cementaciones primarias

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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 sometimes

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

cementaciones primarias

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