centralizer review

8/18/2019 Centralizer Review

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Centralizers: A Review

Date:

Apri l 17, 2014

To:

Lauren Boyd and Greg Stillman

United States Department o !nergy

"rom:

#iann Su

Sandia $ational La%oratories


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IntroductionWell completions are an integral part of providing safe, reliable and continuous

access to underground resources such as oil, gas and geothermal resources.

Completions are typically considered to be the nal step of drilling engineeringwhich includes processes such as setting casing, cementing, and perforating to

reach the target formation !". Completions provide the conduit from the resource

to the surface. Although completions encompass a wide range of disciplines,

several #ey factors ultimately determine the $uality of the completion. %ne of those

is cementing and centralizing casing within the wellbore.

Centralizers provide the restoring force to #eep casing centered in a wellbore. &his

centralization provides a uniform space between the casing and wellbore to

promote good cementing, and thus isolating 'uids from di(erent zones in a

formation.

&his white paper e)amines the current state of the art for centralizers in the conte)t

of well completions. &he paper will include an introductory primer on well

completions to provide the framewor# for the centralizer discussions. &he types of

centralizers currently available and how they are used will be discussed in addition

to alternative centralizer techni$ues.

Well Completions

What are well completions?

Well completion is the process of ma#ing a well ready for production or in*ection +".t is a multi-discipline systems engineering tas# involving geology, drilling,

cementing, and production. &he goal of the completion is to provide a safe and

ecient conduit from the formation to the surface. A good well completion must

minimize formation damage, maintain good communication between the reservoir

and wellbore, and ma)imize reservoir productivity !". A completion design re$uires

not only sound science and engineering, but also practical hands-on wellsite

e)perience. A balance of theoretical and practical tends to produce the best results

/".

Well design and completion typically depends on regulatory as well as economic

issues. Completions are often divided between reservoir completion and production

completion. &he reservoir completion is relates to the connection between the

reservoir and the well. &he production completion is the conduit from reservoir to

the surface.

0ey considerations for reservoir completion include the following /":

- Well tra*ectory and inclination


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- %pen hole vs. cased hole- 1and control re$uirement and type of sand control- 1timulation re$uirements- 1ingle or multi-zone- 2roducing or in*ecting well

n the production completion, #ey factors include

- 2roduction thru casing or tubing- Articial lift and type- Anticipated production rate- 3luid produced or in*ected- Anticipated corrosion resistance- &hermal cycling- 1ingle or multiple completion- 4)pected di(erential pressures

Types of reservoir completions &he type of completion chosen depends on reservoir characteristics and production

re$uirements. &here are two basic types of completions: open-hole and cased-hole.

Open-hole completion

An open-hole completion is the most basic type of well completion. t encompasses

several techni$ues with the commonality being casing does not cross the reservoir.

Although it is the simplest type of completion, it is typically reserved for competent

formations capable of withstanding production conditions. &his is more li#ely to

occur in geothermal drilling than oil 5 gas. %pen-hole completions can be

performed in both vertical and horizontal wells.

n open-hole completions, the well is drilled to the top of the formation. Casing is

then run to the formation without crossing the reservoir 63igure !7. 2roduced 'uids

are allowed to 'ow directly into the wellbore. Without a liner, this type of

completion is also #nown as a barefoot completion.


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Figure 1. arefoot open-hole completion illustration

&he barefoot techni$ue does have some limitations. 8onal isolation during

production or in*ection operations is more challenging and reservoir and fracturing

stimulation options are limited to the use of open-hole pac#ers 6sometimes not

feasible7 or possibly diverter based technologies. Additionally, controlling 'ow of

'uids from the formation can be dicult.

Another type of open-hole completion is a liner completion 63igure +7. t is used in

deep well completions where formation collapse is an issue. A liner is a string of

casing that does not reach the surface. t is hung from a previously installed casing

string using a liner hanger. 9tilizing pre-drilled or slotted liners in the formation,

this completion techni$ue provides additional formation control in the production

zone. &he liner can be used in con*unction with e)ternal casing pac#ers to provide

zonal isolation. &he liner also provides support to prevent formation collapse and

allows zonal isolation pac#ers to be deployed. enerally, pre-drilled liners are

preferred over pre-slotted liners because of the larger in'ow area and higher

strength /". &he use of slotted liners is common in geothermal completions.


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Figure !. "lotted liner completion

Cased-hole completion

Cased-hole completion di(ers from open-hole completions in that casing is run

through the production zone and cemented in place. &he casing is selectively

perforated using a perforator 6commonly an e)plosive shaped charge7 to connect

the formation to the casing 63igure /7. &he perforator penetrates the production

casing and the cement sheath and creates a channel to allow the reservoir toproduce into the well !".

&his type of completion provides advantages in zonal isolation. A fully cemented

production zone allows more homogeneous 'ow of 'uids along the wellbore ;". t

also permits selected shuto( of unwanted 'ow. t is also useful for selective

hydraulic fracturing and acidizing.


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Figure #. $erforated casing completion

&he most obvious drawbac# to perforated casing completion is the increased costs

associated with running casing to the production zone. &his can be signicant when

wor#ing in high angles or long intervals. A drawbac# when wor#ing with

hydrothermal systems is that cementing across production zones is dicult and

would cut o( the desired wor#ing 'uid. Additionally, the high 'ow rates re$uired in

those systems are susceptible to 'ow restrictions from the perforations.

A variation on the casing perforation is liner perforation. n this method, a liner is

hung from the intermediate casing and then cemented and perforated. 2erforated

liner completion ta#es advantage of the seal created by the intermediate casing.

&he overall weight of the casing string and volume of cement can be reduced, thus

decreasing completion cost. &his is a common completion techni$ue for medium or

low pressure deep oil and gas wells !".

n both techni$ues, perforations are performed using shaped charges 63igure ;7.

&he charge creates a high pressure focused *et that penetrates the casing. &he

shaped charges are arranged inside a perforation gun to create a desired pattern. &he pressure pulse deforms the casing and crushes the cement and formation.

2ressures generated by the pulse can reach !< million psi /". =ebris generated in

the vicinity of the charge must be removed afterwards.


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Figure %. "haped charge

Ta&le 1. Completion service condtions 'adapted from (1)*

Completion +ode "ervice Conditions for ,se

Open hole

'&arefoot*

- Competent roc# reservoir- %il 5 gas reservoir without gas cap, bottom water,

water-bearing interbed- 1ingle thic# reservoir or mutli-zone layer with

similar pressure and lithology- >o zonal isolation re$uired

Open hole 'liner* - %il and gas reservoir without gas cap, bottom water- 1ingle thic# reservoir or multi-zone reservoir with

same pressure and lithology

- 8onal isolation not re$uired- 9nconsolidated medium and coarse grain sand

reservoir

Cased-hole - 8onal isolation re$uired due to complicated

geological conditions- ?ow-permeability reservoir that re$uires hydraulic

fracturing- 1andstone reservoir and fractured reservoir

Casing

Casing provides the controlled 'ow path from the production zone to the surface

and is a #ey component in completions. t protects the wellbore from the

surrounding environment and the surrounding environment from produced 'uids

and prevents the formation from collapsing.

Well casing is comprised of a metal tubes installed in drilled holes. &here are ve

types of casing based on function.


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Conductor casing

&he conductor string acts as a guide for the remaining casing in the hole. t is the

rst string cemented to the top and tted with casing head and blowout prevention

e$uipment. t is shallow, typically between +@-


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&he depth of each section is determined based on having the borehole pressure

being greater than the pore pressure but less than the fracture pressure F" or to

case a section of the well that is #nown a priori to be problematic. 3rom there, the

casing and hole sizes are determined. Dit sizes are chosen to provide between +.@in

to ;.@in between the casing and the wellbore to allow for good cementing. >ewer

regulations re$uire +.@in of cement on all sides and are becoming standard in mostareas.

Casing designations

Casing is classied according to the way it is manufactured, the grade of steel used,

dimensions, and type of coupling. A2 1pec early all metal used in completions is some form of steel with occasional niche

application of titanium which is immune to corrosion and resistant to hydrogenembrittlement in geothermal brines /". ?ow alloy steels are the starting point for

material selection. Completion components typically use the American ron and

1teel nstitute 6A17 four-digit system for classifying low-alloy steels. &he 9nied

>umbering 1ystem 69>17 system is also commonly used.

Alloy steels 6metal concentration other than iron I


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of casing materials. 4lements such chromium help to improve corrosion resistance.

>ic#el improves toughness as well as corrosion resistance. &able / lists common

alloying elements and their e(ect on the bul# properties of the material.

Ta&le #. /lloying elements for steel (#)

/lloying 0lement $urposeChromium mprove corrosion resistance

>ic#el mprove toughness, useful in presence of K1

olybdenum ncrease high-temperature strength, resistance to

pitting

anganese ncreases hardenability

&itanium 1trengthen steel

A commonly used alloy recognized by A2 is ?G@ !/Cr. t is similar to ?G@ carbon

steel but with !/B chromium. ?G@ !/Cr is common in many o(shore wells and

geothermal. >ic#el alloys are used for high-strength high corrosion resistantapplications.

Coatings and liners can be used where the cost of corrosion resistant materials is

beyond reach. &he liner can be used with relatively ine)pensive steel to produce

the desired results.

Cementing

2rimary cementing 6cementing the casing and the liner7 is the most important

operation in the development of a well F". Cementing is usually performed as a

part of drilling with specialty contractor support. Cementing materials vary from

basic 2ortland to sophisticated specially formulated synthetic or late) cements. &hecement slurry is pumped to specic locations in the well. n geothermal, casing and

liners are normally cemented to the surface. When cured, the cement slurry

provides a bond between casing and the wellbore that controls the 'ow of 'uids in

and around the wellbore.

n addition to providing structural support to casing, primary cementing also isolates

porous formations from the production zone, prevents unwanted sub-surface 'uids

from entering the producing interval, protects casing from corrosion, and connes

abnormal formation pressures.

Cementing has a specic purpose for each of the strings described in the previoussection. 3or conductor casing, cement prevents drilling 'uid from circulating

outside the casing. 1urface casing is cemented to protect freshwater formations

near the surface and provide a structural connection between the casing and

formation. n intermediate casing string, cement seals o( abnormal pressure

formations. 2roduction casing is cemented to prevent the mi)ing of produced and

non-produced 'uids.


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Cements are divided into nine classes by the American 2etroleum nstitute 6A27.

&he classes describe the intended application for each of the cement types.

Ta&le %. /$I cement classes (1 2)

Clas

s

3epth ange $roperties

/ 1urface to E,@@@

ft

no special properties re$uired

1urface to E,@@@

ft

moderate to high sulfate resistance

C 1urface to E,@@@

ft

high early strength re$uired and high sulfate resistance

3 E,@@@ ft L !@,@@@

ft

moderately high temperatures and pressures. Available

in both moderate and high sulfate resistance

0 !@,@@@ ft L

!;,@@@ ft

high temperatures and pressures.

F !@,@@@ ft L

!E,@@@ ft

e)tremely high temperatures and pressures. Available

in both moderate and high-sulfate resistance

4 1urface to G,@@@

ft

can be used with accelerators and retarders for wide

range of depths and temperatures. Available moderate

and high-sulfate resistance. Dasic oil well cement

5 1urface to G,@@@

ft

can be used with accelerators and retarders for wide

range of depths and temperatures. Available moderate

and high-sulfate resistance. Dasic oil well cement 6 !+,@@@ ft L

!E,@@@ ft

4)tremely high temperatures and pressures. Can be

used with accelerators and retarders.

n oil and gas, one of the crucial characteristics of any well cement is sulfate

resistance. 1ulfate is abundant in underground formation li$uids that can contact

the set cement. &he chemical reaction between the sulfate and cement can corrode

the set cement causing e)pansion resulting in cement disintegration. &he relative

increase in sulfate resistance indicated in &able ; indicates decreasing amounts of

tricalcium aluminate. n geothermal, acid and C%+ resistance are of primary

importance. Calcium aluminate phosphate 6Ca27 and sodium silicate-activated slag

611A17 cement have been shown to have good performance against C%+ attac# E".

n high-temperature environments such as geothermal wells, the principal binder in2ortland cement begins to lose strength M". &his occurs at temperatures e)ceeding

+/@N3. &hese limitations are addressed by using silica-lime cement which is more

stable at high temperatures !@". &he silica added to the cement helps to stabilize

it at high temperatures. n a silica-lime hydrothermal cement, calcium hydro)ide


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and silica are the only reactants. &his type of hydrothermal cement re$uires less

retardant and ta#es advantage of well temperatures 6I!M@N37 to set.

&he slurry and set cement should meet basic re$uirements for ensuring safety and

$uality of the cement *ob. Additional properties to consider include density,

thic#ening time, set strength.

&he density or specic weight is one of the most important properties of cement

slurry F". Cement slurry density should be higher than the density of the drilling

'uid but not high enough to induce fracturing in the wellbore. &he specic weight is

dened by the amount of water used with the dry cement. &he range of specic

weights is limited by the minimum and ma)imum standards set by A2. Kowever,

typical density that provides good 'owability and set strength is around !E lbHgal

!".

&he thic#ening time of the cement slurry must be #nown before prior to being used.

t is dened as the time re$uired to reach !@@ Dearden

!

units of consistency. F@Dearden units is typically considered the ma)imum pumpable viscosity F". f the

thic#ening time is e)ceeded, there is the ris# of damaging e$uipment and not lling

the annulus. &hic#ening time can be controlled with additives that will retard the

chemical reaction and e)tend the thic#ening time.

&he compressive set strength of cement indicates how much load the cement can

withstand before rupturing. A compressive set strength of


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Figure 7. Casing shoe illustration (11)

Above the guide shoe, the 'oat collar acts as a 'ow-control valve to prevent heavier

cement slurry from entering the casing from the annulus. &he 'oat shoe and 'oat

collar are run on a single string to provide chec# valve redundancy. &he 'oat collar

is part of a 'oat *oint. &he *oint is usually left full of cement to insure an ade$uate

supply of cement to the bottom outside of the casing. t provides a margin of safety

against casing volume calculation errors when estimating cement volumes.

n geothermal, it is common practice to cement to surface, so additional cement

volume is added for the inter-casing annulus and one watches for cement to return

to surface. ost geothermal regulations have special provisions for casing not

cemented to surface, and these provisions can be very e)pensive to implement. A

top *ob may be re$uired as the cement level nearly always falls as the cement

cures. n a top *ob cement is placed from the surface via a tremie pipe to ll the

annulus to the surface or very near the surface.

Centralizers are used to position the casing uniformly within the wellbore. &hey

help to insure the casing is centralized in the wellbore to allow a more uniform

distribution of cement slurry around the casing. Recommended positioning of thecentralizers is described in A2 R2 !@=-+. 3urther discussion about centralizers is

provided in the ne)t section.

&he casing string is lowered into the hole until the shoe is a few feet o( the bottom

of the hole. As it is lowered into the wellbore, the drilling mud is displaced and

stored in the mud tan#s, while an annulus of drilling mud remains in the wellbore.

&he casing string remains hanging throughout the cementing operation. &his allows


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the string to reciprocate and rotate to assist in securing a proper bond from the

casing to the formation.

After the casing string is lowered into position, a cementing head is made up to the

upper end of the string. &he cementing head contains two wiper plugs that are

essential to the cementing process 63igure E7. &he top wiper is solid and designedto build pressure in the casing. t maintains separation between the displacement

'uid and the cement slurry. &he bottom plug separates the drilling mud from the

cement slurry and has a rupture dis# that allows spacer and cement slurry to 'ow

into the annulus after a set pressure has been reached 6+@@-;@@ psi7.

Figure 8. Cement plugs (11)

nitially, both plugs are held in place with retaining pins in the cementing head

63igure Fa7. &he bottom pin is released when the spacer+ and cement slurry are

ready to be pumped into the casing 63igure Fb7. When all of the cement has been

pumped, the top wiper is released and a displacing 'uid 6often drilling mud7 is

pumped behind it 63igure Fc7. When the bottom plug reaches the 'oat collar, the

increase in pressure eventually causes the rupture dis# to burst. After the rupture

dis# bursts, the spacer 'ows into the annulus between the casing and the wellbore

and displaces the remaining drilling mud 63igure Fd7. Additional pumping drives theslurry cement into the annulus until the top plug reaches the bottom plug 63igure

Fe7. At this point, pressure in the pumps begins to build until a desired set point.

&he casing is then pressure tested 6from the outside to the inside7 to chec# for

lea#s.

+ 1pacer 'uid separates the drilling mud from the cement slurry. &he spacer

removes drilling mud ahead of the cement


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Figure 2. "ingle-stage cementing steps (1!)

&he displacement 'uid is usually lighter than the cement slurry. &his creates a

pressure imbalance and results in the casing being under compression while the

cement sets. &his preload allows the cement-casing interface to always be loaded

to improve the bond between the surfaces.

Reverse circulation cementing

n conventional %5 cementing operations, cement is typically not run bac# to the

surface. %nly a portion of the casing is cemented in place. Kowever, in geothermal

where high thermal stresses re$uire uniform cement over the full length of casing,

cement is run all the way bac# to the surface.

9sing conventional cementing techni$ues, this creates uni$ue challenges. &he high

pump pressures re$uired to pump cement bac# to the surface create high downhole

pressures. &his can lead to lost circulation where the cement is pumped into the

formation rather than bac# up the annulus. &he high pump pressures can also

O'oatP the string !/".


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M7. A mar#er along with the tail slurry is initially pumped into the annulus. ?ead

slurry is then pumped in to displace the tail slurry into the shoe. &he slurry

continues 'owing through the drill pipe until the mar#er is seen at the surface.

Figure ;. "ta&-through with marer to surface

1tab-&hrough ?ead to 1urface

n this variety of stab-through reverse circulation, lead cement is pumped down the

annulus and displaced up the drill pipe 63igure !@7. When the lead cement is seen

at the surface, tail cement is pumped down the drill pipe, displacing the lead

cement at the shoe. ud or water is then pumped until only lead cement remainsin the annulus and the shoe.


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Figure 1o need to run stab-in

drill pipe in casing- Kighest pressure in

annulus after pumping

- &racer reliability- 1everal hundred feet

of cement to drill out- Casing shut in with

di(erential

hydrostatic pressure

at surface

"ta&-through

marer to surface

- Cement displacement

conrmed with returns tosurface

- inimize micro annulus

by controlling hydrostatic

di(erential downhole

- ncreased friction

from circulatingthrough drill pipe,

more pressure in

annulus

"ta&-through

lead to surface

- Conrmation of complete

ll with returns to surface- 2recise tail slurry

- Kigher 4C= than

other reverse

circulation


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positioning around shoe- ?ess cement to drill out

of casing- =ecrease in hydrostatic

pressure on annulus

techni$ues- Additional rig-up time

to pump tail cement

"ta&-throughfoamed cement

- ?ower hydrostaticpressure- 2ositive verication when

annulus is lled- 2recision placement of

tail slurry around shoe

- Kigher 4C= thanother reverse

circulation

techni$ues due to

friction in drill pipe

when circulating to

surface- Additional rig-up time

to pump tail cement- 9se of nitrogen

increases comple)ity

of setup

Centrali>ersA centralizer is a piece of hardware tted onto casing or liner to #eep it centered in

the borehole during cementing operations. &he $uality of a cement *ob is largely

dependent upon the centralization between casing and the wellbore. A centralized

casing allows cement to 'ow uniformly in the annulus as well as enabling ade$uate

mud removal. &he #ey to that is removing mud in the annulus between the casing

and borehole and replacing it with cement. =ue to di(erences in properties

between the mud and cement, there is a tendency for cement to leave behind mud

channels ;". &he stando( provided by centralizers is one of the most important

factors in preventing the mud poc#ets 63igure !+7.


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Figure 1!. Illustration of eect of poor stando on cement

ntroducing additional motion while running casing is another techni$ue used to

improve mud removal. Reciprocation, rotation, and the combination of both are

often used to aid casing downhole. Centralizers can act as rotational bearings to

help pipe rotation.

n open-hole sections, centralizers play an important role in preventing di(erential

stic#ing. 3igure !/ illustrates how centralized casing can help to eliminate

di(erential stic#ing. 3or centralized casing, the pressure e)erted on the casing by

the drilling mud is uniformly applied. &his means there is no net force beyond

gravity acting on the casing. f the casing is allowed to settle into the mud ca#e, the

contact area between the mud ca#e and casing can approach !H; of the total

surface area of the pipe ;". &his di(erential area results in a net side force driving

the casing into the mud ca#e. f this side force e)ceeds the force available to run

the casing, then the pipe becomes stuc#. Although there is additional running force

when centralizers are used, their use can prevent stuc# pipe scenarios.

Figure 1#. 3ierential sticing illustration

Although centralizers are typically anonymous hardware, they made headlines in

the =eepwater Korizon incident. &he number of centralizers used in the well was

the sub*ect of scrutiny during the investigation. &he original well plan called for +!

centralizers to be used for the completion. Kowever, various underlying conditions

resulted in only using si) centralizers and a nitrogen foam cement program.

According to an incident report Othe resulting cement program was of minimal

$uantity, left little margin for error, and was not tested ade$uately before or after

the cementing operation. 3urther, the integrity of the cement may have been

compromised by contamination, instability, and an inade$uate number of devices

used to center the casing in the wellbore.P !E"


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A case study published in !F" shows the e(ect of casing centralizers on a cement

*ob. A total of !EE centralizers were used in a !;,/!< ft. well. &he centralizers

allowed the operator to save time and cost by eliminating the e)pense of washing

and reaming or casing 'otation. n the study, two sub*ect wells were used for

comparison. Results from cement bond logs show that the rst well was centralized

on every *oint in the curve and lateral and the *oints from the #ic# o( point to thetop of the cement. &he second well was not centralized and showed several areas

of poor cement bond. &he centralized well showed an overall higher $uality cement

sheath. 3indings from the study resulted in operational changes to include more

centralizers and decrease the spacing.

Types of centrali>ersCentralizers are divided into two basic categories: bow-type and rigid 63igure !;7.

&he utility of each depends on the particular application. Dow springs have been

designed for traditional applications such as vertical or slightly deviated wells while

rigid centralizers are suited for horizontal and e)tended reach applications. &he

main purpose of each is to provide uniform spacing between casing or pipe and the

wellbore.

a. Dow-spring centralizer b. Rigid centralizerFigure 1%. asic centrali>ers (19)

Dow-spring centralizers are made from a set of 'e)ible springs attached to two

collars. &he 'e)ible bows generate a restoring force that creates separation

between the casing and wellbore. &he shape, size, and number of bows can varydepending on the particular application. 2erformance re$uirements such as starting

force, restoring force, and testing for bow-spring centralizers are dened in A2 1pec

!@= !M". 1ince the outer diameter of the bows is typically larger than the well

diameter, bow springs are suitable for use in washout areas.

Within the bow-spring category, there are both non-welded and welded centralizers.

&he non-welded type performs well under compressive loads and is used in


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standard applications where no rotation is re$uired or minimizing drag force is not a

consideration. &hese centralizers are not optimized for holeHpipe size combinations

so they tend to be less e)pensive than other types.

Welded bow-spring centralizers are optimized for specic pipe and hole size

combinations which result in lower drag forces. &he welded design provides betterperformance under tensile loads and allows rotation of the stringHcasing within the

centralizer. &he lower running force and higher restoring force ma#e this type of

centralizer a good choice when operating in washed out and highly inclined sections

+@".

&he di(erence in performance between welded and non-welded centralizers is due

to the way the bows are attached to the collars. n non-welded centralizers, the

bows are attached to the collars in a way that allows them to hinge. 3or welded

centralizers, the bows are welded to the collars providing more rigidity in the

centralizer.

Rigid centralizers are used when drag forces have to be minimized such as in long

horizontal or highly deviated wells. Rigid centralizers can be used in slimhole

environments, close tolerance drift diameters, and to help reduce friction in

e)tended reach laterals +!". Kelical blade designs help to enhance circulation and

hole cleaning. &ungsten carbide hardfacing or other friction reduction techni$ues

are also available ++". &hey are also used when the lateral forces e)ceed the

spring compressibility. ?i#e the bow-spring centralizers, there are two main sub-

categories for rigid centralizers. &hey are solid body and nned type.

1olid body rigid centralizers are made from a cast material, usually a metal alloy or

non-metallic composite 63igure !


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Figure 17. "olid &ody centrali>er with spiral @ns (!%)

Kollow n rigid centralizers 63igure !;b7 are the other type of rigid centralizer. &hey

consist of straight or spiral hollow steel ns welded to steel collars. &he shape of

the ns is designed to minimize drag forces while running pipe. &he ns also have a

pre-dened collapse load to yield under stuc#-pipe conditions. &he reduced drag

design also enables reciprocation as well as rotation while running pipe. &hey have

a larger 'ow-by area compared to solid body centralizers thus reducing circulating

pressures. Decause of these characteristics, they are well suited for use in highly

deviated or horizontal wells. &hey are used in con*unction with stop collars to

properly locate the centralizers on the casing.

&he balance between running force and restoring force is a #ey factor in selecting

the right centralizer. Commercial software is available to assist in modeling forces,displacements, a positioning. Kowever, if those tools are not available, &able E

provides some basic guidance for choosing centralizers.

Ta&le 8. "election criteria for centrali>er type '&ow or rigid* (%)

ow Type igid

>on-weld Welded 1olid Dody 3innedotating

liner

applications

>ot advisable 4)cellent ood 4)cellent

+inimi>e

drag force

>ot optimized 4)cellent ood 4)cellent

5igh &uild

rate

ood ood >ot advisable ood

$assing

restrictions

in well&ore

ood ood >o 2ass without

damage

5ydrodynami

cs

>ot optimized ood ood %ptimized


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$assing

casing

windows

9se caution ood 9se caution ood

4auge hole 4)cellent 4)cellent 4)cellent 4)cellent"lightly

oversi>e hole

4)cellent 4)cellent ood ood

Aarge

washout

section

4)cellent ood >ot advisable >ot advisable

,nder gauge

hole

ood ood >o >o

5ow do I use them?2ositioning centralizers in the correct place down hole is critical to their utility.

&echni$ues for establishing centralizer placement have been published in the

literature +


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1s 1tando( at the sag point

Figure 18. Calculation of casing stando in a well&ore

3or perfectly centered casing, the annular clearance la is given by

2

w p

a

D Dl

−=

!!Q 4R43%RA& 67

where D& is the wellbore diameter and D p is the casing outside diameter. &he

stando( at the centralizer is indicated by S' in 3igure !E. 3or a bow-spring

centralizer, the stando( is given by the load-de'ection curve of the centralizer

tested in a particular hole size and an applied lateral load. &his information is

typically provided in the centralizer specications. 3or a rigid centralizer, the

stando( is determined by

2

c p

c

D DS

−=

++Q 4R43%RA& 67

where D' is the outside diameter of the centralizer. &he stando( at the sag point 1s

is then given by

s cS S δ = − //Q 4R43%RA& 67

whereSs

is the stando( at the sag point andδ is the ma)imum de'ection of thecasing between the centralizers.

n practice, the minimum stando( may be located between the centralizers where δ

is the ma)imum or at the centralizers. &he stando( S of a section of casing is the

minimum of the stando( at the centralizers or the stando( at the sag point.

&he stando( ratio is then dened by 4$uation ;.

100 sa

S R

l = ×

;;Q 4R43%RA& 67

Changes in inclination angle or other factors such as tension in the casing have an

impact on stando( re$uirements and centralizer placement. &he de'ection of the

casing in the wellbore depends on these loading conditions. Dased on beam theory,

de'ections for common loading scenarios have been derived and captured in the

literature +


26/36

Aoading Condition +aBimum Casing 3e:ection

13 straight inclined

well&ore without aBial

tension

( ) 4sin

384

b cW l

E I

θ δ =

×

13 straight inclinedwell&ore with aBial

tension

( )4 24

cosh 1sin 24

384 2 sinh

b cW l

E I

µ µ θ µ δ

µ µ × − = − ÷ ÷ ÷×

2

4

t c F l

E I µ

×=

×

!3 well&ore ( )3 2

4

cosh 124

384 2 sinh

l c F l

E I

µ µ µ δ

µ µ

× − × = − ÷ ÷ ×

sin 2 sin2

l b c t F W l F β θ = × × + ×

6decreasing inclination7

sin 2 sin2

l b c t F W l F β

θ = × × − ×

6increasing inclination7

#3 well&ore ( )3 2

4

cosh 124

384 2 sinh

l c F l

E I

µ µ µ δ

µ µ

× − × = − ÷ ÷ ×

2 2, ,l l dp l p F F F = +

, cos 2 sin2

l dp b c n t F W l F β

γ = × × + ×

6decreasing inclination7

, cos 2 sin2

l dp b c n t F W l F β

γ = × × − ×

6increasing inclination7

( )

( )

1 2 1 2sin 2

cos sinsin 2 2

n

θ θ θ θ γ

β

− + = ÷

( )1 1 2 1 2 2 1cos [cos cos sin sin cosβ θ θ θ θ φ φ

−

= + −

, 0cos

l p b c F W l γ = × ×


27/36

=enitions for symbols in the above e$uations are given in &able G.

Ta&le 9. 3e@nitions for terms used in de:ection calculations

"ym&o

l

3e@nition

a)imum de'ection of casing betweencentralizers

W& Duoyed weight of casing per unit length

θ

Wellbore inclination angle

lc =istance between centralizers

0 odulus of elasticity of casing

I Area moment of inertia of casingFt 4(ective tension below centralizer

θ

Average wellbore inclination between two

centralizers

r Radius of curvature of wellbore path

&otal angle change between centralizers

γn Angle between gravity vector and principal

normal of wellbore

γ< Angle between gravity vector and binormal of

wellbore

φ

Azimuth angle

Fldp &otal lateral load in the dogleg plane

Flp &otal lateral load perpendicular to dogleg plane

&he recommended spacing between centralizers is determined by solving for l' in

the above e$uations.

2ositioning centralizers on the casing or pipe is done with stop collars or upset

features integrated into the bo) end of casing. 1top collars are typically held in

place using set screws or loc#ing pins 63igure !F7. 1ome are held in place with

resins or other adhesives while others use screws, nails, or mechanical dogs +F".

&hey can be independent of the centralizers or integrated into the centralizers.

According to A2 R2 !@=-+, the stop collar or holding device Oshall be capable of

preventing slippage.P &o accomplish this, the holding force of the stop collar shall

be greater than the starting force of the centralizer with additional margin built in

for varying well conditions.


28/36

Kinged collar with cross-bolt 1et screw stop collar Figure 12. "top collar illustrations (!9)

n addition to centralizer spacing, installation patterns should also be considered.

Weatherford +;" provides guidelines for patterns suitable for various conditions

3igure !G. 3or optimal centering in Case , centralizers should be installed over stopcollars. &his type of installation can be performed prior to running the casing and

minimizes lost time. t is not recommended for close tolerance situations. Case is

well suited for centering in close-tolerance patterns. &his pattern can also be

installed prior to running the casing. n Case , the centralizer is installed between

a stop collar and casing coupling. &his allows the centralizer limited travel and

re$uires only one stop collar per centralizer. Case S places centralizers over casing

couplings and reduces annular 'ow area. &his arrangement is typically avoided.

Case :

%ver stop collars

Case :

Detween stop

Case :

Detween couplings

Case S:

%ver couplings


29/36

collars and stop collarsFigure 19. ecommended installation patterns (!%)

Why wouldnt I use centrali>ers? &he importance of using centralizers in achieving good cementing results is well

#nown, however, they are often used with less than optimum placement due to

fears of the inability to the casing point. ;". Dow spring centralizers have wor#ed

well in traditional low angle and vertical wells, but e)tended reach and horizontal

wells re$uire more specialized centralizers.

&he 'e)ible bows create a restoring force that creates separation between the

casing and wellbore. &he restoring force, however creates a friction force between

the casing and the wall. &his running force adds considerable drag and can prevent

running casing to the desired casing point.

Korizontal and e)tended reach wells present increased challenges to getting casing

to bottom compared to vertical wells. Casing in high angle sections will have to be

pushed into the hole rather than allowing them to slide down with gravity. &he need

to push the casing through the hole can lead to buc#ling of the casing as it is run.

3or casing to slide down the hole, the a)ial force must be greater than the drag

force. f the a)ial compressive forces are large enough, sinusoidal buc#ling in the

casing can occur. Deyond sinusoidal buc#ling, helical buc#ling can also become a

concern. n helical buc#ling, additional side forces can be signicant !F".

Additionally, there are #nown cases of centralizers being damaged or destroyed

while running casing. A eld study by +M" showed that centralizers are susceptible

to damage while being run, especially as they e)it casing. &hey discovered several

failures of centralizers run on liners in the transition from intermediate casing to thehorizontal lateral. 1everal types of rigid centralizers were tested in the lab to

determine the failure mechanisms. &hey concluded that a variety of factors can

a(ect centralizer performance including the blade shape and the diameter relative

to the opening.

/lternative centrali>ersA case study of a downhole-activated centralizer 6=AC7 was presented by /@". &he

centralizer was designed for use in highly inclined wells and other restrictions such

as close tolerance wellheads. t was designed to be activated with e)ternal

hydraulic pressure, temperature, or by chemical reaction. &he activated

centralizers were tested in two o(shore wells near taly.

&he =AC was designed to allow optimum stando( in applications where

conventional centralizers reach their limits. &he centralizer has a low running force

and is activated downhole once the casing is in place. &he =AC is based upon a

conventional non-weld bow centralizer. &he bows are held down in the running

position with a steel band. A loc# is used to hold the band in place until the

mechanism is activated.


30/36

&he downhole activated centralizers were tested in two development wells.

Centralizer spacing was computed based on A2 !@=-+. 3ield tests showed the

e(ectiveness of downhole activated centralizers. &he measured hoo# load was in

line with predicted hoo# load indicating the centralizers deployed as predicted. &he

drag forces were reduced, but the restoring force was still limited by the bow-spring

design.

Figure 1;. 3ownhole activated centrali>er (#


31/36

Figure !er with @ns (#1)

3esigning a etter WheelCentralizers fall into two basic categories: 'e)ible and rigid. 3rom a positioning

capability perspective, they are either )ed force or )ed displacement devices.

&hese passive devices have inherent deployment limitations. %ftentimes

centralizers are omitted for fear of causing issues reaching the casing point. A 'at

pac# centralizer that could produce a variable displacement when needed would

help to eliminate some of the issues associated with current centralizing techni$ues.

An alternative to the current selection of centralizers would be capable of producing

controlled forces and displacements comparable to the bow spring with little or no

installation drag. &he new centralizer would leverage e)isting techni$ues and

technologies for deployment mechanisms in a limited space and generate large

forcesHdisplacements. &he active centralizer will be able to operate in situations

where the bow spring and rigid centralizer would not be deployed.

3or bow spring centralizers, the drag force is directly proportional to the centralizing

force. f the centralizer can be deployed in a retracted position, the installation drag

is minimized which eliminates the limits on centralizer performance. Without that

limitation, the centralizer can be used more eciently, whether by applying higher

forces or controlled displacements when needed.

&his can be achieved through an active centralizer system as shown in 3igure +!.

&he active centralizer will allow a large centralizing force compared to a traditional

bow spring with little or no installation drag. Additionally larger displacements can


32/36

be produced with a powered system to centralize the casing in e)tremely deviated

well bores. =epending on the re$uirements, the powered centralizer could be

deployed with a range of technologies that include paran actuators, shape

memory alloys, energetic materials 6gas generators7, etc.

Figure !1. 3eploya&le centrali>er concept

&he centralizer would be run in with the casing in the retracted conguration. &he

retracted conguration would still provide a minimal stando( between the casing

and the wellbore to prevent di(erential stic#ing. When it reaches the desired

location, it would deploy based on one of the methods previously described. &he

on-demand deployment helps to overcome the shortcomings associated with using

conventional centralizers.

1olving this problem will re$uire a systems-based approach. ntegrating the

centralizer with the casing, the environment, and the geology of the formation are

#ey factors to consider when developing this type of tool. Dy carefully dening the

problem re$uirements, a mechanism and power source can be developed for

geothermal applications. Accomplishing this will improve centralization of the

casing and help to eliminate failures associated with poor cement placement, thus

lowering the overall cost of well completion.


33/36


34/36

/ppendiB

Centrali>er Terms and 3e@nitions

&he following terms and denitions are included to facilitate the discussion ofcentralizers and completions. &erms related to centralizers have been adapted

from A2 1pec !@=.

:eBedcondition of a bow-spring centralizer when force three times the specied minimum

restoring force has been applied to it

holding devicedevice employed to ) the stop collar or centralizer to the casing

holding force

ma)imum force re$uired to initiate slippage of a stop collar on the casing

hole si>ediameter of the wellbore

restoring forceforce e)erted by a centralizer against the casing to #eep it away from the wellbore

wall

rigid centrali>ercentralizer with bows that do not 'e)

running forcema)imum force re$uired to move a centralizer through a specied wellbore

diameter

solid centrali>ercentralizer made to be a solid device with non-'e)ible ns or bands

stando smallest distance between the outside diameter of the casing and the wellbore

stando ratioratio of stando( to annular clearance for perfectly centered casing

starting forcema)imum force re$uired to insert a centralizer into a specied wellbore diameter

stop collardevice attached to the casing to prevent moving of a casing centralizer


35/36

eferences

!. Wan, R., Ad(an'ed &ell 'ompletion engineering. /rd ed. +@!!, Waltham, A:ulf 2rofessional 2ub. )), F!< p.

+. Wi#ipedia. )ompletion *oil and gas &ells+. +@!; cited +@!; 3ebruary,

http:HHwww.glossary.oileld.slb.comHenH&ermsHcHcementingUplug.asp) .!+. 1upport, 2. Single State )ementing 3peration. cited +@!; 3ebruary /"TAvailable from: http:HHpetroleumsupport.comHsingle-stage-cementing-operationH.

!/. Kernandez, R. and K. >guyen, e(erse8)ir'ulation )ementing and "oamedLate )ement !na%le Drilling in Lost8)ir'ulation ones, in ro'eedings orldGeot-ermal )ongress 2010. +@!@: Dali, ndonesia.

!;. Ric#ard, D., et al., e(erse )ir'ulation )ementing o Geot-ermal ells: A)omparison o ;et-ods6 RC &ransactions, +@!!. #7: p. ++


36/36

!M. A2 1pec !@= 1pecication for Dow-1pring Casing Centralizers, A2, +@!@+@. 0inzel, K. and V.. artens, T-e Appli'ation o $e& )entrali.er Types to

/mpro(e one /solation in ori.ontal ells. !MMG.+!. Kalliburton, rote'- )B )entrali.ers. +@!@, Kalliburton Cementing.++. &41C%, ydro8"orm )entrali.ers, &41C% Corporation.+/. ammage, V.K., Ad(an'es in )asing )entrali.ation Using Spray ;etal

Te'-nology , in 3>s-ore Te'-nology )oneren'e. +@!!, %&C: Kouston, &.+;. Weatherford, ;e'-ani'al )ementing rodu'ts. +@@M, Weatherford

nternational ?td.+

centralizer review

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