems. Design, installation, operation and repair,ISO 10417.

Magarini P.A. et al. (2000) Best practices & minimumrequirements. Sec 1, Eni-STAP.

NACE (National Association of Corrosion Engineering) (1996)Laboratory testing of metals for resistance to sulfide stresscracking in H2 S environments, NACE TM 0177 96.

SINTEF (Scientific and Industrial Research at the NorvegianInstitute of Technology) (2002) Reliability of well completionequipment. Phase IV, SINTEF-Eni.

References

API (American Petroleum Institute) (2004) Specification forwellheads and Christmas tree equipment, API 6A.

ISO (International Organization for Standardization) (2003)Petroleum and natural gas industries. Drilling andproduction equipment. Wellhead and Christmas treeequipment, ISO 10423.

NACE (National Association of Corrosion Engineering) (2001)Sulfide stress cracking resistant metallic material for oilfieldequipment, NACE MR 01 75.

Vogel J.V. (1968) Inflow performance relationships for solutiongas drive wells, «Journal of Petroleum Technology», January,83-92.

Marco MarangoniScientific Consultant



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