03 well completion

8/17/2019 03 Well Completion

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Well Completion

3.1 INTRODUCTION

The individual well is much more that just anexpensive faucet. It provides the onlycommunication with reservoir during theexploitation of a field. The effectiveness of

that communication is a driving factor in thereservoir drainage as well as overalleconomics. The individual well completionmust be designed to yield maximum overallprofitability.

A well completion is nothing but anarrangement that allows the well to produceoil and gas from the reservoir to surface.

The completion basically consists of: Bottom hole equipment to provide

communication between producingformation and well.

Tubulars and accessories to provide a

means for the produced fluids to flowfrom bottom to surface

ell head equipment for control and

monitoring of the produced fluids.

An ideal completion is the one that meets thedemands placed upon it for the exploitation of a reservoir at lowest cost for the entire

producing life. !any factors"both reservoir and mechanical need to be considered tointelligently design completion of a well.

Reservoir Considerations:

#eservoir considerations involve the locationof different fluids in the formation penetratedby the well bore$ flow behaviour of these fluidsin the reservoirs and the characteristics of theroc% itself. It is the producing rate thatprovides maximum economic recovery which

is often considered as the starting point for well completion design. The other importantfactors that influence the well completiondesign are as follows:

!ultiple reservoirs that require multiple

completions with or without pac%ers$ insingle or multiple strings etc.

#eservoir drive mechanism mainly

determines the completion or perforation interval depending on

expected movements of gas"oil or water"oil contacts. A water drive

reservoir may indicate water cutproblem. &issolved gas drive mayindicate artificial lift and the dissolvedgas and the gas drive reservoirsusually mean declining productivityindex and increasing '(#.

'(# Techniques may require

completion methods conducive toselective injection or production.Thermal recovery processes mayrequire special casing and cementingmaterial.

)timulation may require special

perforating patterns to permit *oneisolation$ perhaps adaptability to highinjection rates and pressures and a

well hoo% up such that after treatment$the *one can be returned to productionwithout contact with %illing fluids.

+igh Temperatures may require

special cementing$ casing and casinglanding practices.

)and ,ontrol may dictate the type of

completion in a well where sandcontrol measures are to be adopted.

or% over -requency$ wherever it is

high$ and often dictates completionconducive to wire line or throughtubing type re"completion systems.

Artificial ift requires single

completions even where multiple*ones exist$ as well as larger thannormal tubulars.

Mechanical considerations:

It involves the mechanical configuration or

well hoo% up to exploit the reservoir effectively$ monitors down hole performancesand modify the well situation when necessary.

hile designing well completion$ it shouldalways be %ept in mind that design should becost effective$ safe$ simple and reliablefulfilling all anticipated operating conditions./eeping in view the above influencing factors$the basic decisions to be reached are

a0 !ethod of completionb0 1umber of completions within the well

borec0 ,asing 2Tubing configuration

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CHAPTER-3CHAPTER-3


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Well Completion

d0 &iameter of the production conduite0 ,ompletion interval

This chapter mainly deals with the types of development wells and their completions.

3.2 TYPE O! "E##

Based on the well construction profile$ thewells can be classified as:

3.4ertical well5.&eviated6 &irectional well7.+igh angle well8.+ori*ontal well9.xtended #each &rilling ;#&0 wellroducers that produce hydrocarbonsfrom the reservoir

Injectors that inject fluid into the

reservoir for better recovery

3.3 TYPE O! COMP#ETION

The completion types can be classified ondifferent basis. )ome of the completionclassifications are discussed below:

3.3.1 C#$I!IC$TION %$ED ONC$IN& CON!I&UR$TION

Basically$ there are the following threemethods for completing a well based oncasing configuration:

3. O'en hole co('letion ;fig. 7.30 wherethe production casing is set on top of or slightly into the pay *one and cemented.The pay *one is left open anduncemented.

$dvanta)es o* o'en hole co('letion

• )pecial drilling techniques can be

used to minimi*e formation damagesince the casing is set at the top of thepay *one.

• +igher production since full well bore

diameter is available for flow

• )aving in perforation costs since no

perforation is required.

• +ole can be easily deepened and

converted to a liner completionsubsequently

• +igh productivity is maintained when

gravel pac%ed for sand control.

!i)+re 3.1 O'en,hole co('letion

Disadvanta)es o* o'en hole co('letion

3. The fluid flow from or into well borecannot be controlled

5. The gas or water production cannotbe regulated effectively since theentire hole is open

7. &ifficult to selectively stimulate

producing intervals

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Well Completion

8. ell bore may require periodiccleanout

5. Per*orated co('letion ;fig. 7.50 wherethe producing interval is covered by theproduction casing cemented and then

perforated for ta%ing production.

$dvanta)es

The tubing controls the internal

corrosion of the casing becauseproduced fluid flows through it and donot contact the casing.

Disadvanta)es

Tubing restricts the flow of produced

fluid.

The completion is more expensive because of the cost of pac%er$ tubing and accessories.

!i)+re 3.2 Per*orated co('letion

7. #iner co('letion ;fig. 7.70 where theproduction casing is set on top of the pay*one and is followed by a liner6slottedliner6 screen. The slotted liners andscreen are not cemented. In case liner islowered then the same is cemented andperforated in the producing layer.

$dvanta)es -ormation damage is minimi*ed

)elective stimulation is possible in

cemented liner

>erforation expense is avoided in

screen liner ,leanout problem is avoided in screen

liner

Disadvanta)es

&iameter across the pay is minimi*ed 'ood quality cementation is difficult in

cemented liner.

!i)+re 3.3 #iner Co('letion

3.3.2 C#$I!IC$TION %$ED ONNUM%ER O! TU%IN& TRIN&

Based on the number of tubing stringslowered into the well$ the most commonlyused completions can be classified into:

a- in)le co('letion

A single tubing string is lowered in to thewell to ta%e production from either a

single layer or many layers. All thefigures shown above indicate singlecompletions.

In case production is ta%en from multiplelayers through a single string then thecompletion string ma%es use of pac%ersand sliding sleeves to control flow fromindividual layer. It is important that thereservoir pressures of all the layersflowing into a single string be similar for this type of completion to be successful.

- D+al co('letion

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Well Completion

In dual completion ;-igure 7.80$ twolayers are completed and productionfrom each layer is ta%en through differentproduction strings. )uch type of completion does not require thepressures of individual layers to besimilar since the production from eachlayer is independent from one another.The layers are isolated through use of pac%ers.

$dvanta)es

It is possible to produce from6inject into

more than one production6 injection*one through a single well$ therebyreducing overall development costs.

)elective treatment of individual *one

is possible.

?se of natural energy from one *one

can be used to artificially produceanother *one.

Disadvanta)es:

arge number of equipment down hole

used can create problems.

xpensive and more complicated

completion and wor%over technique.

>ossibility of loss of production in *onedue to mechanical problems andformation damage during wor% over.

!i)+re 3./ D+al co('letion

3.3.3 C#$I!IC$TION %$ED ON

NUM%ER O! 0ONE COMP#ETED

Based on the number of layers completed$ thecompletion types can be:

in)le one co('letion

This is the simplest concept in which only asingle layer is completed for production.

M+lti'le one co('letion

In this type of completion$ a number of layersare completed in a well using various

configurations. )ome of the configurationsare:

in)le strin),in)le Pacer:

The flow from two layers is ta%en throughtubing and casing. This type of completion is not used in offshore asproduction through casing and tubingannulus is considered a safety ha*ard.)uch configuration does not allow upper formation to be produced through tubing.

in)le trin),D+al 'acer:

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Well Completion

In this type of completion also$ there isflow in tubing and annulus. +owever$ itallows the upper *one to be flowedthrough tubing. Again$ for safety of casing$ such completions are not used inoffshore unless in cases where there isprovision to divert the production throughannulus to tubing string.

Parallel strin),M+lti'le 'acer:

This type of completion is same as dualcompletion discussed above.

in)le strin),M+lti'le 'acers,

elective ones:

In such completions$ the producing*ones are opened or closed individually

through use of wire line or hydraulicpressures.

3.3./ MICE##$NEOU COMP#ETION

&as li*t co('letion ;-igure 7.90

The casing is set through the pay *one andthen perforated. A pac%er is set above theproducing *one with the tubing string thathas required number of gas lift valves. Areadily available natural gas is injected downthe casing through the gas lift valves and into

the tubing. It may be injected at variousintervals. This gas is used to lift the reservoir fluid to the surface when the reservoir pressure is not sufficient to lift the fluids onits own.

!i)+re 3. &as #i*t Co('letion

T+in)less cased hole co('letion

In tubing"less cased hole completion$ casingis set into or through the producing formationand cemented ;refer fig 7.


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Well Completion

!i)+re 3.4 T+in)less cased hole

Co('letion

3./ COMP#ETION E5UIPMENT

The completion equipment used arediscussed in brief in the following sections.

3./.1 "ellhead E6+i'(ents

ellhead equipments are attached to the topof the various casing strings lowered in a wellin order to support the tubular strings$ hangthem$ provide seals between strings and

control production from the well.

A typical wellhead assembly$ as shown in-igure 7.= consists of:

#o7er(ost casin) head to support

the other strings of pipe and seal theannular space between the two stringsof casing.

#o7er(ost casin) han)ers to

suspend the next smaller casingsecurely and provide a seal betweenthe suspended casing and the casingbowl.

Inter(ediate casin) heads to provide

a means of supporting the next smaller

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!i)+re 3.8: $ t9'ical "ellhead asse(l9

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Well Completion

Intermediate casing hangers to

suspend the next smaller casing stringin the intermediate casing head.

Tubing head to provide a support for

the tubing string$ seal annular spacebetween the tubing string andproduction casing string and alsoprovide access to the casing 6tubingannulus through side outlets;threaded$ studded or extendedflanged0.

Tubing hanger ;fig 7.@0 to provide a

seal between the tubing and the tubinghead and also to support the tubing.

The loc% screws force the top steelmandrel or plate down to compressthe sealing element and form a sealbetween the tubing and tubing head.-ull tubing weight can be temporarilysupported on the tubing hanger$ butpermanent support is provided bythreading the top tubing thread into theadapter flange on top of the tubinghead. The hanger then acts as a sealonly.

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!i)+re 3.8: $ t9'ical "ellhead asse(l9

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Well Completion

In selecting a tubing hanger$ it should beensured that the hanger will provide anadequate seal between the tubing and tubinghead for the particular well conditions ;metalto metal seals are desired in most cases0 andthat it is of standard si*e and suitable for lowering through full opening drillingequipment.

Adapter to connect two flanges of differentdimensions or connect a flange to a threadedend. ,rossover flange to connect flanges of different wor%ing pressures.

!ultiple completions or multiple"tubing"stringcompletions require the same wellheadassembly as single tubing string completions$with one exception. The tubing"head bowl

must be designed and si*ed to accommodatethe required si*e and number of tubing stringsand provide a means for properly orienting thetubing strings.

!i)+re 3.: T+in) ;an)er

3./.2 Christ(as tree


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Well Completion

!i)+re 3.?: =,(as tree

3./.3 Prod+ction t+in)

>roduction tubing forms the conduit for the

reservoir fluids to flow from well bore tosurface. In addition$ it facilitates well boreservice operations such as wire line$stimulation$ circulation etc. Typically$ tubing isrun inside a casing or liner but can also becemented in slim hole wells as the casing.&epending on the type of completion$ one or two tubing strings may be used in the well.

The major considerations in the selection of tubing for a particular well are:

T+in) sie is determined on the basis of inflow performance of the reservoir and tubingperformance so as to ensure optimumproduction rates over the fieldDs life. Tubing

si*es from 5 =6@E to 9 FE si*es are in use.

T+in) )rade determines the chemicalcomposition and physical mechanicalproperties of tubing. The tubing gradeselected for a particular completion mustsatisfy the minimum performancerequirements for that application. Tubing of sufficient yield strength to withstand thevarious forces caused by changes inpressures and temperatures must be used inthe well. The tubing must also be resistant to

formation fluids containing corrosivecomponents e.g. +5)$ ,(5$ chlorides andwater. 1ormally$ "@G grade of tubing is usedwhich provides resistance to )ulfide )tress,rac%ing.

T+in) 7ei)ht determines the burst andcollapse ratings of a tubing and is normallyexpressed in pounds per foot ;ppf0 and is afunction of thic%ness of wall.

T+in) connections are primarily either A>Iconnections or premium connections. The

commonly used A>I connection is ? thatprovides reliable service in a majority of wells.>remium tubing connections are used incorrosive environments$ high"pressure wellsand in wells with bends and doglegs. A Typical well completion diagram with thedown hole completion equipment is illustratedin fig.7.3G. The well completion configurationcan vary from well to well based of differentfactors.

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Well Completion

-ig. 7.3G Typical well completion diagram

3././ Pacers

A pac%er ;-ig.7.33 and7.350 provides a meansof sealing the tubing string from the casingthereby preventing communication of fluids.This protects the casing from undue stress inthe form of pressure differentials and alsoprotects the casing against the corrosion anderosion from the produced fluids. )ince casingused in a well is a permanent component of

the completion system$ repair 6 replacement of casing is very complicated and expensive.The pac%er along with tubing string is easier to remove and replace. >ac%ers are also usedfor *one separation as in the case of multiple*one completions. All types of pac%ers are mostly consists of:

!lo7 (andrel to provide the flow

conduit for production. Resilient ele(ents to ensure the

tubing to annulus pressure seals. Cone or "ed)es to assist in

positioning of the slips.

li's to grip the casing wall and

prevent the pac%er from movingup and down.

;old do7n +ttons to prevent

pac%er from unseating.

The pac%er design also provides for a spacer tube that has holes to remove trapped air andbypass ports to circulate out debris settled onpac%er pressure equali*ation across thepac%er elements.

The criteria for pac%er selection mustconsider:

)election 6 completion strategy

#ig capacity for fishing6 milling

-ishing requirements ell fluid characteristics$ +5)$

,(5 Bottom hole pressure

temperature

!i)+re 3.11.Mechanical

'acer

!i)+re 3.12. "ire line setPer(anent 'acer

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Well Completion

The pac%er can be single$ dual or triple bore

and are mainly classified as: "

• Retrievale 'acer

A retrievable pac%er is run as an integral

part of the tubing string and is set either mechanically or hydraulically and can bereleased by pulling or rotating the string.

$dvanta)es

Tubing can be landed and the

,hristmas tree be installed.

The pac%er does not have to be milled

out if it becomes necessary to removeit$ thus saving rig time.

>ac%er can be reused in other

applications.

!echanical retrievable pac%er can be

reused in same well withoutredressing.

Disadvanta)es

>ulling may swab the well in if pac%er

is not fully released.

They have lower differential pressure

rating mostly limited to =9GG psi.

quali*ation of pressure across the

pac%er may be difficult.

hile stimulating the well with cold

fluids$ excessive contraction of tubingmay shear the pac%er release studs of straight pull release type pac%ers$ if the hold down buttons are not holding.

The mechanically set retrievable pac%ers are

set by applying sufficient right hand rotationsto the string and released by straight pull.,ompression set mechanical pac%ers havedies downwards e.g. #TT)$ #"7. Tensions setmechanical pac%ers are used when pac%er isto be set at shallow depths where requiredcompression cannot be given. The pac%er configuration in tension set pac%er is oppositeto that of compression set i.e. slips at top andrubber elements at bottom. >rior to running inthe pac%er$ it must be ensured that the rubber elements$ spacer rings$ dies$ slips$ Teflon ringat the top sub are in good condition.

The hydraulic set retrievable pac%ers are setby applying a pressure of 38GG to 5GGG psiinside the string and thus require a systemsuch as >ump (ut >lug to apply pressure.The >(> rating depends on well pressure.The ratchet mechanism in the pac%er storesthe setting pressure and enables theelements to remain in inflated condition. Thepac%er is released through a releasering6screws that shear at an over pull of 5G$GGG to 7G$GGG lbs above pull out weight.

Per(anent 'acer

The permanent pac%er$ normally once set$ isregarded as part of the casing and can onlybe removed destructively by milling.

The completion string can be engaged into for providing the flow conduit or removed fromthe pac%er for well %illing.

>ermanent pac%ers can be set mechanically$hydraulically or electrically through wire line.

)ome recent designs of permanent pac%ers$such as Huantum pac%er of !6s)chlumberger$ can be set hydraulically andretrieved also after the job is completed.

These type of pac%ers are recommended for use where long term completion$ high"pressure differential$ maximum dependability$large pac%er bore are required.

In*latale 'acer

The inflatables pac%ers ;Figure 3.13) arerun through the tubing string either on wireline or coiled tubing and inflated to therequired si*e. The pressure rating of suchpac%ers is less. )uch pac%ers are used instraddle completions and for open hole

testing.

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Well Completion

!i)+re 3.13 In*latale 'acer

3./. %last @oint

#eservoir fluids entering the well bore throughperforations may display a jetting behaviour that can erode the tubing string at the point of fluid entry and ultimately may cause thetubing failure.

The blast joints


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Well Completion

3./.11 a*et9 valves

a. +,+r*ace Control a*et9 >alve-

)ubsurface control is executed by a number of devices such as safety valves$ bottom

hole cho%es regulators and injectionsafety valves. Based on operating6activation mechanism these valves can beclassified as:

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Figure 3.14 Blast joint Figure 3.15 Flo !oupling !i)+re 3.14 eatin) Ni''le

!i)+re 3.18 #andin) Ni''le !i)+re 3.1 a*et9 oint

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Well Completion

Di**erential 'ress+re or velocit9 t9'ewhere the valve is spring operated and %eptnormally open. The differential pressuredesign valve shuts in the well automaticallywhen there is abnormal production rate$ thisis due to rupture in surface equipment$ thatresults in higher pressure differential thanthe spring setting of the valve.

Press+re activated t9'e consists of avalve that is dome pressure operated andnormally closed until acted upon by apressure greater than the pre"set domepressure. The pressure"actuated valuesare pre"charged with a set dome pressureand held open by well pressure. hen theflowing pressure of the well drops$ the valvecloses to shut in the well. hen the tubing

pressure is equali*ed with dome pressure itwill open the valve automatically.

. +r*ace controlled s+,s+r*ace sa*et9valves -

The use of ),))4 is mandatory for offshore producing wells and offers amechanism for remotely operated sub"surface well control. It consists of a flapper type valve that is located in the string at a

depth of normally 39G m from wellhead. It iscontrolled from the surface by hydraulicpressure application through external Estainless steel control line. The valve is fail"safe close and is held open against springpressure by maintaining hydraulic pressure.The loss of hydraulic pressure will causethe valve to close and shut in the well.

)urface control units$ which supply thehydraulic pressure$ also monitor any

abnormal increase or decrease in flow linepressure. The valve operation isindependent of tubing pressure$ and wellfluid surges.

Both wire line retrievable and tubing

retrievable designs of ),))4 are availablebut the tubing retrievable type is extensivelyused in estern offshore.

Mal*+nction !ail+re o* C>

The four major reasons for the failure of ),))4 along with the li%ely reasons andtheir possible remedies are tabulated below:

In case of failure to open a ),))4$ asecondary safety valve vi*. storm cho%e isinstalled through wire line to loc% open the

),))4 flapper and continue withproduction. This is employed as a stop gaparrangement only till the time a rig isdeployed at the well for wor% over operationduring which the ),))4 is retrieved$repaired6 replaced and reinstalled.

The storm cho%e is velocity operated andhence requires no hydraulic pressure for itsoperation. The valve is designed for closureonce the production rate exceeds a pre"

determined level thereby ensuring wellsafety.

c. h+t do7n valve -

The shut down valve is used at surface inthe flow line from the C"mas tree and islocated after the flow valve. It ispneumatically controlled and gets closed in

case of any lea% in the flow line downstream of it.

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l.No. PRO%#EM PRO%$%#ERE$ON POI%#E REMEDIE

3. -lapper valvestuc% in openposition

)cale deposition due to highwater cut 6 1on"operation of

),))4 for a long time

Acid spotting6 (peration of),))4 once in < months6Installation of secondary)afety valve ;)torm cho%e0

5. +ydraulic controllinelea%

Temperature gradientdifference owing toinitial flow or flow afterstimulation job6 ea%ingconnector joints6 lastomer seals

)ystem always to be putonline to control panel for corrective pressure release6)ealtite application

7. ,ontrol line

bloc%age

)olid partcles in hydraulic oil >eriodic change of oil filters

8. ,ontrol systemfailure

)ame as at point no. 5 above

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Well Completion

3./.12 Circ+latin) valves

>rovision for tubing to annuluscommunication is required to circulate fluidsin a well$ treat a well with chemicals$ injectfluids from the annulus in to the tubing

string or produce a *one that is isolatedbetween two pac%ers. )uch tubing toannulus access is provided in thecompletion string through use of varioustypes of circulating devices.

a. lidin) sleeve

)liding sleeves;-igure 7.5G - are theprinciple circulating devices that providethe ability to circulate a well and alsoselectively produce multiple reservoirs.

A sliding sleeve is a cylindrical devicewith an inner sleeve and outer bodybored to provide matching openings. Theinner sleeve is moved using a wire lineshifting tool. hen the sleeve is movedand matched with openings in the outer body$ it creates a circulation pathbetween tubing and annulus.

)ome of the typical applications for which the sliding sleeves are used arefor displacing fluid$ selective testing$treating or production in multiplecompletion$ %illing by circulation$pressure equali*ing etc.

. ide Pocet Mandrel

)ide poc%et mandrel ;-igure 7.3 - has apolished receptacle6poc%et on one sidethat can accommodate down hole toolslowered by wire line. )ide poc%etmandrels are placed in the tubing stringat a location where it is necessary toinstall gas lift valve6 chemical injection

valve6 down hole cho%e$ complete thedual or multiple *ones$ test or treatselectively and provide communicationbetween the tubing and the annuluswhen required.

!i)+re 3.1? ide Pocet Mandrel

!i)+re 3.2B lidin) leeves

3./.13 &as li*t (andrel

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Well Completion

The gas lift mandrel is similar to side poc%etmandrel and is used to install gas lift valvesin the string through wire line or at surfacein wells completed with gas lift.

3./.1/ P+(' o+t 'l+)

A pump out plug is generally run at thebottom of the string and is used for hydraulically setting the retrievable pac%er.It has a seat to accommodate the ball andthe seat is loc%ed in position by shear screws of specified shear value. The balldropped for setting the hydraulic pac%er sitson this seat and ensures lea% proof system.hen hydraulically pressuri*ed fromsurface$ the pac%er is set at a

predetermined pressure. As more and morepressure is applied$ the entire shear screwsin the seat shear off allowing the seat of >(> to fall along with the ball in the sump.

3./.1 "ire line re,entr9 )+ide

The wire line re"entry guide forms thebottom most part of completion string and isbasically a mule shoe that is bevelled tofacilitate easy lowering of wire line tools inwell bore and their re"entry into the string.

)ome of the pump out plugs used have abeveled profile at the bottom and can beused as wire line re"entry guide.

In deviated wells$ when the string can getheld"up at pac%er top a self"indexing muleshoe is used. The weight on touching thepac%er triggers indexing and facilitates entryinto the pac%er by rotating the string.

3. INT$##$TION O!COMP#ETION E5UIPMENT

The following considerations should be %ept inmind while lowering and installation of completion equipment:

• ,asing I& restriction should be minimi*edor eliminated and well fluids should becirculated and conditioned before theequipment is lowered. The I& restrictionsmay result from mud ca%e build up$

cement scale$ over torque of casingconnection$ and pipe scale build. 1on"

condition well fluid may develop gelstrength or conversely may not be able to%eep solid in suspension. In either case aviscous coagulated$ semisolid stage maydevelop down hole$ ma%ing it difficult$ if not impossible$ to run completionequipment. A bit and scrapper run may benecessary to circulate out and reconditionthe well bore fluids.

• hen selecting completion equipment for a particular down hole service$ it isnecessary to specify equipment that isappropriate for use with the productiontubular under worst collapse and tensionconditions. &eviation from thisrequirement may be costly if equipmentfailure occurs down hole.

• hen installing pac%ers and other completion equipment it is best to run andset as quic%ly and accurately as possible.)afe run in speed should be determinedsince most completion pac%ers havesmall clearances with respect to thecasing I&. #unning tool fast may causethe pac%er elements to swab the well thatmay damage the elements.

3..1 PROCEDURE !OR INT$##IN& $COMP#ETION

The basic steps involved in the installation of completion system are:

3. #I+ down hole completion hoo%"up.5. #I+ ),))4 with control line

strapped to completion string. The),))4 must be function pressuretested prior to lowering.

7. Installation of tubing hanger pressure test.

8. 1ippling down B(>.9. Installation of C"mas tree andpressure test.

ac%er setting@. Activation. ,leaning3G. +anding over well to platform for

production

3.4 COMP#ETION O! ;ORI0ONT$# MU#TI#$TER$# "E##

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Well Completion

The hori*ontal multi lateral wells can beclassified under a special category of xtended #each &rilling ;#&0 wells. Thisclass of wells can be defined as wells with adeparture of twice or more of True 4ertical&epth ;T4&0 of the well i.e. a reach to T4&ratio of 5 or more. This definition separatesconventional directional wells from hori*ontaland multilateral wells that require specialconsiderations.

+ori*ontal well drilling and production havegained increasing importance in recent yearsdue to the potential increase in oil and gasproduction from hori*ontal and multilateralwells and comparatively high reduction indrilling and completion costs. &evelopments

in technologies to tac%le the problems of wellbore stability and formation damage havemade hori*ontal wells more attractive. Thethrust on hori*ontal and multilateral wells hasdiverse reasons such as productivity increase$production from low permeability formations$connecting vertical fissures$ staying awayfrom (', (, contacts$ producing thinreservoirs$ injecting steam$ increasinginjectivity$ increasing sweep efficiency$controlling sand$ producing gas from coalseams$ etc.

+ori*ontal wells are normally new wells drilledfrom the surface. &rain holes or laterals aregenerally drilled from existing well ;vertical or hori*ontal0 through re"entry drilling. &rainholes or laterals may be single or multipledrain holes ;multilateral0. In contrast to avertical well$ a hori*ontal well provides infiniteconductivity fluid path for the formation fluid.-ormations in which bottom and top gas caprenders fracturing difficult$ a hori*ontal welloffers an alternative to get high production

rates without gas and water coning problems.Thus$ in general$ hori*ontal wells are effectiveway of exploiting new as well as mature oilfields having thin formations$ naturallyfractured formations$ tight formations andformations with gas and water coningproblems.

;oriontal 7ell Co('letion

)election of completion method has asignificant influence on life of well$ its

performance and intervention requirement infuture. A completion option may loo%

expensive at the time of well completion but inthe long term it may be very cost effective.4arious factors such as potential of thereservoir$ reservoir characteristics$ geology$roc% and formation type$ nature of fluid to beproduced and exploitation strategy play veryimportant role in well completion.

Based on these considerations$ the followingfour types of completion options ;-igure 7.530are available for hori*ontal wells:


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Well Completion

In unconsolidated sandstone reservoirs$the prepac%6 gravel pac% liners are usedto provide some degree of sand incursioncontrol.

The major disadvantage of slotted liner

completion is that it still does not offer selective layer stimulation and controlsince no *onal isolation is used inbetween the layers.

!i)+re 3.21 >ario+s Co('letion O'tions *or ;oriontal 7ells


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Well Completion

!i)+re 3.22 ECP and lidin) leeve Co('letion

!i)+re 3.23 CasedF ce(ented 'er*orated liner co('letion

!ultilateral well technology involves drillingand production from various layers drilled

from a single slot or mother bore. It providescost reduction in terms of increasedproduction$ increased reserves for exploitationand slot conservation.

#eservoir characteristics and completionvariables such as sand or debris control$water production$ draw down requirement$lifting mechanism$ various completiondesigns and production control help indetermining the most appropriate multilateralsystem for any given reservoir.

M+ltilateral 7ell classi*ication:The difference between the variousmultilateral systems is basically a matter of the completion itself. The most simplemultilateral from a drilling standpoint is notmuch different from drilling of a very complexmultilateral. But the completion hard waresbetween the two systems will vary widely andthe ris% involved will also vary drastically.

#evel Classi*ication

3 O'en Uns+''orted +nction%are*oot (ain ore lateral or slotted liner h+no** in either ore

5 Main ore Cased Ce(entedF #ateral O'en#ateral either are*oot or 7ith slotted liner h+n)o** in o'en hole

7 Main ore Cased Ce(entedF #ateral Case+t Not Ce(ented#ateral liner anchored to (ain ore +t notce(ented at @+nction

8 Main ore #ateral Cased Ce(ented%oth ores ce(ented at the @+nction

9 Press+re Inte)rit9 at the +nction$chieved 7ith the co('letionF i.e. straddle'acersG


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Well Completion

#evel,1 (+ltilateral 7ell:

!i)+re 3.2/ Re'resentation o* M+ltilateral 7ell classi*ication


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Well Completion

Both evel"3 5 multilaterals have beencompleted in !umbai (ffshore.

#evel 3 7ell co('letions:

The next level of completion ;-igure 7.5


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Well Completion

3.8 "E## $CTI>$TION UIN& %$CJUR&E TOO#

4arious methods of well activation have beenused in development wells with mixed results.

Activation of highly deviated wells such as#& wells or hori*ontal wells poseschallenges that require special tools or innovative ideas to successfully activate or stimulate these wells.

)ome of the methods of activation in thesetypes of wells are:

3. !atrix acidi*ation job5. 1itrified !AJ7. Acid spotting with ,T?

8. Acidi*ation through ,T?

+owever$ the results from the application of these techniques were not very encouraging.

#ecently$ many such wells have beenactivated through use of Bac% surge tool;-igure 7.5reciselyrated shear screws are used to set the tool toactivate at a predetermined draw downpressure starting from 9GG psi to 8GGG psi.

Activation of the tool is achieved in a numberof ways:

Bleeding off above the tool ,irculating out well contents to

nitrogen above the tool >re"pressuri*ing the formation and

bleeding off above the tool.

-igure 7.5


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Well Completion

connected to a converted )emi submersibledrilling rig to produce ?/Ds first offshore oil in3=9. +owever$ the main growth of sub seaproduction technology began in 3@Gs in1orth )ea and offshore Bra*il. In the ?)A$despite the early pioneering wor%$ there waslittle sub sea activity until discovery of deepwater reserves in 'ulf of !exico$ whichhas prompted a surge of development over the past < years. #ecent advances in diver"less technologies have further boosted theapplication of sub sea completion systems.

+ ea >s +r*ace Co('letion

'enerally spea%ing$ surface completion arecheaper to manufacture$ easier to install andfar less troublesome to maintain than sub

sea systems and hence the decision to optfor sub sea development is generally ta%enwhen other context specific criteria ma%e itdemonstrably superior in terms of overallcost effectiveness. )uch criteria includewater depth$ prevailing climate andenvironmental conditions$ well numbers$reservoir si*e and reserve distribution$ wellmaintenance requirement etc.

,onditions that particularly favour theadoption of sub sea completion technology

are: &eepwater fields

)mall 6 !arginal field or fields with

scattered reserve distribution +arsh nvironmental conditions

-ast trac% development projects

>hased development 2designed to

achieve early production that can thenbe augmented by latter stages of development

In some situation sub sea developmentslin%ed to -loating >roduction )ystem ;->)0or tied bac% to existing platforms provide themost cost effective development option.

(ne of the fundamental aspects of fielddevelopment$ including deepwater development$ is whether to have an abovesurface wellhead or sub ea. In deep waters$the choice is limited due to the water depths$the availability of appropriate technology andextreme cost limitations for opting a surface

tree.

A sub sea well completion has proved itsreliability in service and cost and hence thenumbers of sub sea completions haveincreased over the years especially for development of deep"water fields where subsea completion presents one of the low costdevelopment solutions in deep water. Thereare$ however$ several %ey elements thatneed to be in place in order to find an optimalsub sea solution. The sub sea wellhead mayalso be designed to accommodate a tiebac%to a surface facility on a T>$ )>A# or afixed platform. A well ,luster or integratedmanifold is selected where a particular fieldis extensively used.

An integrated manifold consists of wells

drilled through a template structure andconnected directly to flow lines andassociated controls as an integral part of themanifold. This method depends on thenumber of wells that can be drilled fromsame seabed position.

The ,luster concept permits drilling andcompletion independent of the manifold.This allows for a smaller manifold structure$is cost effective and can be made retrievablethrough a drilling rig moon pool. This results

in a reduced installation cost and providesmore installation options. >iling and levelingof the manifold are less stringent due to thesi*e and overall loading$ although soilparameters can be the governing factor. Incase the deepwater production wells arescattered over a wide area and wellmaintenance is relatively low then sub seasystems involving seabed completion areselected.

3..2 DI!!ERENT $#TERN$TI>E O!U% E$ COMP#ETION $ND#$YOUT

Three main alternatives can be thought of for sub sea completion layout strategy:

• Individual satellite wells• ,luster development

SSP 3.23


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Well Completion

• Integrated templates6manifold

3..2.1 INDI>IDU$# $TE##ITE "E##

)atellite wells comprise of individual wells

with separate control umbilical and flow linefor each well lin%ing production bac% tofloater or platform.

In the past$ the sub sea connection andmaintenance wor% was carried out by diversand therefore these systems were depthlimited. Also the cost of individual flow linesand umbilical was prohibitively expensive incase of long distances.

+owever$ with technological advances inproduction hardware and development of remotely operated vehicles ;#(40$ thesatellite concept has become a practical andeffective development strategy for deepwater prospects and has been adoptedin many current projects.

A simpler approach of )ub sea completionsystem involves a simple manifold to gather production from a cluster of individualsatellite wells ;-igure 7.5=0 typicallyseparated by 7Gm and connected by shortflow lines. !ost of the 'ulf of !exico&eepwater developments are based on thisconcept. >roduction can be co"mingled for transmission to the host platform$minimi*ing flow line costs. )ome of thedisadvantages of cluster developments arethe costs associated with flow line andumbilical jumpers and the need for acentrali*ed location$ which in turn$necessitates extended reach drillingrequirements.

-igure 7.5= )atellite )ub )ea ells

3..2.2 C#UTER "E##

!i)+re 3.2 Cl+ster 7ells

3..2.3 INTE&R$TED TEMP#$TE M$NI!O#D

Integrated template 6!anifolds ;-igure 7.50are used to combine the flows from anumber of wells. A template can provide thebase for multiple wellheads$ manifold and

protective structure. In the early 3=Gsdesigns emerged for integrated sub seatemplate6manifold through which a do*en or more wells could be drilled and completedallowing the co"mingling of their production.

Typically$ in the case of a 35"welldevelopment$ instead of using individualflow lines and central lines for each well$only 9 lines will be required in the case of integrated template lay out " two productionflow lines$ one injection flow line ;if

applicable0 and perhaps a test flow line anda single electrical6hydraulic control umbilical.

SSP 3.24


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Well Completion

+owever$ in addition to increasedcomplexity and associated costs$ theintegrated template6 manifold has severalsignificant disadvantages such as its heavyweight which requires a dedicated crane

barge for its installation$ increased drillingcosts in terms of extended reach drillingfrom a central location$ need for preciseleveling at the sea bed etc. These factorscan offset the savings made in terms of flowlines and umbilicals.

!i)+re 3.2? Inte)rated Te('late

3..3 U% E$ YTEM JEYCOMPONENT

A sub sea system is a system that isspecially designed for a particular reservoir that is to be developed. hen comparingvarious sub sea systems$ it is safe to saythat all sub sea systems are different.)ome of the reasons for this are listedbelow:

• #eservoir conditions

• ater depths

• 'eographical ocation

• )eabed ,onditions

• xperience from >revious >rojects

• Technical Advances

• )pecific (il ,ompany #equirements

All sub sea systems consists of Kbuildingbloc%sK ;standard or purpose built subsystems0 that are assembled into a mainsub sea system. 1ot all sub sea systemsuse the same building bloc%s. This depends

on the system layout that is chosen to best

serve the overall objective " to maximiseprofits and minimise ris%s.

The main Kbuilding bloc%sK ;sub systems0that are used in most sub sea systemsinclude the following:

• )ub sea Trees

• !arine ellheads

• ,ontrol )ystems

• ,ontrol ?mbilicals

• -low line ,onnection )ystems and

>ipelines

• #iser )ystems

3..3.1 U% E$ =,M$ TREE

"E##;E$D

The sub sea tree consists of an assembly of valves that controls the flow of producedfluids. The valves are mostly controlledremotely ;open6close0. The sub sea treealso facilitates vertical access to theproduction bore to perform wellmaintenance and injection of chemicals toprevent hydrates$ corrosion and wax build"up.

T9'es o* + sea Trees

There are two types of sub sea tree designsin the mar%et today:

• >ertical Tree

The 4ertical Tree ;-igure 7.7G0 has valvesin the vertical production and annulusbores. It has its tubing hanger situatedbelow the tree " in the wellhead and henceis needed to be pulled out prior to pullingout the tubing hanger6tubing. The tree is

very tall and hence requires a completionriser.

• ;oriontal Tree

The +ori*ontal Tree 6)ide valve tree hasno valves in the verticalproduction6annulus bore. All the valves aremounted on the sides of the tree bloc%.The tubing hanger is landed in the treebloc%. The tree is short and does not needa completion riser. +owever$ part of the

subs ea well is drilled through the+ori*ontal Tree with the Blow (ut

SSP 3.25


26/31

Well Completion

>reventer ;B(>0 loc%ed at the top of the+ori*ontal Tree. The +ori*ontal Tree isused in wells in which the tubing stringhas be pulled out frequently since the treeis not required to be pulled out prior topulling the tubing hanger6tubing.

!i)+re 3.3B Ca(eron D+al %ore s+ sea Tree ertical tree-

!i)+re 3.31 ide >alve Tree !i)+re 3.32 Ca(eron 'ool Tree;+ori*ontal tree0

3..3.2 U% E$ M$NI!O#D

A sub sea manifold ;-igure 7.770 is used togather production from a cluster of individualsatellite wells typically separated by 7G"9Gm and connected by short flow lines and acluster line LjumpersD. !ost of the 'ulf of !exico &eepwater developments are basedon this concept. >roduction can be co"mingled for transmission to the hostplatform$ minimi*ing flow line costs.

Cl+ster (ani*oldThe cluster manifold concept is adoptedwhere wells are drilled within 9G m from themanifold and flexible or rigid jumpersconnect the wells to the manifold. Thecontrol umbilical jumpers are also usedbetween the cluster wells and the manifold.

The main advantage is that no infieldpipeline 6 control umbilical required.

atellite 7ells 7ith (ani*oldThe )atellite wells with manifold concept isadopted where wells are drilled more than3GG m to 5GG m away and the infield flowlines are required to connect manifold to thesub sea wells. The main advantage of thesatellite wells is that the wells can be drilledin sequence and the production cancommence from the drilled wells if the other

facilities are available for commissioning.

Te('late (ani*oldThe manifold with well template is adoptedwhere wells are drilled using the manifold asthe sub sea template and the ,hristmas treeis integrated within the sub sea manifold.The main advantage is that the drillingvessel can be stationed in one placethroughout the drilling period for all the wellswithin the template.

3..3.3 RIER

#isers carry either hydrocarbon fromseabed to surface or injection fluid from thesurface to the seabed. At the foot of theriser$ it is joined to the seabed pipelineeither through a simple elbow or by a morecomplex geometrical configuration thatincludes a dogleg or a loop to ta%e up thepipelineDs thermal expansion.

In shallow waters$ risers can be installed bya straightforward Mstal%ing onE procedure

where a riser is bolted on to a platform usingpreviously installed clamps. In greater

SSP

!i)+re 3.33 + ea (ani*old

3.26


27/31

Well Completion

water depths$ the riser is installed with theplatform and joined to the pipeline through aspool piece 2 a short section of pipe thatmay in some situation be flexible.

,aisson risers are used when several risers

are bundled together in a large diameter pipe. The internal pipes carry thetemperature and pressure loads and theexternal pipe carries the external waveloads. In some instances$ these areinsulated.

-or deepwater developments with floatingproduction systems$ there are four maintypes of riser systems:

• Top tension vertical risers that are

supported from surface• )teel catenary risers that will attempt to

assume the shape of a catenary despitethe effects of bending stiffness andelasticity.

• +ybrid risers 2 a combination of vertical

bundled pipes supported by buoyancy ata certain water depth below the surface.

• -lexible pipes connecting top of the

vertical bundle to the floating hostfacility.

3..3./ U% E$ PIPE#INE

The various types of pipelines that are usedconsist of:

Ri)id 'i'elines

#igid pipe has been used extensively in allareas of the world in shallow and deepwater applications to fabricate flow lines and jumpers. 4arious materials$ most commonlycarbon steel and duplex stainless steel$

have been used to manufacture the pipe.

The main advantages in using rigid pipe$ asopposed to flexible pipelines$ are the lower material cost per metre for correspondingsi*es$ and the ability to be able to assemblethe flow line offshore in long lengths ;lengthof flexible that can be manufactured andtransported in a single section is limited0 asit is laid.

The main disadvantages are related to the

problems of installing rigid flow lines$especially on deepwater developments$ due

to the stress imposed on the pipe as it isover boarded from the lay vessel. Inaddition$ there is generally a need for amore comprehensive survey of the seabedroute to be underta%en$ and for pre" andpost"lay preparation of the seabed.

%+ndled s9ste(

The bundled system ;-igure 7.780 allows anumber of flow lines and umbilicals to bemounted and contained within a single steelcarrier pipe. Bundles are normallyconstructed onshore in sections$ which arethen joined and towed out to sea for transitto the field and final installation.

The main advantages of this arrangement

are: It allows simultaneous installation

of a number of lines6 services. It is also possible to incorporate a

sub sea manifold in to the bundleassembly in the form of a towhead.This would be attached directly tothe end of the bundle and would beinstalled with the bundle.

There is no need to employ

specialised lay vessel. -low line diameter can be increased

with no effect on installation cost. ?se of such bundles is particularly

appropriate when the seabed is verycongested or when well streams areprone to hydrates and waxdeposition$ since the bundleconfiguration allows the lines to beheated relatively cheaply comparedto non"bundled alternative.

The thermal insulation properties of

bundles ma%e them attractive

propositions for deepwater developments. If necessary$ hotheating pipes can be built intobundles. As case in point is Total-inalfDs landmar% 'irassol projectoff Angola in & 3$7GGm$ whichfeatures flow line bundles. )ub seatemperatures at the 'irassol site arearound 8G , and the temperature of the crude is relatively low$ meaningthat heat loss from the flow linesmust be %ept below 3G , per %m.

SSP 3.27


28/31

Well Completion

!i)+re 3.3/ %+ndle s9ste(

!leAile *lo7 lines

-lexible pipe has been used extensively insub sea applications and has been provenin water depths up to approximately


29/31

Well Completion

!i)+re 3.3 Control s9ste(s

The control of various production functions$executed at the seabed$ is carried out froma topside production facility ;a platform or afloating vessel0. A satisfactory response timefor a control system is an important factor that may have a dramatic effect on reliabilityand safety of environmentally criticaloperations.

As communication distance betweentopside production facilities and sub seainstallations increases$ due both to multiplewell developments and water depth$ earlymethods of well control using directhydraulic control of sub sea valves havebecome less feasible due to operationallimitations of such controls and due to boththe si*e and cost of the multi"core umbilicalsrequired to provide hydraulic power transmission. This has led to thedevelopment of more advanced and

complex control methods using pilotedhydraulic systems$ sequential pilotedsystems and electro"hydraulic systems;hard"wired and multiplexed0. Thecomplexity and performance characteristicsof sub sea control systems depend on thetype of control used.

Topside control system equipmentcomprises of a hydraulic power unit ;+>?0$an electronic power unit ;>?0 and a well

control panel. The +>? provides high andlow"pressure hydraulic supplies and is

usually powered by electric motors$although redundancy is sometimes providedby air drives. The +>? includes tan%s$pumps$ a contamination control system andhydraulic control valves. mergencyshutdown facilities are provided to bleed off hydraulic fluid and thus to close sub sea fail"safe valves. The hydraulic components arefairly standard.

3..3.4 CONTRO# UM%#IC$#

An umbilical ;-igure 7.7


30/31

Well Completion

!i)+re 3.34 Control +(ilical reel

3../ MODE O! INTER>ENTION

MInterventionE describes a corrective or

preventative action for the purpose of detecting damage location assessment andminor or major repair. The methods used for accessing a sub sea system are:

&ivers

#emotely operated vessels

!anned submersibles

&epth constraints are a %ey factor in definingthe specific capabilities and limitations of intervention techniques. The general depthconstraints for various intervention techniquesare:

• )aturation diving 239GG feet.

• (ne 2 atmospheric diving suit 2

57GG feet

• !anned submersible 25


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Well Completion

The limitations and capabilities of mannedsubmersibles are generally similar to those of #(4s. +owever$ depth limitations for mannedsubmersibles on a whole are less than thosefor #(4s.

(ne beneficial aspect of mannedsubmersibles is the lac% of reliance oncameras to record sub sea operations. Thepresence of the vehicle operator next to theintended tas% may simplify the resolution of any complications that may arise.

03 well completion

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