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.
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