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Transcript of cementaciones primarias
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2001, Halliburton
4 1 Cementing 1
Section 4
Primary Cementing
Table of Contents
Introduction................................................................................................................................................4-3
Topic Areas.............................................................................................................................................4-3
Learning Objectives................................................................................................................................4-3Unit A: Primary Cementing Background...................................................................................................4-3
Preparations for Primary Cementing ......................................................................................................4-5Pre-Job Checklist....................................................................................................................................4-5
Unit A Quiz ............................................................................................................................................4-6
Unit B: Types of Casing Cementing Jobs ..................................................................................................4-7Conductor Casing ...................................................................................................................................4-7
Surface Casing........................................................................................................................................4-7
Intermediate Casing................................................................................................................................4-8
Production Casing...................................................................................................................................4-9
Innerstring Cementing .......................................................................................................... ................4-10
Unit B Quiz...........................................................................................................................................4-12
Unit C: Preventing Cementing Failures ...................................................................................................4-13
Causes of Primary Cementing Failures ................................................................................................4-14
Effects of Drilling Fluids and Contaminants on Cements....................................................................4-14Flow Properties.....................................................................................................................................4-15
Conditioning the Drilling Fluid ............................................................................................................4-16
Pipe Movement.....................................................................................................................................4-16
Pipe Centralization ...............................................................................................................................4-17
Eccentric Flow and Density Difference................................................................................................4-17
High Displacement Rates ........................................................................................................ .............4-18
Spacers and/or Flushes ......................................................................................................... ................4-18
Unit C Quiz...........................................................................................................................................4-19
Answers to Unit Quizzes..........................................................................................................................4-20
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Use for Section Notes
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Introduction
Primary cementing is the cementing operation
performed immediately after the casing has been
run downhole. This is accomplished by pumping
cement slurry down the entire length of casing,
out the bottom joint, and up into the annular
space. The cement is then allowed to set before
drilling is resumed or the well is completed.
The materials, tools, equipment, and techniques
to be used vary depending on the holeconditions, depth of the well, and the people
planning the job. Successful primary cementing
presents a constant challenge and requires up-to-
date knowledge and technology.As part of a cementing team, you must know
and understand purpose and methods for
primary cementing, and how to ensure that the
job is done correctly.
Topic Areas
The units in this section are:
A. Primary Cementing Background
B. Types of Casing Cementing Jobs
C. Preventing Cementing Failures
Learning Objectives
Upon completion of this section, you should be
familiar with:
The purpose of primary cementing
The main types of casing which arecemented
How to help prevent cementing failures byusing best practices
Unit A: Primary Cementing Background
The primary cementing process bonds the pipe
to the wall of the hole and prevents
communication of fluids in the well bore from
one zone to another. This is critical in the upper
part of the well where freshwater zones may be
encountered. The three main functions of the
cement are isolation, protection, and support.
Primary cementing isolates zones so that themigration of fluids cannot occur. For
example, it prevents:
- oil, gas, and salt water from migrating toand causing contamination of freshwater
zones.
- salt water from migrating into gas andoil zones and causing production
problems as well as pollution.
Primary cementing provides a sealant andprotects the casing against
- formation fluids or gas, which couldcause casing corrosion
- external pressure, which could collapsethe casing or result in a blowout.
- hole cave-in while deeper drilling isbeing done.
Primary cementing supports the casing andguards the casing string against:
- the excessive weight of other strings.
- the possibility that the bottom jointsmight unscrew.
Primary cementing uses several basic
techniques. The most typical procedure is the
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single-stage primary cementing job using the
two-plug displacement method (Fig. 4.1).
The single-stage primary cementing procedure
pumps cement down the casing between two
rubber plugs. The plugs are equipped with
wiping fins to help prevent contamination of thecement by mud and to help clean the interior of
the pipe.
Other commonly used techniques depend uponwell depth and completion requirements. Two-,
three-, and four-stage cementing procedures
decrease the hydrostatic pressure of the fluid
column in the annulus, help protect weak zones
against excessive high pressure, and help
prevent circulation loss. In addition to offering
economic advantages, cement may or may not
be circulated up the entire string to surface.Multiple-stage primary cementing is also
important for use in wells where two or more
zones are separated by long intervals.
Figure 4.1 Single-stage primary cementing job using the two-plug displacement method.
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Preparations for PrimaryCementing
Before any primary cementing job can proceed,
many steps need to be taken: seismographic
analysis, legal procedures, land surveys, and theselection and preparation of the specific wellsite. One of the last things that needs to be done
to prepare a land location is the digging of the
cellar. This is a hole (about 8 ft square), the
depth of which ranges from 1 to 6 ft. For
offshore locations (platform or jack up), thecellar deck is below the rig floor. The rig will be
placed over the cellar or cellar deck. It provides
height for blowout preventers (a BOP prevents
the escape of pressure from the annulus or an
open hole) and flow lines below the rotary table.
The power, hoisting, rotating, and circulating
systems are installed, and drilling begins. Then it
is time for the cementing service company crew
to do its work. In a later section, calculations
will be performed that are necessary for a
primary cement job. However, when you arrive
on location, you need to know several items ofinformation to be able to effectively complete
the job. The Pre-Job Checklist below was
developed to help you obtain this information.
The Pre-job Checklist should serve as a general
guideline to help you prepare for most primary
cementing jobs. Other questions, specific to the
individual type of job being performed need to
be asked accordingly.
Pre-Job Checklist
Questions to answer before leaving forlocation:
Questions to answer while on location:
Does the bulk cement ticket agree with theorder from the well operator?
What is the approximate time needed to mixand displace cement? (Does this agree withpumping time of cement?)
Has preparation been made to weigh cementproperly while mixing?
What is the size and type of thread on theconnections?
What type of floating equipment is being used?(Is a ball or other dropping device used withthis equipment?)
Has the Pre-Trip Inspection been performed onthe equipment?
Has the Lab report been finalized on thecement and additives?
What type of recording equipment is to beused?
Have pumping equipment and bulk cementequipment been checked and are they ready tomix cement?
Has maximum pressure been agreed upon?
Has it been determined if the rig pump or theservice unit is to pump the plug down?
Has preparation been made to flush the linesafter releasing the plug if the customer sodesires?
Has preparation been made to leave theservice truck tied into casing while rig pump isdisplacing cement in order to record pressureon casing job if the well operator so desires?
What size and weight casing is being used?
What is the size of the hole?
Is there enough water to mix cement? Is the
rate of water supply adequate? Has the volume of displacement fluid been
checked to see if there is adequate supply onlocation?
Is everyone on location aware of all the safetyconcerns?
Has preparation been made to drop the plugson the fly?
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Unit A Quiz
Fill in the blanks with one or more words to check your progress in Unit A.1. Primary cementing _____________ zones so that migration of fluids cannot occur. It prevents
pollution and contamination of ________________________.
2. In addition, primary cementing protects the casing against ____________ and ______________, and
the hole against _____________ while deeper drilling is being done.
3. Before drilling, a hole is dug on site which will house BOPs as well as other items. The rig will be
placed over this hole, which is called a ____________.
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Unit B: Types of Casing Cementing Jobs
In primary cementing, four basic strings of
casing may be used depending on well depths,
downhole formations, pressures, temperature,
freshwater zones and fluid to be recovered (oil,
gas, or steam). This section explains the
cementing of the four basic types of casing.
Conductor
Surface
Intermediate
Production
These casings were discussed in Section 2 ofthis workbook.
Conductor Casing
If conductor casing is used, it is first string set in
a well (Fig. 4.2). The setting depth of the
conductor casing can vary from 10 ft to more
than 300 ft. The depth of conductor casing
depends on how deep you must go to reach solid
material. The size of conductor pipe ranges from
16 in. to 36 in. OD, depending upon how manyother strings run through it.
ConductorCasing
Reservoir
Figure 4.2 Conductor Casing
In soft formations, the conductor casing may
simply be pounded into the ground. Otherwise, a
hole is drilled for it. Only conductor casing that
is run in drilled holes is cemented. The cement
used for conductors is usually accelerated to
reduce WOC (Wait on Cement) time. It also
may include lost circulation additives to prevent
loss of cement to the formation.
This pipe may be cemented in the conventionalmanner or it may be cemented in stages. Care
must be taken to ensure that the pipe does not
collapse during cementing. If a hole has been
drilled for the conductor, mud may have beenused. Therefore, a spacer should be run for goodmud removal, and a top plug should be run to
help prevent channeling when the conventional
cementing method is used.
To reduce the amount of cement that is inside
the casing at any point during the job,
innerstring cementing may be used on the
conductor casing. In this technique, tubing or
drill pipe (small enough to fit inside the casing)
is run to a specially-designed innerstring guide
shoe or float collar. The tubular goods are
stabbed into the collar or shoe, and cement ispumped. If the hole size has been estimated for
the job and cement slurry is designed to be lifted
to surface, some of the excess cement may be
eliminated and returned in dry bulk form due to
having a minimal amount within the
tubing/drillpipe at any one time. Typically, a
latch-down plug is run inside the workstring
after the cement to seal off in the collar or shoe.
Surface Casing
Surface casing is usually the second string set in
the well (Fig. 4.3). However, it may be the first
if conductor casing is not used. Surface casing
depth requirements vary from near ground level
to several thousand feet, depending upon how
deep you must go to cover all fresh water zones.
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Surface pipe size ranges from 7 5/8-in. to 20-in.
OD. Again, the size depends upon how much
additional casing will be run below the surface
casing. As the depth increases, so does the
temperature, pressure, and the amount of
corrosive fluids. Thus, different grades of pipe
are necessary to withstand different wellconditions. The hole is drilled to the depth
desired for the surface casing.
ConductorCasing
SurfaceCasing
Cement
Reservoir
Figure 4.3 Surface Casing
Before cementing, the well should be circulated
to break up the gel strength of the mud. Also, aspacer should be run for good mud removal.
Cement for surface casing will usually be an
accelerated type. Other additives are used to
combat lost circulation, if necessary.
Normally, a simple combination of a casing
guide shoe, float collar (or insert float valve),
and centralizers is used. It is important to ensure
that the bottom section of the surface casing is
well centralized. Downhole equipment discussed
in Section 10 may be used when running surface
casing.
On a conventional job, both a top and a bottom
plug should be run, unless you are using a lost
circulation additive in the cement. An important
point to keep in mind is that the pressure to land
the plug, when released, must not be enough to
collapse the casing. When innerstring cementing
techniques are used, the possibility of collapsing
the casing is reduced by adding weighted fluid
between the drill pipe and the casing.
If lost circulation is a problem, the cement may
be pumped down the annulus through a 1 in.
pipe to bring cement to the surface. If casing
collapse or formation breakdown may be aproblem, the cement may be pumped in stages,
using a multiple stage tool.
Usually a filler or lead cement (a less expensivecement, such as Class H cement with Bentonite)
is run to fill the annulus back to ground level.
Higher strength cement (called the tail cement)
is then pumped to set around the bottom of the
surface casing. Before drilling out, the cementshould have a compressive strength of at least
500 psi.
The bottom joints of surface casing (or any
casing string that will have drilling operations
conducted below it) are subject to being
unscrewed by drill pipe rotation. As drill pipe is
rotated clockwise inside the surface casing, any
drag transferred to the casing results in a
counter-clockwise force being exerted above the
point of drag. Should the force be adequate to
unscrew a casing joint, the problem must be
fixed or the well abandoned. For this reason, the
bottom joints of casing must be well centralized
in the hole, with a competent cement in place to
hold it securely in a fixed position. Often,
special thread compounds are used to chemically
"weld" the box and pin connections together.
Intermediate Casing
Intermediate casing is set after the surface casing
(Fig. 4.4). A string may extend from ground
level to as far as 25,000 ft. The size and type of
intermediate casing is again dependent on the
number of other strings to be run below it, and
the grade required to withstand the conditions in
the well. Sizes range from 6 5/8 in. to 20 in.,
with the most common sizes being: 9 5/8-in., 10
3/4-in. and 13 3/8-in. casing. The hole is drilled
to the depth desired for the intermediate casing.
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ConductorCasing
SurfaceCasing
Intermediate
Casing
Cement
Cement
Reservoir
Figure 4.4 Intermediate Casing
As in most casing jobs, it is very important to
break up the gel strength of the mud and run a
spacer to clean the mud before cementing is
begun. Since prolonged drilling is done through
the intermediate string, damage to this casing is
fairly common. Centralizers and scratchers are
used on the intermediate casing string to help
ensure uniform cement bonding. In addition,
cement baskets may be used to help protect
weak formations.
The first cement pumped (lead slurry) forintermediate casing is a filler type. It is followed
by a higher density tail cement. Unlike cement
used in surface or conductor jobs, it usually
contains retarders to allow good pump time in
high temperatures. It may also contain friction-reducing, lost-circulation, or fluid-loss additives.
If the casing is being run through salt or shale
zones, a salt additive will be needed. In short,
several blends of slurries may be needed because
of the characteristics of the formationsencountered.
The innerstring cementing method is sometimesused for intermediate casing. However, if the
pipe size is small, the conventional two-plug
method may be used. (Remember to use the
bottom plug unless lost circulation materials are
being run.) If the casing is run to a great depth,
or if formation breakdown is a problem, the
cementing job may be performed in multiple
stages.
Production Casing
The production casing (Figure 4.5) is the last fullstring of pipe set in the well. Sometimes liners
are used instead of production casing. The
production string extends from the surface to the
deepest producing formation. It must be small
enough to fit through all the previous casings.
The most common sizes are 4 1/2 in., 5 1/2 in.,
and 7 in. casing. It will be cemented, then
perforated in the producing zone. Therefore, a
good cement job here affects the success of the
well more than in any other part.
ConductorCasing
Surface
Casing
IntermediateCasing
ProductionCasing
Casing ShoeCement
Cement
Cement
Reservoir
Figure 4.5 Production Casing
As stated before, it is very important to have a
good cement job here. The hole is drilled to the
lowest producing formation. Then it is circulated
and a spacer is run. Depending on the well
conditions, all types of equipment may be used(centralizers, packer shoes or collars, multiple
stage tools, etc.) to help ensure the jobs success.
The proper blend of cement depends upon the
hole conditions. Testing of the cement is
particularly essential for a production casing
cementing job. When cementing, the slurryshould be at the highest possible rate while
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rotating or reciprocating the pipe. After the job,
but before the cement sets, the pressure should
be released to ensure that the float valve is
holding. Also, holding pressure until the cement
sets could cause a microannulus behind the
casing.
Innerstring Cementing
Halliburtons inner string cementing equipment
allows cementing large diameter strings through
drillpipe or tubing that is inserted and sealed in
floating equipment. This method is some- times
less costly than cementing large casing using the
conventional plug displacement method. Other
advantages include:
Large diameter cementing plugs are notrequired
By pumping through the smaller innerstring, you can reduce cement contamination
resulting from channeling inside casing
Cement is discharged outside the casingmuch faster after mixing, reducing the risk
of the cement slurry within the casing
having a highly accelerated setting time
Reduces amount of cement that has to bedrilled out of large diameter casing
Less circulating time required with innerstring cementing
There are three basic methods available for
performing inner string cementing. Each relies
on Halliburton's proven line of Super Seal II
floating equipment. Methods include (1) Super
Seal II float collar with sealing sleeve (Fig. 4.6),
(2) Super Seal II float collar with sealing sleeve
and latch-down seat, and (3) standard Super Seal
II float collar. Super Seal II equipment offers
these benefits:
Reduces cement waste
Reduces casing collapse
Reduces cement drill-out time
Eliminates large diameter cement plugs
Drillpipe latch-down plugs available
Figure 4.6 Super Seal II Float Collarwith Sealing Sleeve
Innerstring cementing requires that a stab-in
float shoe or float collar be installed in the
casing string. The casing string is run into the
well in the usual manner. The inner string is then
run in, with the sealing adapter made up on the
lower end and stabbed into the floating-
equipment sealing sleeve.
The sealing sleeve is built into the floatingequipment to provide a sealing-surface
receptacle for the innerstring sealing adapter.
Concrete is molded around the sealing sleeve to
secure the sleeve within the floating equipment.The floating-equipment top is also tapered to
form a surface that helps guide the sealing-
sleeve adapter into its sealing sleeve. Two
centralizers should be run on the inner string:
one centralizer is directly above the sealing
adapter, and another one or two joints above the
first centralizer. This arrangement will help the
inner string enter the stab-in floating equipment.
After the inner string (usually drillpipe) has been
stabbed into the floating equipment, cement is
pumped through the inner string and floating
equipment into the casing/wellbore annulus.After cementing has been completed, the check
valve in the floating equipment prevents cement
from re-entering the casing, and the sealing
adapter and inner string can be pulled from the
casing.
Floating equipment with a latch-down plug seat
is also available. This floating equipment is built
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with a combination sealing sleeve and latch-
down plug seat. The combination sleeve, which
is held in place by concrete, provides (1) a
sealing surface for the inner-string sealing
adapter on the top and (2) a bore configuration
to latch and seal the nose of a latch-down plug
on bottom.
After the last cement is displaced down the inner
string, a top latch-down cement plug is launched
down the inner string. The nose of the latch-
down plug seats and latches into the float
equipment sleeve immediately after passing
through the innerstring sealing sleeve. After
latching in, the plug nose should seal and
withstand pressure from above and below.
After the innerstring is retrieved, the latch-down
plug serves as a backup to any backpressure
valves located in the casing string below.Pressure can be applied inside the casingimmediately after the latch-down plug has been
landed and the sealing-sleeve adapter has been
pulled from the sealing sleeve.
Figure 4.7 Innerstring cementing method,used for large-diameter casing.
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Unit B Quiz
Fill in the blanks with one or more words to check your progress in Unit B.
1. Cement for conductor and surface casing usually contains additives to _______________ the setting
time and to reduce _________ time.
4. A cementing technique known as __________________ is sometimes used for large diameter casing
to reduce the amount of wasted cement. Tubular goods are stabbed into a specially-designed
________________________. Cement is then pumped through this smaller string and a
____________________ plug is run.
5. The depth of surface casing depends on how far you must go to cover all ______________ zones.
6. Following the spacer, _____________ cement is run. This is followed by a _________ cement which
is usually more expensive and more dense.
7. Cement with _______________ is used as the tail cement with intermediate strings.
8. The last full string of pipe run in the hole is ________________ casing.
9. The hole for production casing is drilled to the ___________________________________________.
10.The cementing job performed for the _______________ casing is probably the most important for the
wells success. The pipe should be_________ during cementing.
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Unit C: Preventing Cementing Failures
Many cementing failures have been caused by
inefficient drilling fluid displacement, resulting
in drilling fluid channels in the cement column.
Since 1971, HES has used a large-scale test
model, equipment, and materials that simulate
actual cementing conditions to study the factors
that affect cementing efficiency. Findings from
these cementing studies, combined with the
knowledge acquired from more than 75 years of
cementing experience, have led to procedures
and theories for effectively cementing wells.
These uncemented drilling fluid channels
provided a permeable conduit for well fluids tomigrate, causing lost production and/or corrodedcasing. Since then, the industry has investigated
many variables under various simulated
cementing conditions. The general testing
procedures and the equipment used to perform
these tests have been modified and updatedthroughout the years, enabling the simulation of
both typical and specialized cementing
conditions.
Displacement research has examined various
formations, irregularities in the wellbore (such
as washouts), and controllable factors (such as
the condition of the drilling fluid, pipe
movement, pipe centralization, flow rate, and the
use of spacers/flushes). Each of these affect
displacement efficiency (the percentage of mud
removed ahead of a cement slurry). This section
summarizes 25 years of study on the factors that
affect displacement efficiency for the majority
of jobs performed:
Causes of primary cementing failures
Possible flow patterns that mud, cement, andspacers may obtain in the annulus during a
primary job.
Importance of mud conditioning and flowrates.
Importance of pipe centralization andmovement.
Importance of cement-mud spacers.
Figure 4.8 Test samples showing cement displacement efficiencies: Sample 2 is 97% efficientand Sample 4 is only 64% efficient (notice the mud between the cement and the outer casing).
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Causes of Primary CementingFailures
You need to know what can go wrong when you
are involved in a cementing job. Many factors
can contribute to a poor job; some will bediscussed briefly here.
Incomplete mixing of the slurry. This can becaused by:
- mechanical failure
- failure of the bulk system
- incorrect water or pressure.
Cement setting too quickly or too slowly.This can be caused by:
- contaminated mixing water- too much or too little mixing water
- incorrect down-hole temperatureestimate
- plugged shoe or collar
- inadequate pumping rate
- mechanical failure.
Channeling of the slurry (less than totalcement coverage around the outside of the
pipe over the target interval). This can becaused by:
- failure to centralize pipe
- failure to move pipe
- failure to circulate mud system and runa mud/cement spacer.
Effects of Drilling Fluids andContaminants on Cements
Cement slurries and drilling fluids (drilling mud)are almost always incompatible. The primary
incompatibility problem is when a mixture of the
two is thicker than either of the separate fluids.
This increased thickness (or viscosity) increases
the difficulty of displacing drilling mud ahead of
the cement slurry, in the annulus, while
pumping. Most often, uncontaminated cement
slurry fingers through the contaminated mixture
resulting in a channel and limited coverage of
the pipe exterior with competent cement. Severe
incompatibility may result in early jobtermination due to being unable to move an
extremely viscous mass of mud/cement mixture.
Mud and cement intermixing also adversely
affect slurry thickening time (designed time
from mixing to becoming unpumpable) and
cement compressive strength. Muds tend to
drastically extent the cement pump time and
prevent the cement mixture from gaining
minimum required compressive strength.
Normally a remedial or squeeze job is
required to correct the poor results of theprimary job. Delays in operations, cost of
additional cement jobs, and decreased
probability of isolating critical zones maydrastically drive well costs up or even force well
abandonment.
Halliburton has numerous mud/cement spacers
that are designed to prevent mud from
contaminating cement. When incorporated with
other best practices, these products help ensure asuccessful primary cement job.
Intermixing of mud and cement inside the casingis eliminated by using special wiper plugs at
critical times during the job. These were
discussed earlier in this section.
Contaminants include fertilizers, decomposed
animal life, agricultural products, soil chemicals,
and waste effluents.
The effects of different mud additives on cementare shown in Table 4.1.
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Table 4.1 Mud Additives and Their Effect on Cement
Additives Purposes Cement Effects
Barium Sulfate (BaSO4) Weighting agent Density increasestrength reduction
Caustics (NaOH, Na2CO3, etc.) pH adjustment Acceleration
Calcium compounds CaO, Ca(OH)2, CaCl2,CaSO4, 2H2O)
Conditioning and pH control Acceleration
Hydrocarbons (diesel oil, lease crude oil) Control fluid loss, lubrication Density decrease
Sealants (scrap, cellulose, rubber, etc.) Seal against leakage to formation Retardation
Thinners (tannins, lignosulfonates, quebracho,lignins, etc.)
Disperse mud solids Retardation
Emulsifiers (lignosulfonates, alkyl ethyleneoxide adducts, hydrocarbons sulfonates)
Forming oil-in-water or water-in-oil muds Retardation
Bactericides (substituted phenols,
formaldehyde, etc.)
Protect organic additives against
bacterial decomposition
Retardation
Fluid-loss control additives (C.M.C., starch, guarpolyacrylamides, lignosulfonate
Reduce fluid loss from mud to formation Retardation
Flow Properties
Mud removal in the annulus is a function of the
flow patterns that are achieved. Three types of
flow patterns are:
Plug Flow - mud removal is minimal due to low
frictional or drag forces exerted on the mudlayer. This flowrate can remove only about 60%
of the mud from the pipe.
Laminar Flow - fluid velocity is higher creating
more friction. This results in more force being
exerted on the mud layer by frictional drag,
resulting in improved mud removal. This
flowrate can remove as much as 90% of the mud
from the pipe.
Turbulent Flow - A maximum mud removalcapability is reached due to high frictional or
drag forces. Eddies and current in the fluid
result in a mud removal percentage as high as
95%.
Plug Flow Laminar Flow Turbulent Flow
Figure 4.9 Plug flows.
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Conditioning the Drilling Fluid
A well-conditioned drilling fluid is the mostsignificant factor affecting drilling fluid
displacement. Studies in test wells that simulate
realistic permeability reveal the importance ofadditives to control fluid leak-off, from the mud,
in order to prevent excessive filter-cake buildup.
In tests simulating vertical wellbore cementing
conditions, immobile drilling fluid filter cake
could not be displaced completely by the cement
slurry, even under turbulent flow conditions.
Low viscosity spacers/flushes placed ahead of
the cement slurry and pipe movement coupled
with mechanical scratchers/wall cleaners can
help remove gelled drilling fluid or filter cake.
However, there is no substitute for maintaining
drilling fluid properties that enhance themobility of the drilling fluid, enabling
displacement by the cement slurry.
FILTRATE
Filtrate Cement
Casing
LowMobility
Mud
FilterCake
MobileMud
Formation
Figure 4.10 Conditioned drilling fluid iseasier to remove.
Another way to improve drilling fluid mobility
(to enhance its displacement capability) is
through prejob circulation to thoroughly fluidizethe drilling fluid before cementing. To further
improve its mobility, the viscosity of the drillingfluid should be reduced, if possible, during the
prejob circulation period. Proper hole
conditioning is critical to successful cementing
operations.
It is also important to limit the amount of static
time before and during the cement job. From the
tests conducted to determine static time
influence, the results presented in Figure 4.5
show a significant decrease in displacement
efficiency after only 5 minutes of down time.
0
10
20
30
40
50
60
70
80
90
100
DisplacementEfficiency(%)
0Minutes
5Minutes
2Hours
4Hours
Affect of Static Time
Figure 4.11 Static Time
A well engineered cement job design will
include laboratory testing of the mud to measure
its viscosity (rheological properties) under
down-hole conditions. Additives or base fluid
(water or synthetic oil) can be added prior tocementing to improve the muds tendency to
flow ahead of the cement slurry.
Pipe Movement
Second to drilling fluid conditioning inimportance is the need to employ pipe
movement, either rotation or reciprocation, both
during and before cementing. Pipe movement
helps break up gelled pockets of drilling fluid
and the loose cuttings that may accumulatewithin the pockets. Pipe movement also can help
offset the negative effects from poorly
centralized pipe. Mechanical scratchers attached
to the casing further enhance the beneficial
effects of pipe movement.
If casing is properly centralized, pipe movement
can be accomplished even in horizontal wells. In
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addition, if the drilling fluid system is not
carrying solids, pipe movement can help
eliminate a solids-settled channel.
Figure4.12 Pipe movement.
Pipe Centralization
According to test results, pipe centralization is
another important factor in obtaining highdisplacement efficiency. In test sections where
the pipe was not central in the hole, the cement
displayed a strong tendency to bypass drilling
fluid. Centralizers improve pipe standoff,thereby equalizing the distribution of forces
exerted by the cement slurry as it flows up the
annulus. Otherwise, cement tends to follow the
path of least resistancethe wide side of the
annulus.
C
Formation
Mud
Cement
Casing
Figure4.13 - Cement tends to follow thewide side of the annulus.
Figure 4.14 Pipe centralization.
Eccentric Flow and DensityDifference
When designing fluids for a specific flow
regime, it is assumed that the flow is in a
perfectly centered annulus. In reality, this is not
true. In an eccentric annulus, the fluid has a
tendency to take the path of least resistance; the
fluid will tend to flow through the wider section
of the annulus more readily.
Under these conditions, the flow regime in the
wider section can be different than the flow
regime in the narrower section. For example, the
flow may be turbulent in the wide section and be
laminar, or even plugged, in the narrow section.
Under these conditions, a large density
difference between cement and drilling fluid can
improve displacement efficiency. Under all
other conditions, it is the velocity of fluids that
will primarily determine the displacement
efficiency.
As a general rule of thumb, the design of spacers
and cements should follow the low to high-density approach. That is, the spacer should be
heavier than the drilling fluid and the cement
heavier than the spacer.
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High Displacement Rates
The greatest displacement efficiencies observedin tests conducted at a scale-model test facility
consistently occur at the highest displacement
rates, regardless of the flow regime of thecement slurry. The highest displacement
efficiency occurred under turbulent flow
conditions; however, if turbulent flow could notbe achieved, displacement was consistently
better at the highest rates attained under like
conditions for similar slurry compositions.
With other factors being equal, thin cement
slurry placed under turbulent flow conditions
exhibited higher drilling fluid displacement
efficiency than a thicker slurry placed at low
rates. Frequently, turbulent flow is not a viable
option, such as when hole and formationconditions create frictional pressures exceeding
the fracturing gradient of the formation. Test and
field data clearly indicate that even when
turbulence is not possible, pump rates should be
maximized.
Spacers and/or Flushes
One of the key factors in obtaining an effective
primary cementing job is to minimize the
contamination of the cement slurry with thedrilling fluid. The drilling fluid must be
completely displaced from the annulus so that a
competent cement sheath can form and produce
an effective hydraulic seal.
The inadequate removal of annular fluids may
result in poor cement bonds to the pipe and
formation, intrazone communication, pipe
corrosion, and pipe collapse. In High-
Pressure/High-Temperature (HPHT) wells, these
factors become even more critical. The correct
spacer system can help the operator/service
company achieve a quality cement job.
Spacers may be water or oil based. Current oil
based spacers often use synthetic oils to avoid
the environmental concerns of hydrocarbon
based oil, such as diesel. Water based spacers
tend to leave steel in a water wet condition
which aids with cement bonding.
Non-weighted spacers are often referred to as
flushes. Water is a common flush. These are
most effective and economical on low density
muds that are near the density of the flush. They
are the easiest to put into turbulent flow. Often,
additives are used which thin drilling mud or
chemically attack mud filter cake.
Figure4.15 Use of spacers.
For densified muds, spacers must be designed
with weighting materials resulting in the spacer
being equal to, or greater, than the mud in
density. A lighter density spacer will result in
poor mud displacement efficiency. The viscosity
of weighted spacers may be modified to further
enhance mud displacement. Halliburton
maintains design software that aids with
weighted spacer design.
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Unit C Quiz
Fill in the blanks with one or more words to check your progress in Unit C.
1. A plugged shoe or collar, contaminated mixing water, or an inadequate pumping rate might cause the
___________ to _________________________.
2. _____________ can be caused by lack of pipe centralization and movement.
3. Drilling fluid and cement are often _______________ and intermixing of the two may cause a
primary cementing job _________________.
4. ___________________________ properties allow for maximum removal of drilling mud due to high
frictional drag forces.
5. A _________________________ drilling fluid is critical for successful mud removal.
6. Pipe movement can offset the ________________ effects of poorly _________________ casing
during a primary cement job.
7. If casing is not perfectly centered, cement will tend to flow up the _________ side of the annulus.
8. Even if turbulent flow cannot be obtained, the highest possible __________________ should be used
for _____________ mud removal.
9. ____________ or _____________ help minimize contamination between a cement slurry and
drilling ___________.
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Answers to Unit Quizzes
Items from Unit A Quiz Refer toPage
1. isolates, freshwater zones 4-3
2. formation fluids, gas, cave-in 4-3
3. cellar 4-4
Items from Unit B Quiz Refer toPage
1. accelerate, WOC 4-7
2. innerstring cementing, guide
shoe or float collar, latch-down
4-7
3. freshwater 4-7
4. lead, tail 4-8
5. retarder 4-9
6. production 4-9
7. lowest producing formation 4-9
8. production, rotated 4-9
9. float shoe, float collar 4-10
10. latch-down 4-11
Items from Unit C Quiz Refer toPage
1. set too quickly 4-14
2. cement, channeling 4-14
3. incompatible, failure (ortermination)
4-14
4. Turbulent flow 4-15
5. well conditioned 4-16
6. negative, centralized 4-167. wide 4-16
8. flow rate, maximum 4-18
9. Spacers, flushes, fluid (mud) 4-18