Csng Centralizers Paper

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Distinguished Author Series articles are

general, descriptive representations that

summarize the state of the art in an area of

technology by describing recent developments

for readers who are not specialists in the topics

discussed. Written by individuals recognized as

experts in the area, these articles provide key

references to more definitive work and present

specific details only to illustrate the technology.

Purpose: to inform the general readership of

recent advances in various areas of petroleum

engineering.

Casing centralizers

The uniformity of the cement sheath

around the pipe determines, to a great

extent, the effectiveness of the seal

between the wellbore and the casing.

Because holes are rarely straight, the

pipe is generally in contact with the

wall of the hole at several places. Hole

deviation may vary from zero to, in

offshore directional holes, as much as

70 to 90. Such severe deviation greatly

influences the number and spacing of

centralizers (Fig. 1).

Fig. 1 Single piece spring bow

centralizer (courtesy of

Eneroil).

A great deal of effort has been

expended to determine the relative

success of running casing strings with

and without centralizers. Although

experts differ on the proper approach to

an ideal cement job, they generally

agree that success hinges on the proper

centralization of casing. Centralizers are

among the few mechanical aids covered

by API specifications.

Centralizing the casing with mechanical

centralizers across the intervals to be

isolated helps optimize drilling-fluid

displacement. In poorly centralized

casing, cement will bypass the drilling

fluid by following the path of least

resistance. The cement travels down the

wide side of the annulus, leaving

drilling fluid in the narrow side. When

properly installed in gauge sections of a

hole, centralizers:

Prevent drag while pipe is run

into the hole

Center the casing in the wellbore

Minimize differential sticking,

thus, helping to equalize

hydrostatic pressure in the

annulus

Reduce channeling and aid in

mud removal.

Types of centralizers

Two general types of centralizers are:

Spring-bow

Rigid

Spring-bow centralizer

The spring-bow type has a greater

ability to provide a standoff where the

borehole is enlarged.

Rigid-type centralizer

The rigid type provides a more positive

standoff where the borehole is close to

gauge.

Positive-type centralizers are to in.

smaller in diameter than the hole size

where they are to be run and, therefore,

have no drag forces with the wellbore.

Rigid-type centralizers are commonly

run in horizontal wellbores, because of

their positive standoff. Both spring-bow

and rigid centralizers are available in

almost any casing/hole size. The

important design considerations are

positioning, method of installation, and

spacing. Centralizers should be

positioned on the casing through

intervals requiring effective cementing,

on the casing adjacent to (and

sometimes passing through) the

intervals where differential-sticking is a

hazard, and, occasionally, on the casing

passing through doglegs where key

seats may exist.

Fig. 2 Stop Collar (courtesy of

Eneroil).

Pipe standoff

Good pipe standoff helps ensure a

uniform flow pattern around the casing,

and helps equalize the force that the

flowing cement exerts around the

casing, increasing drilling-fluid

removal. In a deviated wellbore,

standoff is even more critical to help

prevent a solids bed from accumulating

on the low side of the annulus. The

preferred standoff should be developed

from computer modeling, and will vary

with well conditions. Under optimum

rates, the best drilling-fluid

displacement is achieved when annular

tolerances are approximately 1 to 1.5 in.

Effective cementing is important

through the production intervals and

around the lower joints of the surface

and intermediate casing strings to

minimize the likelihood of joint loss.

Restraining devices (collar or

stop collars)

Centralizers are held in their relative

position on the casing either by casing

collars or mechanical stop collars. The

restraining device (collar or stop collar)

should always be located within the

bow-spring-type centralizer, so the

centralizer will be pulled, not pushed,

into the hole. The bow-spring-type

centralizer should not be allowed to ride

free on a casing joint.

Fastening devices for casing

attachments

All casing attachments should be

installed or fastened to the casing by

some method, depending on the type

(i.e., solid body, split body, or hinged).

If they are not installed over a casing

collar, a clamp must be used to secure

or limit the travel of the various casing

attachments.

There are a number of different types of

clamps. One type is simply a friction

clamp that uses a setscrew to keep the

clamp from sliding. Another type uses

spiral pins driven between the clamp

and the casing to supply the holding

force (Fig. 2). Others have dogs (or

teeth) on the inside that actually bites

into the casing. Any clamp that might

scar the surface of the casing should not

be used where corrosion problems exist.

Placement of centralizers

Most service companies offer computer

programs on the proper placement of

centralizers, based on casing load, hole

size, casing size, and hole deviation. All

computer spacing programs are based

on a standoff of 67% used in API Spec.

10D.[1]

The computer programs

determine placement of the centralizers

on the casing string, depending on the

well data entered into the program. The

programs are based on the equations

published in API Spec. 10D.[1]

Design of centralizers

The design of centralizers varies

considerably, depending on the purpose

and the vendor. For this reason, the API

specifications cover minimum

performance requirements for standard

and close-tolerance spring-bow casing

centralizers.

Definitions in API Spec. 10D[1]

cover:

Starting force

Running force

Restoring force

Starting force

The starting force is the maximum force

required to start a centralizer into the

previously run casing. The maximum

starting force for any centralizer should

be less than the weight of 40 ft of

medium-weight casing. The maximum

starting force should be determined for

a centralizer in its new, fully assembled

condition as delivered to the end user.

Running force

The running force is the maximum force

required to move a centralizer through

the previously run casing. The running

force is proportional to and always

equal to or less than the starting force. It

is a practical value that gives the

maximum running drag produced by

a centralizer in the smallest specified

hole size.

Restoring force

The restoring force is the force exerted

by a centralizer against the casing to

keep it away from the borehole wall.

The restoring force required from a

centralizer to maintain adequate

standoff is small in a vertical hole but

substantial for the same centralizer in a

deviated hole (25_ 65 inclination)

Centralizing smaller annuli is difficult,

and pipe movement and displacement

rates may be severely restricted. Larger

annuli may require extreme

displacement rates to generate enough

flow energy to remove the drilling fluid

and cuttings. Semi rigid integral

Centralizers like CENTEK,

CENTRATEC, ANTELOPE,

ENEROIL or similar mechanical

cementing aids that are commonly used

in the industry may also serve as inline

laminar-flow mixers, changing the flow

pattern of the fluids, which can promote

better drilling-fluid removal and greater

displacement.

The flexible integral bows create a

restoring force that creates separation

between the casing and wellbore. The

restoring force however creates a

friction force between the casing and

the wall. This running force in gauged

or tight holes adds considerable drag

efforts. Take account that the

centralizers are designed as per as API

Spec. 10D[1]

to be run in hole dragging

hole cuttings down while those are

falling to the hole pocket.

During casing running operations

sometimes due open hole conditions is

needed pick up or POOH the casing.

Under those conditions while picking

up de casing the restoring forces gather

than 70 % plays against the bore hole

dragging cuttings that must be

cumulated, carried and packed off if the

circulation is not enough to cause

cleaning effect.

The API Spec. 10D[1]

consider 67%

standoff radio as minimum

recommendable, any phrase mention

that 100% restoring force o full standoff

is needed or better because every

centralization program must consider

tight hole conditions not ideal

conditions.

Casing in high angle sections will have

to be pushed into the hole rather than

allowing them to slide down with

gravity. The need to push the casing

through the hole can lead to buckling of

the casing as it is run. For casing to

slide down the hole, the axial force must

be greater than the drag force. If the

axial compressive forces are large

enough, sinusoidal buckling in the

casing can occur. Beyond sinusoidal

buckling, helical buckling can also

become a concern. In helical buckling,

additional side forces can be significant.

Additionally, there are known cases of

centralizers being damaged or destroyed

while running casing. A field study by

[13] showed that centralizers are

susceptible to damage while being run,

especially as they exit casing. They

discovered several failures of

centralizers run on liners in the

transition from intermediate casing to

the horizontal lateral. Several types of

rigid centralizers were tested in the lab

to determine the failure mechanisms.

They concluded that a variety of factors

can affect centralizer performance

including the blade shape and the

diameter relative to the opening.

References

1. Kinzel, H. and J.G. Martens, The Application of New Centralizer Types to Improve Zone Isolation in Horizontal Wells, in SPE International Oil and Gas Conference and Exhibition in China,. 1998, Society of Petroleum Engineers: Beijing, China.

2. API 5CT Specification for Casing and Tubing, API, 2005

3. Schlumberger. Schlumberger Oilfield Glossary. [cited 2014 February 3]; Available from: http://www.glossary.oilfield.slb.com/en/Terms/c/cementing_plug.aspx.

4. Support, P. Single State Cementing Operation. [cited 2014 February 3]; Available from: http://petroleumsupport.com/single-stage-cementing-operation/.

5. Sanchez, R.A. and W. Adams, Casing Centralization in Horizontal and Extended Reach Wells, in SPE/EAGE European Unconventional Resources Conference and Exhibition. 2012, Society of Petroleum Engineers: Vienna, Austria.

6. Antelope. Series 400 - Positive / Rigid Welded Centralizers. 2014 [cited 2014 January, 27]; Antelope Oil Tool: Available from: http://www.antelopeoiltool.com/products/series-400-positive-rigid-welded-centralizers.html.

7. API Spec 10D Specification for Bow-Spring Casing Centralizers, API, 2010

8. Halliburton, Protech CRB Centralizers. 2010, Halliburton Cementing.

9. Gammage, J.H., Advances in Casing Centralization Using Spray Metal Technology, in Offshore Technology Conference. 2011, OTC: Houston, TX.

10. Juvkam-Wold, H.C. and J. Wu, Casing Deflection and Centralizer Spacing Calculations. SPE Drilling Engineering, 1992. 7(04): p. 268-274.

11. Blanco, A., V. Ciccola, and E. Limongi, Casing Centralization in Horizontal and Highly Inclined Wellbores. 2000.

12. API RP 10D-2 Recommended Practice for Centralizer Placement and Stop-collar Testing, API, 2010

13. Kinzel, H. and A. Calderoni, Field Test of a Downhole-Activated Centralizer To Reduce Casing Drag. SPE Drilling & Completion, 1995. 10(02): p. 112-114.

14. Antelope. Series 500 - Hinged, Welded, Standard Bow Centralizers. 2014 [cited 2014 January, 27]; Antelope Oil Tool: Available from: http://www.antelopeoiltool.com/products/series-500-hinged-welded-standard-bow-centralizers.html.