Weather Ford Cementing Program Handbook)

•. Weatherford® Weatherford~--

CementingProgram

-,

Notice:The information in this handbook is given in good faith. However, nowarranty is given and Weatherford assumes no liability for advice orrecommendations made herein.

Published by Weatherford International Inc.

Printed by Gi1comston Litho (Aberdeen) Limited

@ Copyright 1986 Weatherford. All rights reserved.

AcknowledgmentFor more than 30 years Weatherford has been striving

to improve primary cementation technology and products.This handbook continues the Weatherford tradition byoffering a compilation of the most recent technology incementation.

Weatherford has relied on many sources in compilingthis handbook and gratefully acknowledges the followingauthors and publishers: George O. Suman, Jr., Richard e.Ellis, Pat Parker, Clark Clement, W.e. Goins, ClydeCook, L.G. Carter, Rudy B. Callehan, World Oil, The Oiland Gas Journal, Drilling Magazine, Dowell Schlumbergerand The Societyof Petroleum Engineers. Please see theBibliography at the end of the handbook for additionalsource information.

r .Weatherford Table of Contents

1--

Introduction.. ......... . ..... ........1

Reasonsfor Cementing Casing. ... 2Axial Load 2ZoneIsolation 3Corrosion ... 3BlowoutPrevention 3

Casing String Design .......................................4Tension ... ... 4Collapse ... 4Burst 5Casing Safety Factors 5Casing Strings 5

CementingTechniques........ ... . .... .. ... .. ... .... ....6Primary Cementation 6SecondaryCementation.. . . . . . . . . . . . .. . .. . . . . . . . . . . . . . . . . . .. . .. .7

Cements and Additivt;s 9Rheology of Fluids. . . . . . . . . . . . . . . . . . .. . . . . .. . . . . . . . . . . . . . .. . . . . .9Propertiesof Cement ..10Additives. . . . . . . . . . . .. . . . . . . . . . . . . . . .. . . . . .. . . .. . . . . . . . . . . . . . ..13

Propertiesof Set Cement... .15

CementingFailures... ...17Conditioning of Drilling Fluids. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17FlowRegime ... ...17DisplacementVelocity ...18EffectofDensity............ ...... ... . ....18Centralization .18DifferentialPressureSticking...... ........... .... . ....19PipeMovement.... .... .... ..... ..... ... ..... .... ..... . .... . .. .20ContaminationofFluids.... ..... . . ... ..... ..... ....21MudChannel... ............. . .......... ...22Bridging .. .23LossofBottomJoints...... ...... .... . . .. .. .... . ...23SaltFlow .23Gas Flow. . . . .. . . . . . . . . . . . . . . . . .. . . .. . . .. . . . . .. . . . . . .. . . . . .. . . .24SeparationofFreeWater... ... .... .... ..... ..... . ..25Buckling of Pipe. .. . . . . . . . . . . . . . . . . . .. . . .. . . .. . . . . . . . . . . . . .. . . .26

Mechanical Cementing Aids...... .28Centralizers .. .. . . . .. . . .. . .. . .. . .. . .. .. . .. .. . .. . . . . . . . .. . ..28API STD10D .29Cement Baskets .31Stop Collars .31Scratchers .31Well bore Wipers , .32Hydro-Bonders........ . .............. .....32RecommendedInstallation Patterns.. . . .. . . ... . . .. . . ... . . .. .33CentralizerPlacementCalculation.... . . .. . . ... . . .. .33Float Equipment.. . . .. . . . .. . . . .. . . ... . . .. . . . .. . . ... . .. .35Wiper Plugs.. . . .. .. .. . . . .. . . . .. . . .. . . . .. . . .. . . .. . . . .. . . .. . . . ..36StageTools. .. . . .. .. . .. . . .. . . . .. . . . .. . .. .. . .. .. .. . . . .. . . .. . . . ..36External CasingPackers. .. . . . .. . . . .. . . .. . . . .. . . . . . . .. . . .. .. . ..37Liner Hangers.. . .. . . . .. . . . .. . .. . . . .. . . .. . . . .. . . . .. . .. .. .. .. . ..37Cementing Heads... . . .. . . . .. . .. . . . .. . . .. . . . .. . . . .. . .. .. .. .. . ..37

Casi"g Running Procedures ... .38Assignment of Responsibilities . ..... ... . . . ... .... .... ...38EquipmentCheck..... ... .. .... ......... ............. ......38The Cement Job. . . . .. . . .. . . ... . ... . . . . . . . .. . . .. . . ... . . .. . . . .. .39Displacement. . . . . . . .. . . . . . . ... . ... . . . . . . . .. . . . .. . . ... . . .. .39Pipe Movement. . . . . .. . . . . . . . .. . . . .. . . .. . . .. . . . .. . . .. . . . . . . . . . .40

Contact Time. . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . .40Landing Practices... . . .. . .. . . . .. . . ... . . . .. . .. . . . .. . . ... . . ..40

Evaluation of Cementation ..41TemperatureSurvey... ...41Radioactivity Tracer Log. . . .. . .. . . . .. . . .. . . . .. . . . .. . .. . . . .. . . . .41Acoustic Logs.. 41CBL/VDL .41CET .43RecommendedJob Documentation.. . . . . . . . .. . . ... . .. . . . .. . . . .. .44

Case Histories. . .. . . . .. . . .. . ... . . . .. . . .. . ... . . ... . . . . . . ... . .45

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The goal of this handbook ISto provide informationcovering the newest technology and products to serveprimary cementation requirements. Weatherford has spentin excessof thirty years developing its technological basefor training personnel and producing the best primarycementation aids on the market.

When an engineer asks how he can best complete hiswell, all his efforts depend upon a successful "primary"cementation. Assuming cement composition andrheological properties are correct, the most common causeof primary cementation failures is inadequate or incorrectuse of cementation aids and technique. Weatherford cansolve both of these problems by providing a detailedplanning programme for primary cementations, startingwith the surface string and extending all the way to theproduction liner or casing.

Weatherford will assist in planning and supervisingprimary cementations. Discussions between the operatorand Weatherford's cementing engineer are encouraged,and if requested, written proposals containing drawings,explanations and recommendations will be submitted.

Subjects to consider in planning for the entire primarycementing are comprehensive. They cover the following:Area: Factors of influence.

Wellbore: Diameter, depth, temperature, deviation,formation properties.

Drilling fluid: Type, properties, weight, compatibilitywith cement.

Casing: Design, size, type of thread, grade ofsteel, setting depth, floating equipment,centralizers, scratchers, stage tools,circulating swages.

Rig operation: Duration and rate of placing casing,circulation time before cementing, pipemovement.

Review previouscementations

New trendsand methods

Technicaladvancesinmaterials

REVIEW

Compare withprevious jobs

Long termwell perfotmance

Long termcost analysis

Find reasonsfor failures

Primary Cementing Engineering

Cementcomposition:

Mixing andpumping units:Personnel:

Cementingtechniques:

Type, volume, weight, flow properties,additives, mixing, influence of fieldwater.

Type of mixer, type of cementing head,plugs, spacers, displacing fluids.Responsibilities of involved parties.Pipe movement during and aftercirculation and placement of cement, useof spacers, rheological programme.

The planning stage covering mechanical cementingaids requires information from the customer for athorough evaluation, such as:

. Casing program (physical properties of pipe).

. Mud program (weights and rheological properties).

. Case history of area (washouts, gas, lithology, etc.).

. Deviation data (single or multishot data).

. Expected type of productive zone.

. Customer's intention towards "pipe movement"(rotation/reciprocation).

To summarize, the planning stage of a primarycementation is based on a

. review of previous cementations,

. regard for new technology,

. consideration for advances in materials and

. an analysis of anticipated costs.The actual operation requires a pre-check of equipmentand materials to be used. Qualified supervision andkeeping of accurate records are essential.

The reviewprocedure should include long term wellperformance and cost analysis as well as reasons forcementing failures.

PLAN

Cost analysis

PERFORM

Pre-check

QualifiedsupervisionAccuraterecords

Final check

1

Reasons for Cementing Casing

Oil well cementing is the process of mixing anddisplacing a cement slurry down the casing and backthrough the annular space behind the pipe. When setting,the cement will establish a bond between the pipe and theformation. No other operation in the drilling process ismore important to the producing life of the well than asuccessfulprimary cementingjob.

Many factors determine the successor failure of aprimary cementing operation. Because a seeminglysimplecasing job can become complex, each single operationshould be properly planned.

There are many reasons for cementing casing:. To support axial casing load.. To bond pipe to formation and to restrict t1uid

movement between formations.The cementation also aids in:

. Reinforcing the casing.

. Protecting the casing from corrosion.

. Preventing blowouts by forming a seal in the annulus.

. Protecting the casing from shock loads when drillingdeeper.

. Sealing off lost-circulation zones or other troublesomeformations.

Axial LoadHigh axial loads can be imposed on the casing string

and/or surrounding cement by landing and suspensionmethods and later operations.

The cement strength required to support such axialcasing loads can be determined through shear bond tests.tests.

Axial casing loads were found to be proportional tothe area of contact between cement and the casing.Therefore, support coefficient, shear bond or slidingresistance, as it is described by various inverstigators, is theload required to break the bond, divided by the surfacearea between cement and pipe.

Force required toinitiate movement

Core

Cement

Mud CakeContact Area

ForceContact Area

Fig. 1 Shear Bond Test.

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This test (Fig. 1) simulates the shear or mechanicalbond of cement to formation and casing. It is obvious thata remaining mud cake has a substantial impact on thebond strength. The force required to move the cementdecreases with an increasing filter cake.

Various factors affect cement shear bond performancewith respect to axial load:. Low water-to-cement ratios that increase slurry density.. Oil-based mud wetting of the pipe, which lowers shear

bond to a greater extent than water-based mud wetting.. Cement contamination by mud, which lowers

compressive strength and therefore shear bond.. Displacement mechanics and efficiency,which affect

thickness and continuity of the cement sheath aroundthe casing.

. Pressure/temperature effects,which can contract thecasing diameter after the cement hardens. Cementhydration is an exothermal reaction creating greatercasing expansion until the reaction is complete, afterwhich cooling allows shrinkage, that may break thebond to the pipe.

. Cement will not bond to the pipe unless the surface iswater wet and mill varnish is removed.

Zone IsolationAlthough cement with low compressive strength may

be adequate to handle axial and radial casing loads, highultimate strength may be required for zone isolation. Zoneisolation depends, in part, on load interactions betweenformation, cement and casing. Difficulty arises indetermining type and magnitude of loads imposed by fluidpressure and drawdown and depletion of formations.

For these reasons, only quantitative judgments havebeen attempted, and these usually relate to the "hydraulicbond" which indicates adhesion between casing andcement, or between cement and formation.

Hydraulic pressureto initiate leakage

Resin

Core

Cement

MudCake

Core

Hydraulic Bond: Pressure when leakage initiated

Fig. 2 Hydraulic Bond Test.

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Hydraulic bond is defined as the resistance of thecement between pipe and formation which prevents fluidcommunication. Tests have been conducted to examine thehydraulic bond between cement and formation.

This bond strength was found to depend on thedegree of contact between cement and formation. Thehydraulic bond was determined when pressure was appliedthrough a nipple mounted in the center of the core. Whena mud cake was present between cement and formation,bond strength was greatly reduced in all cases examined.Various investigators have measured hydraulic bond.Pressure is applied to the exterior surface of the casing,causing the casing to become smaller in diameter and "pullaway" from the cement, forming a micro-annulus whichpermits leakage (Fig. 2).

Pressure applied internally expands the pipe and alsocauses bond failure. Most casing pressure tests areconducted before maximum compressive strength of thecement is reached. Some operators have even run CBLswhile casing is internally pressurised in order tocompensate for a micro-annulus. Cement bond logs haveshown good bond before pressure test and poorer bondsafter pressure test.

Reasons for Cementing Casing

CorrosionCorrosion of oil well tubulars should not be

underestimated. In most cases, it is an electro-chemicalprocess. This means that there is an electrical current flowbetween two different metals. Free water in the annulusacts as an electrolyte, which increases in conductivity asthe amount of dissolved salt and/or metal ions increases.Gas in the wellbore can also contribute to corrosionembrittlement through a sour gas (H2S)environment.

Blowout PreventionSealing off the annulus is a must for wellcontrol

during the drilling process. Uneven setting of cementcauses bridging, thus reducing the hydrostatic pressure onthe formations below.

The faster the initial setting time passes, or the longerthe full hydrostatic pressure can be maintained during thesetting phase, the less likely are hydrocarbons or otherfluids to migrate through the cement. This migration cancause severe problems, even blowouts.

3

Casing String Design

Casing strings for average well conditions aredesigned to withstand th,reeprincipal forces: collapse,tension and burst. Principles are describedcomprehensively in API Standards 5.

Casing strings are frequently composed of tubes withdifferent weights and grades, as the strength of the casingstring must be considered during running, landing andcementing.

Depth IFormationl

FracturingPressure

Fig. 3 Casing Design Criteria.

The design can be based on full or empty pipe. Theapplication depends on company experience and policy.

TensionEach section of the casing must be evaluated for

tensile or compressive loading. Biaxial effects of tensileloading on burst and collapse can also be significant interms of potentially underdesigned sections. Cost savingsmay be achieved by using the biaxial effects to select less-expensive, lower-strength pipe.

Casing YieldStrength

API Joint Strength

Fig. 4 Tension Analysis.

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Tension loads are defined by computing the buoyantforces acting on the pipe and the pipe weight. The buoyantforces are defined as the product of the wellbore fluidpressures acting on horizontal cross-sectional areas. Forcesacting on the vertical sections of the casing are considerednegligible since the inside and outside forces cancel(approximately) each other. The buoyant forces and pipeweights are usually evaluated graphically. The example inFig. 4 illustrates the procedures for determining the tensileloads in a casing string.

CollapseThe primary collapse load depends upon the fluids.on

the outside of the casing, usually mud or the cement inwhich the casing was set. In calculating the primarycollapse load, backup fluids within the pipe are consideredto be negligible, as though a complete loss of mud insidethe pipe had occurred.

0+ Pressure.!I.-----..!.~

Casing

Formation External I)Mud ~ (May be equa

~~~. Cementc"- (Mayi$:. reinforcel

~1---C!l..sl!!~LL_-

Fig. 5 Collapse Analysis.

Of course, collapse can also occur when some loss ofinternal mud provides only partial support of the pipe.Collapse loads are computed in the same manner as burstloads.

o Pressure_.~-----

Surface" String

Casing BurstingStrength

FormationPressure

Fig. 6 Burst Analysis.

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BurstBurst loads on the casing must be evaluated to ensure

that internal yield resistance of the pipe is not exceeded.These loads are normally caused by mud hydrostaticpressure inside the casing and perhaps some surfacepressure. Backup fluids on the outside of the casing supplya hydrostatic pressure that helps resist pipe burst. Theresulting effective burst pressure is the internal pipe loadminus any external pressure. This net burst pressure istermed the resultant (Fig. 6).

Casing Safety FactorsDesign factors are established because the multitude

of stresseson a casing string cannot be accuratelyevaluated and some margin for error is needed to ensure acompetent string. Casing design factors recommended byAPI Standard 5A are:Collapse: 1.0on API minimum values, assuming

the inside of the casing is completelyempty of any fluid, even gas.1.6on minimum parting load of theconnections or pipe body, whichever isless.API or manufacturer supplies thisinformation.1.1on minimum internal yield pressure.Many companies use safety factors thatdiffer from those established by API.

The performance data of casing and tubing in APIStandard 5A are based on the physical properties of steelfrom which the casing is produced (Fig. 7).

Tension:

Burst:Note:

'0.75 sq. in. area and greater

Fig. 7 Physical Properties of Tubular Goods.

Casing StringsA typical casing program consists of various strings

with diminishing outer diameters. They are describedbelow:

Conductor pipe is set to establish the circulationsystem. It also prevents washing out around the rig base,and it can provide a base for blowout preventers. Further,it may be used to support some of the wellhead load.If not driven, this string is cemented to the surface.

Casing String Design

Surface casing is used to seal off problem sections ofthe upper part of the hole, to provide support for thewellhead, and to provide blowout protection incombination with blowout preventers. Depth can rangefrom a couple of hundred to several thousand feet.

This casing is usually cemented to the surface.Precautions have to be taken to prevent the loss of bottomjoints by strengthening the lower connections by usingthread locking compound, using two plugs, using both aguide shoe and float collar, centralizing the pipe, andreinforcing the pipe/cement column.

Type Casing

Conductor Casing

Surface Casing

Intermediate Casing

Liner

Cement

Fig. 8 Casing Program.

Intermediate casing is a protective casing used to sealoff weak or sloughing zones that might otherwise befractured by heavy muds used to drill deeper. Conversely,this string serves to isolate high pressure zones, so lighterdrilling fluid can be used for drilling deeper zones.Intermediate casing is also used to isolate corrosive water.It can be set as a liner as well.

Drilling deeper wells can create the need for morethan one intermediate casing string. As a result, drillinghas to start with a large bit size to allow more casingstrings to be set.

Production casing, in addition to the borehole supportfunction, is run to prevent interzonal flow while producingfrom or injecting into different production intervals.

In many areas production casing is set as liner first,and later is extended to the surface. A good cementation isof utmost importance.

As a rule, all casing strings are cemented. Wherebyone has to differentiate between primary and secondarycementing jobs (squeeze cementing). The techniques to beapplied for primary cementation depend on therequirements and are described in the following section.

5

MinimumElongation

Grade of YieldStrength Tensile Strength of 2-in. StripCasing + (psi) (psi) Specimens.1\Jbing Minimum Maximum Minimum Maximum (percent)

H-40 40,000 - 60,000 - 29.5J-55 55,000 80,000 75,000 - 24.0K-55 55,000 80,000 95,000 - 19.5C-75 75,000 90,000 95,000 - 19.5N-80 80,000 110,000 100,000 - 18.5C-95 95,000 110,000 105,000P-110 110,000 140,000 125,000 - 15.0Q-125 125,000 140,000 135,000 - 14.0

Cementing Techniques

Primary CementationIn the conventional method of cementing casing,

cement slurry is pumped down the pipe, followed by acementing plug that seats on a cementing shoe or collarinstalled one or severaljoints off bottom.

Conventional casing cementing uses a float shoe onbottom and a float collar above to allow plugs to seat(Fig. 9a I).

Cementing larger diameters takes much time and cancause pipe collapse due to excessivehigh differentialpressures encountered during the displacement process.

Cementingthrough Drill PipeAn alternative method for cementing large diameter

casing uses drill pipe for pumping cement slurry to thebottom. Cementing through drill pipe is accomplished bysealing a drill pipe stinger sub in a special cementing collarwith a drillable sealing receptacle (Fig. 9a 3). There aresome advantages in this method. It features low internalpressure, better displacement control and time savings inthe cementingjob because less mud has to be displaced.

_ Cement c=J Mud

Fig. 9a Placement Techniques.

Cement LostTo Weak Zone

Fig. 9b Placement Techniques.

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..

Stage CementingStage cementing is required for wells having critical

fracture gradients. Several stages can be set depending onthe number of critical formations. Special equipment isrequired (Fig. 9a 2). (See more details under sectiondownhole cementing equipment.)

Liner CementingA liner is a string of casing that is used to case-off the

open hole below an existing casing string, and which doesnot extend up to the surface.

Liner cementing is one of the most difficult operationswhen completing a well. If a liner is not effectivelycemented, the well's capability to produce can be reduced.A liner is normally run on drill pipe that extends from theliner setting tool to the surface.

The liner hanger is installed at the top of the liner.Hangers are usually classified by the method used tosecure them in place: mechanical or hydraulic. They aresometimes used in conjuction with a packer system.

Small annular clearance is the primary problem inliner operations. High pressure lossesduring circulationand cement placement increase the possibility of lostcirculation.

PIU9D"PP;ng

~Head __

y-C~~if~:d9

. -:::;;::;-r;;r.

[Line~~~:""k

SettingTool---JJH NIf

r r:t~~:~:~~~ional)Hanger

Liner Centralizers

i' ~ 1: LendingCo""

Float Collar

~~Float Shoe

'"

Fig. 10 Liner Cementation

Small annular clearances as often experiencedbetween liner and open hole, do not facilitate muddisplacement. Thus cement channeling or mud bypassingis most likely under these circumstances. A way to increaseclearance is to re-design the casing program and drill largerholes for a given liner size or, conversely, run smallerliners,noneof which- undermostcircumstances- isfeasible.

Another solution is to under-ream the open hole.However, selectivelyunder-reamed sections can be similarto borehole washouts, making effectivecementing moredifficult.

.Weatherford

Centralizing the liner in the hole is very critical toeffectivecement placement. This is particularly true indeviated holes. The small annular clearance between linerand open hole needs a careful selection of the right typeand design of centralizers. They also reduce the likelihoodof differential pressure sticking between liner and openhole. This makes it easier to reciprocate or rotate the lineronce it is in place.

ReverseCirculation CementingThe reverse circulation cementing technique involves

pumping the cement slurry down the annulus anddisplacing the mud back up through the casing. To do this,the float equipment and wellhead assembly must bemodified. Care should be taken so that none of the cementremains in the surface installation after pumping.

Open Hole Cement PlugsThere are several reasons for performing plugging

operations:a) Abandon a dry or depleted well.b) Change hole direction.c) Plug back the well.d) Combat a lost circulation problem.

Each plugging operation presents a problem becausea relativelysmall volume of cement slurry is surrounded bya large volume of wellbore fluid.

It is important that plug placement be successfulonthe first try because of the expense of drilling out a badplug and reconditioning the mud, as well as the cost ofmaterial and servicesto place a subsequent plug.

Plugging and Abandoning Sidetracking

SurfaceHole ~ ~~:iJr::.:..:.. Surface ~~: Thebitisdirectedagain.st;:-'t;:. :"~q Plug I:.':'~: (S'.c;! both the high compresSIVe

Surface Casing 0 : p::( ;~~\ ~D.:, strengthcem~ntplugandthe;.' ":. ::.o.:~ :$:}:"Q: ~..t:l ~ofter.f~rmatI0n;the.result

Pi C ment~' ~:~:::...(7.',0 9...:'.~ C"'( ISa drdhng of formation away

Imary e . ~~,\\*1\~2, ~~~~~e ~~.~ ~~ Irom the previous wellbore.Non Productive Hole '(1.:£ '~~.~:~Protective 6?o i::.:~~~:~.( Firm cement set in

::> :).. .:. Plug i:.; ~. 1\7-.( openholetobypass:.t?:Q ,.~~ C.: ",:,~,:"1. Unrecoverablejunk0~"""ii~~~? . -:! j', .:o.~'.~ 2. Un~es.irab.ledirection\-~.~.n;. Isolatton ~ )'.~:~."'S Orlnchnatlon

i.O~!'lug .:;. -.~~fs.:.o'~ InTop ~.:',J.V"o'";~': ofC.ut ~ ;.:\~ ~~:<,...~Casing t: .Q..8 .....

~~..~i~~

a

Fig. 11 Cement Plugs a-b.

b

Delayed-setCementingThis technique is being used in tubingless completion:

the slurry is placed at the desired depth and multipletubing strings are lowered into the unset cement. Thedelayed-set cement slurry allows prolonged reciprocationof the production string, which is more likely to assure auniform cement sheath.

A disadvantage is that the cement slurry requires aconsiderably longer Waiting on Cement (WOC) time thanconventional slurries.


Combating LostCirculation

Sealing CasingSeat

Fig. 12 Cement Plugs c-d.

Secondary CementationSqueezecementing is the process of forcing a cement

slurry through holes in the casing into the annulus. Theprimary objective in squeeze cementing is to develop a sealin the wellbore between formation intervals that duringproduction tests have shown signs of detrimentalcommunication.

$jt,Prim.ry

Cementing

Fig. 13 Squeeze Cementing.

Squeeze cementing may be used:. To correct a defective primary cementing job. Problems

resulting from channelling or insufficient fillup on theprimary cementing job are often overcome by squeezecementing.

. To control water flow. Water can be squeezed off belowthe oil sand to help decrease water/oil ratios.

. To repair casing leaks. Cement can be used to repairleaks due to wear or corrosion.

7


. To control high GaR's. By isolating the oil zone froman adjacent gas zone, the GaR can usually beimproved, which will help increase oil production if thevertical permeability is negligible.

. To abandon a specificzone.

A typical application for a squeeze operation is thepacker set above perforations to control pressures andflow of cement slurry to the formation, as in the followingexample of a water/oil/gas contact. This well faces theprospect of possible water coning and gas ingression.

CBl Over Gas-Oil-WaterContactsSP150 Bond Log 201140 <1\.0Ii: 40

Weatherford

AFTER7 DAYS: CEMENT:SL0-5ET59 BOPD 8% GEL

6644 GOR 51 HRS.1900 PSI 4' SPACING

1670 F

Fig. 14 CBL over Gas-ail-Water Contacts.

The oil zone (Fig. 14)was perforated four feet fromthe gas contact at the top and three feet from the watercontact at the bottom. Initial production was 162barrelsof oil per day with a 463 gas/oil ratio and 640 psi flowingpressure. After sevendays, production dropped to 59barrels of oil per day with 6644 gas/oil ratio and 1900psiflowing pressure, which confirms the poor cementationover the gas/oil contact.

High-pressuresqueezecementing is defined as a job inwhich working pressure in the wellbore exceeds formationfraction pressure prior to or during the time that cementslurry is in contact with the formation and wellbore.

After the formation is fractured, cement is displacedand follows fluid from the channels into the fracture.

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Cement is deposited in the channels between perforationsand the fracture.

During a high-pressure squeeze there is no control ofeither location or orientation of the generated fracture.The fracture will result perpendicular to the weaker of thetwo stress planes.

Fig. 15illustrates the effect of well depth and vertical/horizontal formation stresses on the type of hydraulicfracture induced by injected fluid.

Horizontal fractures will not be created if fracturepressure is less than overburden pressure. Formationfracturing during high-pressure squeezing may be counter-productive, as fractures induced in formations deeper thanapproximately 3000ft are nearly always vertical. Thus,even if the casing wellbore annulus were sealed, fracturingmay establish vertical communications between zones.

Wellbore Frac. Press., PF

Vertical Stress, 0,

Horizontal

Stress, 0H,

Induced HorizontalFracture

Induced VerticalFracture

PF~aH1or 0H2;.GH,orUH2<GV

Fig. 15 Effect of Well Depth on Fracturing.

Low-pressuresqueezecementing is defined as a job inwhich the working pressure in the wellbore is maintainedbelow the fracture pressure of exposed formations prior toand during the time slurry is in contact with the wellbore.

Squeeze cementing is only a remedial tool. It cannotbe considered as a planned supplement to primarycementing. Careful design and execution of primarycementing is a much better way to get zone isolation thanrelying on high-pressure "block squeezing" above andbelow the pay. High-pressure block squeezing may, insome cases, increase communication between zones, whichmay permanently damage the payzone with cementfiltrate.

.Weatherford

The channeling of cement slurry through mud is acommon cause of poor quality primary cementing jobs.

Mud displacement depends on a great manyparameters, none of which can be ignored: annulusgeometry (diameter, eccentricity, inclination, depth);spacer and slurry volumes; flow rates; properties of eachfluid (mud, spacer, slurry) including density, flowcharacteristics and thixotrophy; pump shutdowns duringwhich the gel strength can increase; and casingmovement.

The experimental study of this problem requiresgreat care in interpreting the results.

Consequently, for a better understanding of thecomplexity of cementations in the following section, therheology of drilling fluids and cement slurries are brieflydescribed and the chemistry of oil well cements andadditives in use are comprehensively discussed.

Rheology of FluidsTwo basic resisting forces associated with drilling

mud displacement during primary cementing aredifferential pressure and cement-mud (fluid-fluid) dragforces. To effectivelydisplace muds, oil well cements mustexert a combination of differential pressures and dragforces of sufficient magnitude to overcome the forcesresisting displacement.

The resisting pressure is related to properties of themud, i.e. density and gel strength. The resisting drag forcesare a function of mud gel strength and viscosity plusdistance betweencasing and borehole wall (see Fig. 40).Drilling mud and cement slurry fluid properties vary in thewellbore due to lack of uniform make-up and temperature/pressure effects.Annular flow area also varies as a result ofdecentralized casing, washouts, unremoved filter cake,directional changes, formation swelling,etc.

A fluid is said to be thixotropic if it is thin whenmixed or shaken, gelswhen it is allowed to stand for ashort period and then becomes thin again when subjectedto shear.

Yield point (expressed in lbf/100ft2),is a measurementof the attractive forces that exist between the particles of agiven fluid while under flow conditions. It is a dynamicproperty of the fluid.

Gel strength is a measure of the attractive forcesbetween the particles of a fluid when under static (non-flowing) conditions. The fluid should be left to stand for aperiod to attain gel structure.

To measure gel strength, the slurry is mixed, pouredin a Fann V-G cup and then stirred at 600 rpm for 10seconds. The viscometer is then stopped and the slurryallowed to stand. After 10seconds, the viscometer isrestarted at 3 rpm and the maximum dial readingrecorded. Similar readings are taken after one minute and10minutes.

Cements and Additives

The measurements taken are referred to as the 'initialgel strength', the 'one minute gel strength' and the'10 minute gel strength' respectively.

Drag force from casingmovement (pos.)

Drag force, mud on wall (neg.)

Cement slurry

CasingEccentric annulus in open hole

Differential pressure movingcement also acts on mud (pos.)

Pressure due to mudcolumn weight (neg.)

Drag force, cement on mud (pos.)

By-passed mud channel

Buoyancy effect ofdenser cement (pos.)

Fig. 16 Forces Affecting Mud Displacement

The flow behaviour of a fluid is defined by therelationship between flow rate (shear rate) and pressure(shear stress) that causes the movement.

There are two basic fluid types. Newtonian and non-Newtonian. Newtonian fluids, such as water, exhibit astraightline relation between flow rate (shear rate) andpressure (shear stress), while the fluid is in laminar flow(Fig. 17).A Newtonian fluid begins to flow when pressureis applied. As pressure increases, flow velocity increasesfrom laminar, through a transition zone (part laminar andpart turbulent) to fully developed turbulent.

Laminar

Flow Regimes

Turbulent

TransitionZone

~ Intercept at Origin

Flow, BPM (Shear Rale)

Fig. 17 Flow Regimes of Newtonian Fluid.

Non-Newtonian fluids, such as muds and cementslurries, are more complex: they may exhibit resistance toflow (gel strength) when pressure is applied (Fig. 18).Fluids with gel strength can flow at very low rates in asolid or plug-like manner. Non-Newtonian fluids thus canhave three flow regimesplug, laminar and turbulent -with transition zones between each.

9


" FlowBegins (Gel Strength) NoAow

Row Regimes

Turbulent

Transition

Laminar

TransitionPlug

Flow. BPM (Shear Rate)

Fig. 18 Flow Regimes of Non-Newtonian Fluid.

Mathematical ModelsThe two mathematical models commonly used in

describing the behaviour of such fluids are the Binghammodel, for Bingham plastic fluids and the Power Lawmodel, for pseudoplastic fluids.

Bingham Plastic FluidsBingham fluids are fluids which are compatible with

the model respresented by the equation:

,= ,y + IlP(- dvjdr)Where: , = shear stress

'y = Bingham yield valueIIp = plastic viscosity

(- dvjdr) = shearrate.Experimental results have confirmed that this model onlyapplies where the fluid is in laminar flow regime.

The distinguishing characteristic of a Bingham plasticfluid is that it will remain static until the applied forcebuilds up to the point where it starts to move.

Two parameters define the Bingham plastic model:. The value oft for dv/dr = 0, 'y.· The slope of the straight line, IIp'

In the laminar flow regime IIpis constant and istermed plastic viscosity, while apparent viscosity, definedas the ratio

shear stress/shear ratedecreases as the shear rate increases.

PseudoplasticFluidsPseudoplastic fluids are, like Newtonian fluids, purely

viscous, yet comply to the Power Law model representedby the equation:

, = K' (- dv/dr)"'where:

, = shear stress

K' = consistency indexn' = flow behaviour index

(+ dv/dr) = shear rate.

10

.Weatherford

This model only applies where a laminar flow regimeis prevalent.

The fluid starts to flow, in the likeness of a Newtonianfluid, as soon as initial pressure is applied, but does notexhibit the characteristic Newtonian proportionalitybetween shear stress and shear rate.

PlugFlow

TurbulentFlow

LaminarFlow

IIIIIIII

t PI8S\\C,,\scos\\'l fLPIIIIIII

BinghamYield

TY

TrueValueYield

II

J.la = ApparentViscosityiII

Fig. 19 Determination of Rheological Properties.

ReynoldsNumberThe nature of a fluid's flow pattern (plug, laminar,

turbulent) is dependent on fluid velocity and fluidproperties.

The criterion used to predict whether the flow will beplug, laminar or turbulent is known as the Reynoldsnumber. This is a dimensionless number defined by:

NRe = pvD/Il.With the Reynolds number being dimensionless, any

consistent system of units may be used to obtain the samenumerical values. Thus: In the imperial system:

p = fluid density in Ib/ft3v = average velocity in ft/sec

D = diameter in ft

Il = fluidviscosityin lb/ft sec.In the metric SI system:

p = is in kg/m3v = is in m/s

D = is in m

11= is in Pa sec.More detailed information about flow patterns are

given in conjunction with the chapter "cementingproblems".

Properties of Cement"Neat" oilwellcement- the basicpowdered

material, without additives - is commonly called"Portland Cement", after the small town in England whereit was first made. It is manufactured from limestone, clay,sand and iron ore, which are finely ground and blended,then fired in a rotary kiln to about 2600°F. These materials

.Weatherford

melt and bake into glass-likeballs or clinkers of complexcalcium silicate which then are re-ground together withgypsum.

Portland cement consists primarily of: tricalciumsilicate,dicalcium silicate, tricalcium aluminate andtetracalcium aluminoferrite. In addition, it contains freegypsum, magnesia (MgO) and lime (CaO), Fig 20.

The percentage of these components in the final blendcan affect early strength, sulfate resistance, hydration,swellingor cracking during cure and the progressive growthtoward final compressive strength. API has establishedclassesof cement with maximum percentages of the abovechemical components designated - water addition,fineness,minimum thickening time, minimum compressivestrength and free water content. Because of this variety offactors, a cementingjob can be tailored to a wide range ofneeds.

Limestone Clay, Fe- and AI-Oxydes(High Calcium carbonate content) (Ifnot sufficiently in Clay)

Clinker

}

Gy~sum CaSO..2 H,O) =Portland Cement1.5-3.0 wt %(controls rate of setting andhardening of cement paste)

Composition of Cement

.3 CaO.SiO,

.2 CaO.SiO,Prevalent-Principal strength producing material.

Slow hydrating compound-Small, gradual gainof strength over extended period of time.

Promotes rapid hydration-Controls initial set andthickening time-High sulphate res. cem. ,;3%

Low heat of hydration.

Waterrequirementsvarywith finenessof grindorsurfacearea.

.3 CaO.AI,O,

.4 CaO.AI,O,.Fe,O,

Fig. 20 Manufacture of Cement.

Factors affecting cement slurry design and operatingperformance are:

. Welldepth.

. Welltemperature

. Holesize.

. Mud-columnpressure.

. Viscosityand watercontentof cementslurries.

. Pumping or thickening time.

. Strength of cement required to support pipe.

. Quality of available mix water.

. Type of drilling fluid and drilling fluid additives.

. Slurry density.

. Heat of hydration

. Permeability of set cement.

. Filtration control

. Resistance to brines.

. Flow regime.

. Solubleformations.

. Porepressureof formation/permeability.

. Mud compatibility with cement or spacers.

. Yield point differential between mud and cement.


. Friction pressure/fracture pressure.

. Weight differential between mud and cement.

The two most critical influences on the downholeperformance of cement slurries are temperature andpressure. They determine how long the slurry will bepumpable and how well it develops the strength necessaryto support pipe.

Pressure imposed on a cement slurry by thehydrostatic load of well fluids also reduces the pumpabilityof cement, mainly due to fluid loss to permeableformations.

10

API Class as Noted

8

I!!.<::<Ii6EF0>c'c~ 4":cI-

2at atmosphericpressure

Temp. of 40Temp°C 4.4

10037.8

18082.2

12048.9

14060.0

16071.1

6015.5

8026.6

Fig. 21 Affect of temperature on thickening time.

Temperature has the more pronounced influence. Asthe formation temperature increases from bottom holecirculating to bottom hole static temperature, the cementslurry will hydrate more rapidly. As cement hydration isitself an exothermic reaction, the initial setting temperaturewill be higher than the bottom hole static temperature.This situation can enhance higher early strengthdevelopment. In operations with prolonged displacementtimes, thickening time can be significantly reduced. Fig. 21shows how temperature affects thickening time.

Temperature gradients vary in different geographicalareas. Estimates of bottom-hole static temperatures maybe obtained from surveys run during logging and fromdrillstem tests. Bottom-hole circulating temperatures areobtained from conditioning trips before casing is set. Thecooling effect of mud displacement lowers the circulationtemperature of the hole considerably during casingcementing.

Cement ClassificationCement classifications provided by API for nine

classes of cement allow for various pressure/temperatureconditions, early strength, sulfate resistance, adaptabilityto modification with accelerators and retarders as follows:

11

Cements and Additives.Weatherford

ClassDepth Range"

ft.

0-6,000

AvailableSulfate

Re~istanceCharacteristics,

Availability

Common (construction),widely availableSpecial (construction)High early strength,fine grind, widely avail.Coarse grind, retardedSame as DSame as DBasic cement, no chemical retarderBasic cement, coarse grind,no chemical retarderResists strength retrogression,min. temp. 230°F

*As manufactured. Basedon normal size cement job in well with geothermalgradient of 1.5°F per 100 feet.

A Ordinary

BC

0-6,0000-6,000

ModerateOrd., mod.,highMod., highMod., highMod., highMod., highModerate

DEFGH

6,000-10,00010,000-14,00010,000-16,000

0-8,0000-8,000

J 12,000-16,000 High

Fig. 22 API Cement Classes.

The classesG and H can be modified withaccelerators or retarders to cover a wide range of pressure/temperatureconditions- theyare the onesmostcommonly used.

Mixing WatersWater is added to the cement to make the slurry

pumpable and to provide for hydration (chemicalreaction). Ideally, the water supply for mixing cementshould be reasonably clean and free of dissolved chemicals,silt, organic matter, or other contaminants.

Inorganic materials (chlorides, sulphates, hydroxides,carbonates and bicarbonates) will accelerate the setting ofcement. Sea water also accelerates cement, while naturalwaters containing organic chemicals retard the setting ofPortland cement. The retarding properties of organiccontaminants are particularly detrimental in cementingsurface pipe and shallow holes. For best results, the waterto be used in mixing cement should be the purest available.

With regard to cementingjobs, three characteristicterms are used in the oilfield:

Normal water. is the amount of mixing water that will achieve a

consistency of II uc (units of consistency) as measuredon an atmospheric thickening time tester after 20minutes of stirring.

. is sometimes called Optimum Water, as it provides agood pumpable slurry.

Minimum water. is the amount of mixing water that will give a

consistency of 30 uc after 20 minutes of stirring (about25% by weight of cement).

Maximum water. should not exceed the amount of mixing water for any

given cementing composition that will give a set volumeequal to the slurry volume, with 1.5% or less free waterseparating (seealso API spec's).

It should be emphasised that excesswater alwaysproduces a weaker cement with lower resistance tocorrosion, and with higher permeability.

12

Fig. 23 shows the water/cement ratios as per APIspecification.

Percent Gals. Water SlurryClass Water Per Sack Den., ppg"

A 46 5.19 15.6B 46 5.19 15.6C 56 6.32 14.8D 38 4.28 16.4E 38 4.28 16.4F 38 4.28 16.4G 44 4.96 15.8H 38 4.28 16.4J 38-43.5 4.28-4.91 16.0-15.4

"Based on absolute vol. per sack cement equal 3.59 gals.

Slurry Yield,ft'/sk'

1.171.171.321.051.051.051.141.05

1.09-1.17

Fig. 23 Neat Cement Slurries.

Normal water content differs for various classes ofcement according to fineness and sphericality of grind.Excess water should be avoided to prevent loss to theformation.

Care should be taken to add the proper amount ofwater for the cement to be used. For example, Class H issometimes inadvertently handled like Class A, and theresulting mix has reduced strength, retarded thickeningtime and excessivefree water. Most cementing units carrydevices that control the density of the slurry; otherwise it ismanually controlled.

Free water content is usually higher at increasedtemperature due to thinning, and lab tests at elevatedtemperature are sometimes required.

Free water can be minimised by:. limiting the amount of mix water.. adding bentonite in small quantities (reduces

compressive strength).. selecting and controlling quantity of other slurry

additives.

/B,OOO~ Hydration

Water

MinimumWater

4.000

No. Pumpable

30

PumpabJe-150

--'- --'40

WaterContent,%

Fig. 24 Compressive Strength vs. Water Content of Slurry.

The compressive strength of cement is reduced nearlyin proportion to the amount of water in the slurry.Approximate points for water required for hydration,"minimum" water and "maximum" water are indicated(Fig. 24) for class G cement.

An experiment conducted by Becker and Petersoninvestigated the effect of water-cement ratios on cementbonding to casing. The term "sliding resistance" was

.Weatherford

defined as a combination of shear bond and coefficient offriction, and this was plotted against various water-cementratios.

20

I Constr- Cern.\

'\API Class A Cement

SpGr = 3.14Weight = 94lbs1sackAbsolute Vol. = 3.6 gal/sackWater = 5.2 gal/sack (API)Slurry WI. = 15.61bslgal46% Optimum Wtr. Ratio

'........

I

APIClassE :

Cement :I II II II II II I

0.38 0.46

0.4 0.5 0.6 0.7

Water-Cement Factor (Weight %)

Fig. 25 Sliding Resistance vs. water-cement Factor.

--0.24I---'-

0.2 0.3 0.8 0.9

The results clearly show a decrease in slidingresistance as the water-cement factor increases, particularlyin the 35% to 50% range. Optimum water percentageswere established to insure satisfactory rheologicalproperties for pumping the cement slurry into theborehole. A water-cement ratio of about 40% by weightsatisfied this requirement.

It is interesting to note that the sliding resistance ofboth Class A and Class E cement is just about the same atthis optimum condition, although Class A cement reflects abetter sliding resistance than Class E over the entire range.

AdditivesAdditives are chemicals or ingredients added to the

cement to change its properties to meet well conditions.

The major cement additives are classified as follows:. Accelerators. Retarders. Densityadjusters. Dispersants. Fluid-lossadditives. Lost-circulationmaterials. Auxiliaryadditives. Fortifiersagainstretrogression.

AcceleratorsMost operators wait for cement to reach a minimum

compressive strength of 500 psi before resumingoperations. At temperatures below lOO°Fcommon cementmay require a day or two to develop this strength level.

Low concentrations of cement accelerators (2-4% byweight of cement) are used to shorten the setting time ofcement and promote rapid strength development, thusreducing waiting-on-cement (WOC) time. Calcium chlorideand sodium chloride are the most common accelerators.

The most widelyused accelerator in the industry,calcium chloride (CaCI2)is produced in white flakes,powder, and pellet forms which are 95% pure CaCI2.A


concentration of I % to 4% calcium chloride is normallyused.

RetardersIncreased welldepths and formation temperatures

require the use of cement retarders to extend thepumpability of cements. Most retarders also affect cementviscosity to some extent.

Lignosulfonates are used to about 200°F bottom-holecirculating temperature (BHCT). Concentrations of 0.1%to 1% are used in most slurry applications to give bothpredictable thickening times and compressive strength.Amounts above I% do not appreciably add to slurryretardation.

Organic acids can be used from about 200°-400°FBHCT. They are used on concentrations of 0.1% to 2.5%by weight of cement as effectiveretarders for high-temperature environments.

Density AdjustersHigh-density slurries are used to cement high-pressur;;:

wellswhere increased hydrostatic head is required to holddown gas or fluids.. Hematite, sp. gr. of 5, is used to increase slurry density

to 211b/gal. Barite, sp. gr. 4.2 can increase slurry weightto 18Ib/gal.

. Sand, sp.gr. 2.65, has a low water requirement andhelps to densify slurries to 17.5Ib/gal.Lightweight cement slurries are used to reducehydrostatic pressure on weak formations and possiblyto lower slurry cost. Basically, lightweight slurries aremade by adding more water to lighten the mixture andthen adding materials to prevent settling.

. Bentonite clay can be used in concentrations up to 25%by weight of Portland cement to decrease the density.The water requirements for bentonite in cement are5.3% water added for each 1% bentonite.

Besidesfiller or lead slurries, bentonite slurries areoften used as lost-circulation cement.

Density may be increased with weight material suchas sand, barite, hematite or ilmenite, and/or salt dissolvedin the mix water, as shown in the following table:

Bentonite has for years been the most commonly usedadditive for "filler" type cement. In addition to its effecton density, yield and cost, bentonite increases viscosity andgel strength, which reduces settling of high density particles(weight material, cement) or floating of low densityparticles (perlites, pozzolan, gilsonite, crushed coal).

13

Max Extra Elf. on Elf. onSpecific Grind Density, Water Compo Pumping

Material Gravity (mesh) ppg Needed Strength Time

Ottawa sand 2.63 20-100 18 None None NoneBarite 4.25 325 19 20% Reduce ReduceCoarsebarite 4.00 16-80 20 None None NoneHematite 5.02 40-200 20 2% None NoneIlmenite 4.45 30-200 20 None None NoneDispersant - - 17.5 None Increase IncreaseSalt - - 18 - Reduce Varies

Fig. 26 Weight Material for Cement.


Bentonite also reduces API fluid loss. However,cements containing bentonite are more permeable, havereduced sulphate resistance and lower compressivestrength.

DispersantsDispersants reduce slurry viscosity, allow slurry

turbulence at lower pump rates, allow heavier slurries withless water and less weighing materials, and help providefluid-loss control for densified slurries. The most commondispersants are aryl-alkyl sulphonates used inconcentrations of 0.3% to 2% by weight of cement,polyphosphate, lignosulfonate, salt and organic acid.

Efficient mud removal is a benefit of slurries pumpedat turbulent flow rates. These rates are more easilyobtained through the use of dispersants because the slurryviscosity is less than with plain cement slurries.

Turbulent-flow additives tend to cause settling andexcessivefree water. These effects should be tested in thelab prior to field use.

Fluid-lossAdditivesFluid-loss additives improve primary cement jobs by

helping to:

. prevent cement dehydration in the annulus;

. prevent gas migration. The viscosity and gelationproperties of slurries containing fluid-loss additives helpto solve this problem;

. improve bonding. The bonding qualities of cementscontaining fluid-loss additives are also very good.

Fluid-loss additives normally are polymers. The mostcommon are cellulose derivates.

Normal concentrations of fluid-loss additives mayvary from 0.3% to 3% by weight of cement.

Lost-Circulation MaterialDrilling fluid or slurries can be lost to either natural

or induced formation fractures. These fluids may also belost through highly permeable formations - starting atabout 5 darcies for drilling fluid with a maximum particlesize of 0.002" (300 mesh). Cement with its larger particlesize (neat cement has 3%-18% particles larger than 200mesh) is less susceptible to loss in permeable formations.

During primary cementation, concentrations ofcoarse materials must be more carefully controlled toavoid bridging the casing or liner/borehole annulus, orplugging of downhole equipment such as bottom wiperplugs, small diameter stage tools and float equipment.

Lost-circulation materials for cement are classified asgranular or laminated material, and include ground coal,mica, cellophane flakes, perlite, fibres, cotton seed hulls,walnut shells and gravel.

SaltSalt (sodium chloride) is one of the most versatile

additives used in oil-wellcementing. It is used in both mud

14

.Weatherford

and cement to prevent shale from swellingand sloughinginto the hole. If the shale were allowed to slough, largecavities would be created. The concentration of salt isbased on the weight of the mix water. Depending upon theconcentration used in the water, salt may either accelerateor retard thickening time. As a general rule, 3% to 5% saltby weight of water is used for maximum acceleration, 18%to 20% results in a neutral response, and more than 20%results in retardation.

7

.;; 6a.oo~,5

~Iie 4<3

Curing Temperature

22.0 3.01.0

Salt Concentration, %

Fig. 27 Effect of Salt on Compressive Strength.

Fig. 27 shows the effect of salt on cement properties.Early compressive strength is increased by small saltconcentrations. Notice that higher compressive strength isobtained at low curing temperatures.

6

CONSISTOMETER DEPTH5

~ 4oje1='g> 3

ju~ 2

o1.0 2.0

Salt Concentration,%

3.0

Fig. 28 Effect of Salt on Thickening Time.

Small concentrations shorten thickening time, andthere is a broad range where the effect is minimal beforesalt begins to retard setting time (Fig. 28).

Salt cement is used extensively. Some importantcharacteristics of salt cement are listed:

.Weatherford Cements and Additives

. Osmotic pressure will cause water from sand or shale tomigrate to the salt cement causing expansion, whichimproves bonding.

. Salt cement is less disruptive to swellingclays, therebyminimising cleavage, softening or sloughing of shalebeds.

. Filtration from salt cement causes less damage toformations than fresh water.

. While salt is an accelerator in low concentrations and aretardant at high concentrations, its effect is neutralthroughout a broad range inbetween. This tolerancecan, in many cases, permit use of either fresh or seawater for mixing without affecting thickening time.

. Salt in small concentrations tends to increase earlycompressive strength, but has little or no effect onultimate strength. In high concentrations, it reducesearly strength and can cut ultimate strength in half.

. Salt can increase slurry weight by as much as 1.7 ppg.

. In the 3.5% range, salt reduces turbulence-critical-flowvelocity through dispersion; it also reduces viscosity. Athigher concentrations, over 18%, this effect is minorand some dispersants may not be effective. Organicacids such as citric acid aid in dispersing salt systemsabove 10%.

Properties of Set CementCement compressive strength increases as a function

of temperature, pressure and time to an ultimate valuethat depends on cement composition. Compressivestrength measurements are obtained on the basis of APIpressure/temperature/time schedules, for depths from1,000to 20,000 ft.

Usually, compressive strength is very close to ultimatewithin three days. Early strength is increased by additionof calcium chloride, sodium chloride, ammonium chloride,"minimum" water and heat. Early strength is decreased byaddition of bentonite, lignosulfonate, and "maximum"water.

Cement requires very little early strength to support astring of casing. Data indicate that alOft annular sheathof cement with only 8 psi tensile strength can support morethan 200 ft of casing, even under rather poor bondingconditions (disregarding the hydraulic bonding quality).

As a general rule, compressive strength isapproximately 8 to 10times greater than tensile; that is, the8 psi tensile strength would be equivalent to 80-100psicompressive strength.

It is generally accepted in the industry and byregulatory bodies that a compressive strength of 500 psi isadequate for most operations, and by using goodcementing practices an operator should be able to drill outsafely when adhering to this minimum strengthrequirement.

The following observations about the strength ofcement to support pipe are based on research and fieldexperience:. High cement strengths are not always required to

support casing during drill-out, and by increasing the

slurry density the time required to develop adequatecompressive strength can be decreased.. Cement slurries with excessivewater ratios result inweak set cement and therefore should be avoidedaround the lower portion of the string.

. By selecting the proper cement and applying goodcementing practices, WOC time for surface casing canbe reduced to 3-4 hours under normal operatingconditions.

Strength RetrogressionFour variables - composition, temperature, pressure

and time - affect compressive strength. At hightemperature, cement compositions may retrogress (losestrength) after reaching a high value.

This strength retrogression is accompanied byincreased cement permeability. For example, a neatretarded cement with 0.02+ md permeability at 290°Fafter three days may have 8+ md at 320°F after sevendays. Retarded cement for high temperature applicationand high water content cement seem particularly subject tostrength retrogression. For cement types used in deep and/or hot wells the phenomenon begins at around 260°F.Generally, complete strength retrogression has taken placewithin seven days. Although remaining compressivestrength may be adequate for many applications, additionof silica flour to the slurry provides a way to eliminate thephenomenon of retrogression. Deep wells and steamproduction/injection wellsshow the above symptom.

ExpansionSaturated salt cement, Pozzolan cement, Gypsum-

Portland blends and several other formulations expandduring setting, which helps eliminate the microannulus atthe cement/casing interface that could otherwise be createdby changes in pressure and temperature during theproduction of the well. Cement expansion may increase thethickness of a cement sheath by a few thousandths of aninch. However, cement expansion or contraction appearsto be of minor importance relative to the magnitude ofother downhole problems, such as inadequate muddisplacement, mud cake thickness, borehole elastic/plasticdeformation and cement loading conditions.

PermeabilitySet cements have very low permeabilities - much

lower than those of most producing formations. But acement slurry, once it dehydrates, goes through atransition stage having some permeability before setting.At this time, the cement in a certain section of the holedoes not exert the full load of its hydrostatic head ontopressured formations, allowing the latter partly to flow.There have been occasions when wells have blown out atthis stage of "instability".

FiltrationControlling filtrate in the cement slurry with the help

of additives is very important in cementing deep casingstrings.

15


.Weatherford

Loss of filtrate to a permeable medium will cause'arise in slurry viscosity and. a rapid deposition of cementfilter cake, thus restricting flow, The factors that influencethe fluid loss of cement slurries are time, pressure,temperature and permeability of surrounding formations.

A successfulcementation has been achieved when thecasing is surrounded by a uniform cement sheath, no mudis left in the annulus, and the casing is sufficientlysupported by the cement. Migration of any fluid and/orgas is prevented due to a good bond of the cement to bothcasing and formation.

This ideal situation will seldom occur, but all

16

measures have to be taken to approach it. In practice, theindustry has to live with boreholes that never show atotally satisfactory configuration:. Holes are never vertical. Deviations of less than one

degree will already allow the casing to drift toward thewall..The configuration of the borehole has its irregularities.

. The hole cannot be defined as a cylinder. The crosssection changes constantly due to washouts, plasticshales, filter cake build-up, key seats, etc.

Consequently, a variety of problem areas must beaddressed and discussed. A better understanding will helpto minimise cementing failure.

.Weatherford

Conditioning of Drilling Fluids

Regardless of the purpose of the individual casingstring, the successor failure in cementing it will affectfurther work.

The best conditions for primary cementing shouldtherefore be established long before the actual cementingoperation.

Drilling successshould not be rated in terms of"penetration per hour", but more in terms of achieving agauge hole. This is especially true for critical zones acrosspermeable formations and/or salt sections. Care is requiredto prevent washouts during drilling of these formations.For achievingthis, utmost care has to be given to theconditioning of drilling fluids.

One of the functions of drilling fluids is to sealpermeable formations. This is achieved by building a filtercake opposite a permeable formation. Maintaining thisthin impermeable filter cake is also essential for theprevention of several possible problems, e.g., differentialpressure sticking, logging difficulties, lost circulationproblems and primary cementing problems.

Drilling fluids, particularly those of the water-claytype, possess thixotropic properties which must beconsidered along with flow properties. A thixotropicmaterial will exhibit a reduction of gel strength upon shearaction and will reform gel structure when quiescent.

Fig. 29 illustrates how the displacement process isinfluenced by the gel strength of the drilling fluid atconstant filtrate loss and equal cement densities. Each ofthe three flow rates for cement, represented by graphedlines, shows that more mud is displaced as the lO-minutegel is reduced.

Cement will only displace mobile drilling mud.Displacement of gelled stationary mud (in wash-outs),partially dehydrated, highly gelled mud and almostcompletely dehydrated mud filter cake is much moredifficult than the displacement of mobile mud. Keeping themud in "good condition" during the drilling phase, plusconditioning the mud prior to running the casing, isextremely important, since this prevents the developmentof highly gelled mud and thick mud cakes.

It is therefore essential that mud properties areadjusted prior to reaching casing settling depth to obtainoptimum parameters for running casing and cementing.

The ideal mud would be:

a) non-thixotropic with low plastic viscosity and yieldpoint.

b) low weight with minimum solids content and fluid/filtration loss. Then a thin cake will likelyminimisedifferential pressure sticking.

c) compatible with cement composition. While suchconditions cannot always be obtained in actual practice,an effort should be made to achieve these conditions.

Cementing Failures

2.8 galls

0.7 galls

1000 2000Ten Minute Gel Strength, Pa

3000

Fig. 29 Influence of Mud Gel Strength on DisplacementEfficiency.

Flow RegimesPlug-, laminar-, turbulent- and transitional flow

regimes for any non-Newtonian fluid are functions ofvelocity and fluid properties. Mathematical determinationsof the velocity at which turbulence is fully established havebeen based on a varying of Reynold's Number for bothmodels (Bingham Plastic Model/Power Law Model). Inthe Bingham Model, a Reynold's Number of 3,000 wasusedto derivethe criticalvelocity- the minimumvelocitythat will maintain fully developed turbulent flow. In thePower Law Model. Reynold's Number is varied: 2.100and 3,000have been used, although the latter is moregenerally applied.

Different flow patterns may be encountereddepending on conduit geometry, flow velocity and physicalproperties of the fluid in question. They are characterisedby the velocity and movement of the particles in differentcross sections of the conduit (Fig. 30).

Plug flowapproaches a flat velocity profile. Thecentral part of the fluid moves as a solid plug, while ashearing effect is present only near the wall.

Laminar flow attains a maximum velocity at theconduit axis, and the velocity diminishes towards the walls.

Turbulent flow occurs when fluid particles move in anirregular motion, forming vortices and eddies.

Plug Flow Laminar Flow Turbulent Flow

Fig. 30 Flow Regimes.

17

100

80

0E 60..II:.":I::Eii 40I:!

I

.l. .20

Cementing Failures

While considered desirable for good cementations,turbulent flow is nevertheless extremely difficult to obtaindue to limitations in rig equipment, eccentric annuli,irregularities of the borehole and inconsistencies in theslurry.

Adding friction reducers has become an acceptedmethod to achieve turbulent flow more easily and at lowerannular velocities;however, this can lead to an undesirablerelationship between the viscosity of cement and mud,resulting in channeling. In addition, friction reducers canincrease the thickening time and reduce the strength of theset cement, and - more important - they increase thefree water content of the slurry. Fig 31 shows differentpumping rates necessary to achieve turbulent flow relatedto casing/hole combination and slurry used.

3

en~u.s82"D.i>:en"c:i~1E..is"'0:z:

fIIminm/s

2001.0

3001.5

4002.0

I/mingal/min

30080

400108

20053

400106

600160

1000 1200 1400266 320 372

IImingallmin

800213

Fig. 31 Pumping Rate to AchieveTurbulent Flow inAnnulus.

Displacement VelocityLaboratory work and field"experiencehave shown

that:. The annular displacement velocity should be at least

250 ft/min and preferably 350 ft/min for small casingsizes (Fig. 32).

. Such dIsplacement velocitiescan be achieved, over theproductive zones, in most circumstances encountered inthe field. The formulation of thin cement slurriestogether with field-validated computer programmes tocalculate the highest possible cement displacement ratesis required. Estimates should also be made in criticalcases of the swabbing/surge action created by pipereciprocation..If the above discussed high rate of displacement is notpossible, then a plug-flow type job should be carriedout. This must be pumped very slowly (30 to 90 ft/min;preferably at the lower velocity).

Experiments have shown that there is no suddenchange in displacement efficiencywhen the flow regimechanges from laminar to turbulent. Throughout therelevant literature the discussion about which flow regimeachieves the highest displacement efficiencyshows

18

.Weatherford

controversy; it is however, generally agreed that laminarflow should be avoided whenever possible.

'$. 80

~ 70c"uiiic 50"E8 40"i 30Q

100

20

10

m/sIt/min.

0.5100

1.0200

1.5300

2.0400

2.5500

Effect of Annular V~loclty

Fig. 32 Effect of Annular Velocity on Mud DisplacementEfficiency.

Effect of DensityAn analytical study was performed to determine how

the displacement process is affected by the densitydifference between the two fluids. The geometry consistedof an annulus with a 5 inch inner diameter and an 8 inchouter diameter. The flow rate was 189gal/min and theproperties of the displaced fluid were held constant asfollows:

Density: 12.8Ib/galPlastic viscosity: 20 cpYield point: 151bf/100ft2

This yield point and the plastic viscosity of thedisplacing fluid were equal to those of the displaced fluid;however, the density of the displacing fluid, pi, was variedfrom 12.8Ib/gal to 16.4Ib/gal.

'$. 95

IfIii:!! 90ffic~8 85"a.enQ

100

Geometry: 127mm (5 in) 1.0.203 mm (8 in) 0.0.

80Flow rate: 12 dm'/s (189 gal/min)

o 120 (1.0) 240 (2.0) 360 (3.0)Density Difference p,-p,. kg/m' (Ib/gal)

480 (4.0)

Fig. 33The Effectof Densityon DisplacementEfficiency.

The difference in densities required to obtain themaximum benefits varies with the density of the displacedfluid; this is indicated by Fig. 33.

Centralisa tionFrom a theoretical standpoint, the importance of

centralisation may be understood by considering Fig. 34.

500 6002.5 3.0

500 600133 160

.Weatherford

Low Rate of Row Moderate Rate High Rate of Rowof Row

_ "Plug" e Stationary Ruid D Shear Region

Fig. 34 Bingham Plastics - Flow Pattern.

It is difficult to predict the flow behavior of fluids ordisplacement mechanics in eccentric annuli when in fully-developed turbulent flow. The velocity distribution aroundthe annulus is less irregular, but the flow still favors thewidest part of the annulus. Displacement of a fluid fromthe narrow part of an annulus may not even be assured byturbulent flow.

1.2

~ 1.08~ 0.8m~0.6~.~0.48~ 0.2

100% Standoff

(Centered)

o3 4 6 8 10 20 40 60 80 bbl.5.6 .95 1.3 1.6 3.2 6.4 9.8 12.8 m3

Flow rate/min.

Fig. 35 Effect of Stand-off and Flow Rate.

Pipe centralization creates a uniform annular flowarea perpendicular to flow direction. This equalizespressure distribution and flow resistance uniformly aroundthe pipe.

Fig. 35 shows how eccentricity affects velocity on thenarrow side of the annulus in relation to the overall rate offlow for one set of fluid and hole conditions.

Example: With 50% standoff, fluid in narrow side willnot move before average flow exceeds 10bpm; above20 bpm, it is never more than 60% of total flow rate.

Centralization not only serves the purpose ofachieving uniform flow patterns, it also helps avoiddifferential sticking problems while running casing into thehole.

Cementing Failures

Differential Pressure StickingIn order to be able to run casing to bottom while

avoiding differential pressure sticking during intermediatecirculation or on bottom, reciprocation or rotation shouldbe initiated without delay once the circulation head isinstalled.

Differential pressure can exist in various sectors of thehole, where the hydrostatic head alone or combined withthe pressure losses for the mud systems in movement causethe mud filtrate to invade a permeable formation with arelatively lower pressure level.As a result, the mud cakedeposited in front of such a formation will increase, thusoffering a greater contact area with the casing. At the sametime the casing will be pressed against the borehole with aforce that is proportional to the contact area and thedifferential pressure.

When pipe movement is interrupted, the casing sealsoff the cake from the filtrate supply in the contact area andthe cake begins to grow as fluids continue to be driven intothe surrounding permeable formation (see Fig. 36). Thispressure loading effect and the high friction factor betweenpipe and cake solids can increase the "sticking" force untilthe casing cannot be moved.

Mud

Casing

PermeableFormation

Filter Cake

Initial Contact

Fig. 36a Differential Pressure Sticking.

Mud

Casing

PermeableFormation

Filter Cake

Contact AreaIncreases

Fig. 36b Differential Pressure Sticking.

19

Cementing Failures

.Weatherford

Centralizers reduce the likelihood of differentialpressure sticking between casing and open hole. The forcesat work in differential sticking are far higher than thosedue to increased drag forces from centralizers contactingthe wall.

The following example illustrates the advantage of theapplication of centralizers.

A 5 inch, 18lbs/ft liner is run from 10,000to 11,000ft.The mud hydrostatic pressure exceeds the formationpressure by 1,000psi. Sand/Shale content is 10% sand and30% shale. The force, F, required to free the pipe ifdifferential sticking has occurred is calculated as follows:

F = (dP) (Ac)(Cr)Where

F = Force,lbsdP = Differential pressure, psiAc = Contact area, sq.in.Cr = Coefficient of friction (Use 0.25)

In this case it is assumed that a 2-in wide strip of thepipe wall is in contact with the borehole. Therefore, thecontact area equals 1,000ft of open hole multiplied by 2 inand then by 0.1 to adjust for the amount of shale presentwhere differential sticking is not occurring. This convertsto 2,400 sq.in. For the liner run without centralizers, therequired force to pull it free once differentially stuck wouldbe:

F = (1,000psi)(2,400sq.in.)(0.25) = 600,000lb.Assume that the increase in drag due to running is

equal to the weight of the liner. This gives a total drag ofonly 18,000lb, which is equal to only 3% of the totaldifferential sticking force possible. Centralizers appear onthe surface to hinder running pipe but in the open hole,where it counts, they are essential.

Again, differential pressure sticking should not beunderestimated when running casings. To summarize:. Sticking occurs opposite permeable formations;. Stickinggenerally occurs after an interruption of pipe

movement;. A small clearance between casing and borehole

conducive to wall sticking tends to increase casing/cakecontact area;

. Sticking results from the inability to build a mud systemthat effectivelyseals the wellbore wall.

To prevent sticking problems, the contact areabetween casing and wall of the borehole must be reduced.Mechanical cementing aids like centralizers will maintain aclearance between casing and the wall, thus minimizing thesliding-resistanceof the casing. Experience has shown thatcasing strings have been smoothly run into highly deviatedboreholes using an adequate number of centralizers, eventhough certain formations were highly permeable and hada low pressure level.

Pipe MovementComprehensive tests were conducted using gauged

and washed-out sections to evaluate displacementefficiencyas a function of flow regime and pipe movement,with and without scratchers.

20

Mud Displacement Test

(Cement Density =Mud Density =1.6 kg/l =13.3 PPG)

(Slurry Volume =571 =15 gal)

'G = 2.74" hole; I = 2.25" hole; L = 3.75" hole- Scratchersused SPE4090

Fig, 37 Mud Displacement Test.

These investigations have disclosed that the bestdisplacement efficiencyin both flow regimes was achievedwhen the pipe was in motion. This is exhibited in Tests 24through 27 for pipe movement versus Test 1and 10for nopipe movement.

A decrease in displacement efficiencywas experiencedwith increasing hole sizes. Pipe movement, as would beexpected, resulted in greater displacements efficienciesthanwithout pipe movement. Contrary to observations made intests run with gauged hole cores, displacement efficiency ina large wash-out was better when pipe was reciprocatedthan when it was rotated. The important observation wasthat pipe movement, either rotation or reciprocation,improved mud displacement.

The highest displacement efficiencywas attained inTests 35 thru 36, which consisted of pipe movement withscratchers.

A significant observation made in the scratcher testswas that cement not only penetrated the narrow side of theannulus as expected, but an improvement in mud removalwas noted on the wide side, even though the ends of thescratcher arms were slightly over 1 inch from the wall.Breaking up of the gelled mud and flow streamdisturbances, caused by the bristles, are credited for theimproved displacement.

Pipe movement employing rotation may be betterthan reciprocation, but the difference in displacementefficiency is only 4-7%, and one has to be very careful inrotating pipe as uncontrolled torque applied toconnections might cause serious problems.

Centering pipe in the borehole creates a uniformannular flow area perpendicular to flow direction, andminimizes variation of resistive drag forces across this flowarea. This concept has been recommended for over 30years. Centralizers do not provide perfect casing-borehole-concentricity. But they will substantially improve standoffconditions, as casing without centralizers will lie againstthe borehole wall.

Pipe. DisplacementEfficiency,%Test Standoff, % Row Pipe 2.74" 2.25" 3.75"No. G I L Regime Movement Borehole Borehole Borehole

3 2 lam. None 6010 6 turbo None 66

24 9 lam. rot.-16rpm 8425 21 turbo rot. -16 rpm 83

26 16 lam. rep. -1.5 fps 7727 15 turbo rep. - 1.5 fps 79

28 9 10 40 lam. None 63 47 3729 10 30 42 turbo None 69 63 55

30 9 14 39 lam. rot. -16 rpm 79 79 6231 11 27 35 turbo rot. -16 rpm 75 71 62

32 6 21 32 lam. rep. -1.5 fps 78 76 6833 14 41 54 turbo rep. -1.5 fps 87 85 67

34 25 44 52 lam. rot. -16 rpm- 93 90 8935 45 63 61 turbo rot. -16 rpm- 92 89 88

36 5 26 38 turbo rep. -1.5 fps- 90 87 80

.Weatherford

Centralizers are available for nearly every possiblecasing-hole size combination. Still, the use of these devicesis sometimes resisted. Generally, this resistance is due to aconcern that they will "hang up" and prevent casing frombeing run to the desired depth. Experience gathered fromthe use of sub-standard centralizers indicates they havebroken up during the casing running process and became ahazard by preventing the casing from reaching T.D.

Unfortunately, conditions that generate greatestconcern about centralizers - like highly deviated wellswith numerous washouts - are, many times, the veryconditions that make their use one of the key requirementsfor success.Centralizers can actually increase changes ofgetting casing down, i.e., where differential sticking is aproblem. Centralizers also reduce the surface contact areaof the pipe against the wall, thereby minimizing dragforces.

Rotating casing at 15-25rpm provides more pipemovement relative to annular fluids than reciprocating20 ft on a one-minute cycle. But rotation can causeovertorquing of connections, and while most rigs are setup to reciprocate without a rotational head, rotationcannot be applied during cementing without specializedequipment. The effects of reciprocal movement on flowrates and velocity of fluid in the annulus are shown inFig. 38.

20 800

1813%" Casing

~~~~

~~ mc~

~~~

~~ c~E

~~ ~Q~

~5K~~

roo

1.5 2.0 2.5 3.0Cycle Time for a 20 ft.Stroke, minutes

Fig. 38 Effects of Reciprocation.

Maximum displacement rate assumes uniformacceleration and deceleration over 4 ft at each end of thestroke.

The motion creates pressure and velocity surges in thewellbore, which improve the erosion effect of slurry onbypassed mud by substantially increasing displacing dragforces. However, it is very important to know themagnitude of pressure changes to avoid breaking down theformation and causing lost circulation.

It should be pointed out that the narrow section ofthe annulus is increased and decreased between upstroke &downstroke due to the action of centralizers.

Before the running operation starts, the Weatherford

Cementing Failures

Weight in Air(Theoretical)

IWeight in Mud(Theoretical)

275

1.0.aMax500

a Max I gal/min525 gal/min

Downstroke

Joint No.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17Hours

Fig. 39 Pipe Weight Observation.

cementing engineer prepares a casing weight chart whichallows close weight control during the operation. Whenanomalies in hookloads are encountered, indicating holerestrictions, doglegs or other obstacles, circulation andmovement of the string are necessary to re-establish anormal condition. Each open hole circulation will alsoclean centralizers and scratchers of material accumulatedduring running, minimizing any possibility of plugging andbridging the annulus. Fig. 39 shows a typical example. Astring of 275 joints of 9r' casing was run into a highlydeviated borehole utilizing a large number of mechanicalcementing aids including centralisers, stop collars andmore than 200 scratchers. Four intermediate circulationsguaranteed a smooth run.

Contamination of fluidsContamination of the cement by mud around the

casing shoe leads to a drastic decrease of its compressivestrength as well as the bond strength.

The absolute value of the shear bond is not shown inFig. 40, but the scale is linear so that percent change canbe estimated. The average shear bond strength of neatslurries with optimum water requirement is approximately500 psi.

- - - Fresh Water Mud- Sail Water Mud

Oil Emulsion Mud

'"coID

Ii!.c'"

o 5 10Volume Mud, Ofo

15 20

Fig. 40 Shear Bond Strength after Contamination with Mud.

21

16ID

g' 14.ct) 121;j

10cE 8uQ 6i5

4

2

I . l0 0.5 1.0

Cementing Failures

As little as 5% contamination of the cement slurry bydrilling mud causes a significant decrease in the slidingresistance. A marked reduction in bond strength occurswhen oil-emulsion mud is used because oil is not a wettingagent and inhibits the chemical reaction of the cement byremaining as a fine film on the pipe surface.

Mud ChannelThe major concern in any cementation is the complete

removal of drilling mud from the annular space and itsreplacement by cement. Mud channels in the cement resultfrom incomplete displacement of the drilling fluid bycement slurry and are usually adjacent to the casing on thenarrow side of the annulus (Fig. 41). This exludes the non-circulatable mud phase, such as the thick mud filter cakewhich occurs across permeable formations or congealedmud which may be present in the washed-out or enlargedsections of the annulus.

Many articles have been written on the mechanicsinvolved to achievea successfulprimary cementing job. Anarticle by Clark and Carter indicates that "improved mudremoval is achieved with pipe movement (rotation orreciprocation), centralization, cement displacement inturbulent flow, a well-conditioned mud, and pipe motionwith scratchers, i.e. if hole enlargement has occured duringdrilling.

100% Stand-Off 75% Stand-Off 50% Stand Off

Fig. 41 Channeling vs. Stand-off.

The extent of channeling depends on how well thecasing is centered.

Fig. 42 illustrates the percent of the mud channel tothe total mud as a function of pipe standoff. This test wasaccomplished by mounting a joint of pipe inside asimulated sand formation wellbore. The pipe had 0%standoff (against the wall of the hole) on each end and100% standoff (true centralization) in the center. The datashow that the percentage of mud channel increased from0.2 when the pipe was concentric to 10.6for the eccentricpipe condition.

22

.Weatherford

_ Total Mudr.,.~J.! MudChannel

;f..,;"~ 20..'Sccca:

100 28Pipe Standoff, %

8

Fig.42 Effect of Stand-off on Remaining Mud in theannulus.

Reducing the pressure drop in the annulus willdecrease the amount of the mud channel remaining there.This factor is related to flow regime and/or rate achievedduring cement placement. Fig. 43 shows a comparisonbetween the percent of mud channel and flow rate using amud that has a PV and YP of approximately 43 and 21respectively.

The mud channel was lowered from 15.7to .02%when the annular velocity was increased from 90 to 455fpm. At the same time, the total mud remaining in theannulus was also reduced. (from 56 to 4%).

Thin Slurries_ Total Mud

!pmcm/s

Fig. 43 Effect of Flow Rate on Remaining Mud

Pipe movement and the use of scratchers in a washoutwill further help the operator obtain a successfulprimarycementing job. Fig 44 depicts the effect of pipereciprocation on displacement efficiency.The use ofscratchers in the enlarged portion of the hole resulted inbetter cement placement across the interval even thoughthe scratchers did not always come in direct contact withthe formation.

60

50

40;f..,;"

30..'Sccca:

20

10

09045

.Weatherford

25 50 75 100TotalAnnularMud After Displacement, %

Fig. 44 Effect of Reciprocation on DisplacementEfficiency.

BridgingBridging may restrict the effectivehydrostatic

pressure, and it can occur anywhere in the wellbore.If bridging occurs during primary cementing before

displacement is complete, there is an increased possibilityof losing returns. To prevent bridging during thecementation, both slurry and casing should be kept inmotion. One may continue to reciprocate the pipe for ashort period of time after the displacement has beencompleted (Post Plug method), but be careful to controlthe up and down-stroke weights as flash setting of cementmight result in landing problems.

Loss of Bottom JointsLoss of bottom joints of surface and intermediate

casing strings have been experienced in many areas. Suchfailures are normally not recognized immediately. One ormore joints may have parted from the casing string anddropped down the hole, and the parted section of casingmay have shifted laterally, restricting the passage ofdrilling tools. Expensive remedial work is required torealign the parted casing. Fig. 45 illustrates various ways inwhich casing can be lost down the hole and with it possiblythe hole itself.

-CementBondTorqueImpulseFromDrillingOut

DrillCollarVibration

Fig. 45 Loss of Bottom Joints.

Cementing Failures

Loss of casing down hole is caused by:. drill collar vibrations. torque impulses from drilling out. poor cement bond resulting from contamination by

mud

Analysis of possible causes of such failures indicatesthat the casing is unscrewed rather than broken. Theunscrewing occurs because of high-level torque impulsestransmitted to the casing by the bit and stabilizers as theyhang up while drilling cement and cementing equipmentout of the bottom joints.

In most cases, the reason is simply the loss of cementbond in the cased section. The bottom joints might havebeen set in a permeable zone and excessfilter cake has notbeen washed or scraped off. Poor cement bonding to thecasing and formation allows the breaking up of the cementsheath due to shocks and vibrations. Similar effects can befound through over-displacement or prematureresumption of the drilling activity.

Salt FlowIn setting casing through salt formations, it is

imperative to obtain a good bond to the soluble zones.This might be difficult to achieve, but everything possibleshould be done to minimize salt flow:

Salt deforms easily even under low confining pressure.In cementing through salt deposits, it is necessary that thecasing withstand these plastic flow forces if collapse is tobe avoided. These forces can approach the overburdenstress of I psi per foot of depth.

An open, unconfined wellbore through salt zones atdepths greater than 3,000 ft will tend to close unlessproperly stabilized with cement. The pressure on the casingsubject to non-uniform loading by salt can increase until iteventually equals the overburden pressure.

For uniform loading of casing, fill the annuluscompletely and uniformly with cement.

'i;:>!'.);:,,~..",'Ci ~."

.~ft.

"., ..~ .

.:~..~'.. ,",.)l~~1Y.-':1;;:w;:r-:

Salt or cement ';>]~.holdspipeat ~thispoint ..~:~I7'.~.,

Fig. 46 Bending of Casing by Salt Flow.

The lines in Fig. 46 on the right show the shift of theoriginal wellbore which has moved due to the flow ofplastic salt. When a hole is being drilled and casing iscemented in salt sections below 1000ft at a temperaturearound 150°C,salt will flow until a state of equilibrium isreached. The non-uniform loading that results causesbending and deformations of the casing string.

23

»HL I_. LaminarRow

U) 3.25 . '. I Turbulent Flowi ... ":,:.:;; 3.75

I r_ - t::::::JILa,,!inarAw with. Reciprocationf

i : fP , Turbulent Row withReciprocation

DTurbulent Flow withReciprocation andScratchers

Cementing Failures

Failure of casing by non-uniform loading ininadequately cemented wasJJ,ed-outsalt sections should beconsidered a drilling or a cementing problem rather than acasing design problem. Salt-saturated or oilbased drillingfluids are often used during drilling to minimize washouts,and salt-saturated cement is used during cementing. Areasonable solution is to use scratchers and Hydro-Bonders. The scratchers will reinforce the cement, and willgive more turbulence in the area of application. Hydro-Bonders should also be used to improve displacementefficiencyin case salt zones are washed out. A reinforcedcement sheath in this area should substantially improve thedistortion resistance of both pipe and cement.

Fig. 47 Restriction in the Wellbore

Restrictions in the wellbore are formed by the buildupof mud solids or cement filter cake in the annulus. Theresult is an increase in annular pressure below therestricted interval, which can cause fracturing of weakformations and losses of mud or cement. (Fig. 47).

The development of this situation can be minimizedby using a wellconditioned mud. During the casingjob,use mechanical aids like scratchers or spiral centralizers toreduce the filter cake to a minimum.

Pipe reciprocation, intermediate circulations and theapplication of scratchers throughout the permeable zonewill help to minimize the cement filter cake buildup. Inaddition, the cement slurry should contain an absoluteminimum of free water (less than 2%) and possibly somefluid-loss additives.

Gas FlowThe pressure exerted by the fluids in the annulus must

be greater than the gas pressure in the permeableformation. If during the displacement phase thehydrostatic pressure exerted by the annular fluid column(mud, chemical wash or spacer, and cement slurry) is lessthan gas pressure in the formation, gas can diffuse into thefluid column. As gas bubbles migrate up the column, theywill start to expand with decreasing pressure.Consequently, a further reduction in hydrostatic pressurewill exist at the gas formation and allow entry of more gas.

24

.Weatherford

Eventually, there will be enough gas entering the annulusto result in a channel in the cement column. When cementdisplacement is stopped, the hydrostatic pressure of thecement column may be too low and communication will beestablished through the channel.

After the pressure becomes equal to or less than thepressure of the highest pressured gas reservoir, it takesonly a short time for gas to start entering the wellbore,since the hydrostatic head has been reduced. The gas,migrating up the unset cement column, further lowers thehydrostatic pressure, which in turn increases the rate of gaschanneling (Fig. 48).

Gas communication through a cemented annulus hasbeen recognized as a major problem for many years.

Previously, gas migration in a wellbore wasconsidered to exist only at the casing-cement or cement-formation interfaces, and poor bonding was considered tobe a major cause of gas communication. This is still amajor problem that may be also responsible for gascommunication between multiple permeable formations.

Possible causes for gas communication in a verticalcolumn can be separated into two main categories:. The first occurs during the displacement of cement into

the annulus and relates to the mechanisms involved inminimizing channeling through mud between horizons.

. The second concerns gas migration through the cementcolumn after primary cementing operations have beencompleted and is associated with the physical andchemical properties of the various cementingcompounds.

Fig. 48 Internal Lattice Development during CementThickening

Based on research and observations to date, severalhypotheses explain why gas may enter a wellbore duringcement displacement. These factors are primarily related todrilling mud being left in the annulus after primarycementing, and the resultant density of the fluids

.Weatherford Cementing .Failures

remaining in the annulus. Each of these affects thehydrostatic pressure exerted at any depth.

In addition to the usual slurry properties, well dataand formation pressure, the transition time is an extremelyimportant factor. This is the period during which theslurry changes from a true hydraulic fluid to a highlyviscous mass showing some of the characteristics of asolid. It starts when the slurry develops enough static gelstrength to restrict transmission of full hydrostatic pressureand ends when the cement develops enough of thecharacteristics of a solid to control percolation of gasthrough the cement column. With this definition oftransition time, annular gas flow can be prevented if thepressure in the cement adjacent to the high pressure gaszone can be maintained at a value greater than or equal tothe gas reservoir pressure until the end of the transitiontime.

Comprehensive laboratory tests have proved that:. A static gel strength of 10Pa may be sufficient to

instigate a pressure restriction.. The start of transition time coincides with the first

measurable static gel strength.. The end of transition time appears to occur when the

cement slurry develops a static gel strength exceeding250 Pa.

. The total transition period appears to have a durationof 1 to 4 hours, and starts within 10minutes after thecement is placed.

To prevent gas flow during the transition time, staticpressure loss due to hydration reaction and volumededuction (0.1-0.5%) during this period has to becompensated for by maintaining internal pore pressure ofthe cement slurry.

Cement slurries should have a minimum safethickening time with a very short period between the API-measured thickening time and the development ofcompressive strength. Other factors such as uniformmixing, rheology, and premature setting of cement high inthe annulus, all have a place in controlling flow aftercementing. One parameter that has not received muchattention is the free water content of the cement slurry.

Separation of Free WaterThere are many factors that contribute to the

formation of free water as the cement sets. Wells deviatingfrom the vertical usually force the casing string against thewall in many places. In deliberately deviated ordirectionally drilled holes, this will occur in many sectionsof the hole. In this case the casing will be off center inmany parts of the wellbore, exerting severe lateral forces.

On the upper side, the resistance and restriction toflow is less, so the mud displacement is more efficient, buton the lower side channels of mud are formed.

Another complication is that at some time duringcement placement the casing contains a rather heavycement slurry, the annulus contains a lighter mud, and thetotal load becomes greater than the mere weight of thecasing.

After the top plug is placed, loading forces arereversed - that is, the heavier cement slurry is in theannulus and the lighter displacing fluid is in the casing -the measured weight of the casing is reduced.

Fig. 49 Configuration of a borehole

Eccentricity will also support the separation of thefree water in the cement. If water separates and forms achannel in the upper section of the annulus of the deviatedwell, the hydrostatic pressure on the formation will bereduced. Several gas kicks in the recent past were a resultof this phenomenon.

Considering the fact that in deviated wells the holeconfiguration will tend to be oval- especially in softerformations- rather than the desiredcylindricalshape,theimportance of achieving a separation between the lowerside of the hole and the casing string is obvious (Fig. 48).

Only with the help of a concentric pattern betweenpipe and hole can the displacement of mud and theplacement of cement slurry be optimized. To achieveconcentricity, the use of mechanical aids is an absolutenecessity.

As cement sets, it forms internal lattices that interlockto give the slurry lateral support. The resulting structureleaves pore spaces filled with water. Just prior to particleexpansion (setting), the hydrostatic head is reduced to theweight of mix water. If this pressure is less than the porepressure, gas will migrate into the slurry, and as it rises gasbubbles will increase in size and widen the originalchannel.

There are probably a number of factors whichseparately or in combination cause flow after cementing.From research on the effects of free water content ofcement slurries, the following observations have beenmade:. Field experience shows that reducing the free water

content of the cement to near zero helps to eliminate flowafter cementing in a number of cases.

25

Cementing Failures

. Laboratory model studies show that a water channelcan form on the top side of a non-vertical cement slurrycolumn which will reduce the effectivehydrostaticpressure of the column. The extent of this pressurereduction is a function of the free water content of theslurry and the degree of column inclination (see Fig 50).

. Free water separation can also leave uncementedsections filled with water pockets. The denser cementwill settle out and form pockets against holeirregularities. This will generally leave a long channelfor interzonal communications.

AngleofInclination

Fig. 50 Model Showing Fully Developed WaterChanneling.

Buckling of PipeCement is used to support, anchor and stabilize the

pipe, and to serve as a seal or barrier to fluid flow. Here weconsider stabilizing the pipe in order to avoid axialbuckling. Such problems are of particular interest whenlarge axial stresses can be induced in the uncemented pipeby compaction and subsidence resulting from fluidwithdrawal or permafrost thaw, or by large changes inpipe temperature such as in geothermal or steamfloodwells.

It is known from experience that even heavy-weightcasing does not withstand all lateral forces caused by saltflow.

Buckling is the helical configuration of a tubularstring with the spirals increasing in length (pitch) to aneutral point away from the fixpoint. Maximum bucklingusually occurs at the lower end of the string, but may alsooccur at the top in highly buoyant conditions.

If the string is stiff enough, it will not buckle to theextent that the lower part is forced against the side of thehole or casing. Otherwise, buckling is limited by the sidesof the hole. Yet it still produces high stresses in the outsidelayers of tubulars, which can lead to pipe failure.

26

.Weatherford

A

Inside Pressure

Compression 0 Tension

TensionNeutralPoint

Fa

Fa Fa

B Fb

Fig. 51 Pipe Buckling A-B

Various authors have discussed the stability of a tubein the pressence of internal and external pressure. Chesnayand Garcial use a formula that involves internal andexternal pressure and cross-sectional areas of the tubes.They call the average of the radial and tangential forcesthe stability force (Fs).

Fs=Ao Po- Ai PiAo = Area of tubing ODAi = Area of tubing IDPo = Pressure outside tubing at depthPi = Pressure inside tubing at depth

H.B. Woods, in a written discussion of Klinkenberg,also made an analysis of the stability of a tube in thepresence of internal and external pressures. He showedthat the neutral point exists where the average of radialand tangential stresses is equal to the axial stress.

oa=or+ot2This value is equal to hydrostatic pressure if other

pressures are not applied, but it can be calculated usingapplied pressures. It is consistent with Klinkenberg.

Fig. 51 illustrates graphically the use of the stabilityforce. In Fig. 51A, Fs equals the compression at the end ofthe tube, arid there is no buckling tendency. But whenpressure is applied to the inside of a string, Fs is reduced,and buckling occurs as shown in Fig. 51B. If the internalfluid density is increased, Fs remains the same, but tensionis reduced by the tube's tendency to expand linearly, andbuckling occurs (Fig. 52D). (These illustrations ignoresome possible associated tensional changes for purposes ofillustration.) As shown, the buckling force is the axial loadFa minus the stability force (Fb = Fa - Fs) and the axialload may result from either hydraulic or mechanicalforces, or both.

NeutralPointFa

c Fb

Fig. 52 Pipe Buckling C-D

.Weatherford Cementing Failures

By using the stability force concept and calculatingaxial tension, problems involving tubing, cemented casingand drill pipe can all be solved by common procedures andgraphical presentations that aid visualization of theconditions and solutions.

The complexity of possible cementing failures and theresults of poorly cemented pipe on further drillingactivities, completion of the well and the lifetime of aproducing well is tremendous. Experienced specialists willbe required in the future more than ever before.Computers will be helpful to avoid mistakes, but one mustalways be aware of potential failures and proceedaccordingly.

On the previous pages many cementing problemshave been addressed. It is easy to write about good results,but hard to achieve them in the field. In remote areaswhere quite often logistical problems reduce theopportunity for optional cementation, engineers on sitemust realize that they have to live with compromises.

Nevertheless, all of the points listed below should beconsidered, and the achievement of as many as possiblewill be helpful:

I) Casing should be as concentric as possible.2) Cement/mud weight ratio should be as high as possible.3) The lowest allowable weight and viscosity of mud

should be used.4) During the circulation prior to cementation a marker

should be pumped to confirm that the hole volume iscirculated and to obtain a comparison between actual

volume and calculated volume - as a rule these figuresshould not differ more than 5-10%.

5) Adverse mud-cement interactions should be avoided;use spacers, flushes and wiper plugs.

6) Control displacement rates and slurry rheology:a) Maximise contact time by using the lowest velocity

level of turbulence.b) Use high rates where turbulence can be maintained in

the widest annular area or across critical zones.c) Consider plug flow in areas too large to use

turbulence; the program must be designed around thesmallest annuli, considering the pressure surges.

d) If laminar flow is inevitable, increase PV and yieldstrength of cement; displace at highest practical rateand use sufficient volume to get desired columnheight in narrow side of annulus.

e) Use mechanical cementing aids to maximizedisplacement efficiency,particularly across washouts.

7) Pipe movement - Reciprocation and/or rotation:a) Rotation eliminates mud channels from behind

narrow side of eccentric casing/boreholeconfiguration.

b) Reciprocation aids in achieving turbulence.c) Rotation and reciprocation - most effective,but most

difficult to achieve.a) Reciprocate with scratchers across high-interest zones

for effective mud removal and cement/formationcontact.A wide selection of mechanical equipment has been

designed to cope with problems encountered in oil-wellcementing and plays a vital role in successfulprimarycementations.

27

Mechanical Cementing Aids

CentralizersA centralizer is a mechanical device attached to the

outside of casing. The primary purpose of this equipmentis to center the casing in the hole and provide a uniformflow passage with relatively equal frictional pressure lossessurrounding the casing. Another major function ofcentralizers in a deviated hole is to help prevent differentialpipe sticking.

Fig. 53 NW ST Centralizer

Weatherford's non-weld (NW) design ST seriesCentralizer is rugged in construction and versatile inapplication. Highest quality spring steel bows, available invaried heights for wide, normal and close tolerance annuli,are inserted in the completely weldless, integrally-hingedcentralizer collar.

Weatherford's non-weld centralizers meet or exceedforce requirements specifiedin API Standard 10for APIhole/casing sizecombinations. A choice of straight bowdesigns assures optimum force criteria in nearly allwellbore diameters. Installation is accomplished by simplywrapping the centralizer around the pipe and inserting apin in the collar hinge.

Fig. 54 NW SP Centralizer

28

.Weatherford

The NW Spiral Centralizer incorporates all of thedesign advantages of the NW Straight Centralizer. Thehelical bow form helps bridge keyseats and otherirregularities in the well-bore and still provides maximumcentering of the casing.

During casing running the spiral bows provide acleaning action, removing excess filter cake and cuttingsfrom the borehole wall, effectivelycleaning the annulus.The chances of pressure build-up in the wellbore due to"Piston effect" are reduced.

During reciprocation and displacement, a swirlingaction is created in the annulus by the spiral bows,improving slurry distribution.

A choice of designs assures optimum force criteria tonearly all wellbore conditions.

Fig. 55 NW Positive Centralizer

Casing inside a cased hole centered with PositiveCentralizers gives almost 100% standoff. Concentriccasing strings, cemented or uncemented, protect theprimary cementation of previously-run strings from theshocks of drilling and tripping.

A Weatherford Positive Centralizer immediatelybelow the wellhead will ensure concentric casing stringsthat aid installation of slips and packoffs.

If cement is injected from the surface into the annulus,distribution of the slurry is improved.

The efficiencyof casing cutting tools whenabandoning locations is greatly improved when casingstrings are concentric.

The frictional drag experienced when running pipe,especially in deviated holes, is significantly reduced whenWeatherford Positive Centralizers are used insideintermediate casing.

A "U" profile bow design permits maximum fluidpassage. A large selection of bows is available toaccommodate any annular combination.

For casing inside casing application, steel collars withsolid fins provide the same function, in addition to

.Weatherford

supporting the centralizers in centering the casing andlimiting the other tools from moving by a strong clampingforce. .

Fig. 56 Turbolizer Clamps

Fig. 57 Slim Hole Centralizer

The slim hole centralizer is designed to be used forcasing-hole combinations with less than I" clearance. Itsstarting force is kept below API standard limitations. Theapplication of slim hole centralizers is essential to avoiddifferential sticking.

The retaining lip on the centralizer collar holds thebow in position after it is closed with a Weatherfordpneumatic assembly tool.

The assembled centralizer is strong and rigid. Thepatented bow retaining lip cannot open when thecentralizer is installed on the casing (Fig.58).


Fig. 58 Retaining Lip

API Standard lODAPI Standard lOD specifies the parameters to which a

centralizer should be produced and perform in the field.

SF. Starting Force (LBS)

W. Welghl of 40 Fl.Medium Welghl Casing.

lk :J

Fig. 59 Starting Force.

Starting force is the force required to start thecentralizer into previously run casing. This force should bequite small if the bows are smoothly cambered, eventhough most contralizers are equipped with oversizebows.The maximum starting force for any centralizer shall beless than the weight of 40 ft of medium weight casing aslisted in table 2.1 of standard IOD.The maximum startingforce should be determined before the bow springs takepermanent set.

Permanent set is the attainment by the centralizer of aconstant bow height of the bow-springs after repeatedflexing of the bow-springs. A permanent set is consideredestablished if the bow height remains constant after eachspring has been flattened twelve times.

The restoring force is the force exerted by a centralizeragainst the casing to keep it away from the bore hole wall.The restoring force required from a centralizer to maintainadequate stand-off is small in a vertical hole, butsubstantial for the same centralizer in a deviated hole.

29


Field observations indicate hole deviation on anaverage varies from zero to approximately 60 degrees;therefore, an average deviation of 30 degrees is used tocalculate restoring force requirements.

=RF = 2 x W x SIN 30.

(@ Stand off ratio of 0.67)RF-Mlnlmum Restoring Force

w-~.::: of 40 ft. Medium WI.

2-Dogleg ComDensatlng FactorOnly From 4%" -9%"

Fig. 60 Restoring Force.

API has specified the minimum restoring force on thebasis of a stated stand-off to annular clearance ratio of0.67 with following conditions:

Fig. 60A Effect of restoring force (CBL)

30

.Weatherford

1) Weight of 40 ft of medium weight casing2) 30. borehole inclination3) Factor of 2 for sizes through 9f' for dog-leg effect

The following case shows 7f' casing cemented in 9.§-"open hole. The maximum deviation is 51 degrees. Twocentralizers were installed per joint throughout the openhole section, in accordance with Weatherfordrecommendation.

From TD to the top of the sands at 8,475 ft. thecentralizers used are of inferior restoring force, and from8,475 ft. to the previous casing centralizers are used withrestoring force above API minimum requirement.

A marked difference is detected on the CBL (Fig.60a); below 8,475 ft. a reading greater than 10mv, andabove a reading less than 10mv. But a more dramaticresponse can be seen on the CEL (Fig. 60b). The overallpoorly cemented section may have been affected byreservoir characteristics; however, distinct channeling canbe observed on the lower side of the hole throughout thispoorly centralized section.

8.400

-

8,500,..

..~

--.

1_~...~~.~~i:~c;t:.<.ttl...2:_~~~.O.~_1

L~°.tm"-..u ~~.O...__._._0.0 ,'0000 1'000.0 0.0

1/200..,

Fig. 60B Effect of restoring force (CEL)

.Weatherford

Runningforce is the maximum force required to movea centralizer through the previously run casing. Therunning force is proportional to and always equal to orless that the starting force. It is a practical value whichgives the maximum "running drag" produced by acentralizer in the smallest hole size specified.Note: Starting and running force values are based on

installation of the centralizer per manufacturer'srecommendations. Both forces can increasesubstantially\through "incorrect" installation (i.e. aclose tolerance centralizer which is, contrary to itsdesign, installed over a casing collar).

Values of above forces are known for all casing/borehole combinations. They must be considered forproper utilization of the centralizer.

Fig. 61 Cement Basket.

Cement BasketsCement baskets protect weak formations from

excessivehydrostatic pressure exerted by the weight of thecement column. They form a restriction against adownhole fluid motion by reducing the flow area. They arenormally installed on the casing string above weakformations, but they are also used in stage cementing or incementing the annulus from the surface.

Stop CollarsThe stop collar serves as a stop to any cementing aid

that is attached to the outside of the ca,sing.It is availablein various designs for standard and slim hole clearance.Weatherford stop collars can be used with set screws andspiral pins. The sliding resistance depends on diameter anddesign.

In deviated wells, where high sliding resistance isexpected to be necessary for holding centralizers andscratchers in position, stop collars are used in tandem. Thismethod has proven to be extremely successful.


Fig. 62 Stop Collars

ScratchersScratchers are designed to clean mud-filter cake off

the wall of the wellbore when the casing is reciprocated orrotated. Reinforcement of the cement sheath is an addedadvantage of scratchers.

Scratchers should always be used when thick mud-filter cake is suspected on the walls of the hole. Thescratchers help remove filter cake and prepare theformation for bonding with the cement.

In combination with centralizers and pipereciprocation, scratchers help ensure the successofprimary cementing jobs.

Fig. 63 Scratcher

The Weatherford CT-IA Scratcher consists of a splitsteel collar which houses double-coiled external andinternal bristles.

31


The external bristle system is inclined 20° tohorizontal and is shielded by slight elevations in the collar.The inclination of these bristles serve to rotate thescratchers while reciprocating the pipe. The internalbristles remove mill varnish and scale from the casing.

WeUbore ~ipersWhen used in casing completions in wells with

unconsolidated formations and excessivefilter cake,wellbore wipers. provide efficientcleaning of the hole during running or

reciprocation of casing;. improve bond of cement to formation and casing;. ensure cleaning of the entire circumference of the

wellbore.

Fig. 64 Wellbore Wiper

Hydro-BonderTo induce a swirling action of the cement slurry

around the casing and improve the displacementefficiency,especiallyin washed-out open hole sections,Hydro-Bonders with molded rubber skirts areemployed.

Fig. 65 Hydro-Bonder

32

.Weatherford

The Hydro-Bonder is a unique cementing aid thateffectivelyreplaces the use of turbolizer centralizers. Itis constructed of a metal ring with nitrile rubber bondedinto a 6" skirt around the collar, is installed on 4-5 ftintervals between stop collars.

The Hydro-Bonder causes a small annularrestriction, which in turn causes a velocity increasearound its outer edge, thereby causing increasedcleaning of the wellbore face. The rubber skirt hastangential ribs that direct the fluid flow around the pipein a vortex fashion. This tool is the only cementingdevice that mechanically forces cement under the lowerside of pipe and aids in displacement efficiency.

The Hydro-Bonder, like scratchers, should alwaysbe run with adequate centralization so that it is in goodshape when it reaches the area of the hole where it mustperform its function. The Hydro-Bonder also aids inkeeping free water or gas in the cement from forming acontinuous channel.

Recommended Installation Patterns

Post PlugPattern

CleavageBarrierPattern

HydrobonderPattern

Fig. 66A-C Installation Pattern

Post Plug (Fig. 66A)Centralizers, scratchers and stop collars are

installed on the pipe rack prior to running the casing,

.Weatherford Mechanical Cementing Aids

scratchers are free to move and are installed about to ftapart. Minimum centndizer spacing is one per joint.Closer spacing of centralizers is recommended withincreased wellbore deviation.

The post plug pattern is used throughout cementcolumn but is effectiveonly when the string isreciprocated.Cleavage Barrier (Fig. 66B)

Centralizers, scratchers and stop collars areinstalled on the pipe rack prior to running the casinginto the well-bore. Scratchers and stop collars areinstalled one foot apart. Two centralizers per joint arerecommended to obtain maximium scratching efficiencyand casing standoff. The scratcher performs the extrafunction of reinforcing the cement sheath in addition tocleaning the wellbore during the cementation. The stopcollars strengthen the casing and dampen shocks causedby future drilling or perforating.

The cleavage barrier pattern is primarily used tosecure the bottom joints and to seal off productionhorizons which lie in close proximity.Hydro-Bonder (Fig.66C)

Hydro-Bonders, stop collars and centralizers areinstalled on the pipe rack prior to running casing intothe wellbore. Two centalizers per joint arerecommended to obtain maximum standoff on thecasing and optimum vortex action. Hydro-Bonders areinstalled on the casing between stop collars andcentralizers on approximately 4 foot intervals.Variations can be made to suit wellbore conditions.

This pattern is used where the casing cannot bereciprocated.Centralizer Installations

Centralizers can be correctly positioned by the useof stop collars. Installation over a coupling or upsetshould be avoided whenever possible.

Some of the advantages of various centralizerinstallations are listed below. (See also Fig. 67)

AdvantagesCase I. Optimum centering. Centralizer pulled. Priorinstallation- no lost rig timeCase II. Optimum centering. Close tolerance. Priorinstallation- no lost rig time. Bow fully compressible. Minimum starting forceCase III. Stop collar not required. Centralizer pulledCase IV. Double centering effect. Close tolerance. Bow fully compressible. Prior installation - no lost rig time. Minimum starting force

DisadvantagesCase I. Not close tolerance. Bow not fully compressible. Stop collar requiredCase II. Centralizer pushed. Two stop collars requiredCase III. Optimum centering not achieved. Installed during running casing-loss of rig time. Increased starting force. Not close tolerance. Bow not fully compressed. Tools in hole hazard. Cluttered rig floorCase IV. Centralizer pushed. Cost-two centralizers per joint

Case I:Over stop collars

Caselli:Between couplingsand stop collars

Casel!:Betweenstop collars

Case IV:Over couplings

Fig. 67 Centralizer Installation

Centralizer Placement CalculationWhat is the proper placement of centralizers? API

cites that the minimum desirable stand-off should be 67%.Therefore, centralizer spacing should be sufficient toaccomplish this goal where necessary. Some ofWeatherford's customers over the past years have

33


expressed opinions and specified stand-off requirementsranging 50% to 77% and even 100%, if available. The keypoint, however, is where to locate that stand-off. Is itacross the payzone only? Or is it the tail slurry sectiononly? Or is it the shoe joints? Weatherford recommendsthat for proper cement placement, a minimum of 67%stand-off in the open-hole section of the wellbore shouldbe achieved and a minimum of 50-67% in the cased-holesection. The goal must be to eliminate wall contactbetween the casing being run and the wellbore wall as thisis the only way that drag forces between pipe and boreholecan be calculated accurately.

The Weatherford Centralizer Program is designed toperform all of the necessary calculations needed toaccurately place centralizers on casing, regardless ofvariations in the borehole geometry.

The algorithm used by Weatherford evolved, in part,from work done by G.M. Myers and A.A. Sutko in 1968,which was later incorporated in API SPEC 100. Since thattime it has undergone many modifications andimprovements as understanding of downhole forcesimproved. The Normal Force/Lateral Load produced by acasing string and the resulting stand-off is the result ofcentralizer spacing, casing weight, hole inclination angle,hole curvature and tension produced by the pipe hangingbelow the point of interest. (Fig. 68).

C: Compression ofCentralizer

STANDOFF=R.-R,-C-DWhere:

Rb= Radiusof boreholeRc = Radiusof casing outside diameterC = Compressionof centralizers due to

the lateral loado = Deflection or sagging of the casing

string

Fig. 68 Casing Stand-off

The highest values for lateral loads usually occur inthe build-up sections of the borehole due to the high tensileloads. The tensile load is a product of all pipe weightbelow a given calculation or survey point. The key is theangle change rate. If a dog-leg in a given situation isperhaps 1.5degrees per 100ft and the resulting lateral loadis 2,600 pounds, it would be possible to double the lateralload by doubling the dog-leg severity to 3°per 100ft in theupper portion of a borehole. In the same way, "drop-offrates" can affect lateral loads in sections of the productionborehole where a directional driller may be making anextra effort to hit a particular target area.

Once the lateral forces are defined, the next step is tocalculate the stand-off at the centralizer. This can beperformed analyticaHyor graphically using a restoringforce diagram.

34'

.Weatherford

Fig. 69 Restoring Force Diagram.

The graph (Fig. 69) reflects standard centralizerperformance under lateral loading. The annular stand-offis plotted against the restoring force. The lateral force isthe same as the restoring force; therefore, simply go up tothe x-ordinate (lateral force) until it intercepts the bowperformance line, then across the y-ordinate to read theresulting stand-off. Weatherford's computer program doesthis using data points on the curve to define its slope.

Sample Centralization ProposalWell Bore Data

TOP BOTIOM LENGTHOF OF OF

INTERVALINTERVAL INTERVAL(ft) (ft) (ft)

CASING0.0.(in)

CASINGWEIGHT

(Ib/ft)

CASINGI.D.(in)

PREVIOUS: 13.375 6835 683568.00 12.415 o

PROPOSED: 9.625 o 109851098553.50 8.535

MUDWEIGHT:11.00Ib/gsl

Survey Data

MEASURED HOLEDEPTH SIZE

(ft) (in)

INCLlN AZIMUTH DESIGN CENTRALIZERANGLE ANGLE SID-OFF TYPE(deg) (deg) ('!o)

o4038613368357065739677737960828886169840

10985

0.000.502.601.007.30

15.2028.3031.6034.0037.5037.5037.50

n~n~n~n~n~n~n~n~n~n~D~n~

0.00225.30150.90233.30278.50282.90286.00286.70286.70286.70286.70286.70

755050757575757575757575

12.41512.41512.41512.41512.25012.25012.25012.25012.25012.25012.25012.250

Fig. 70A

For a custom-designed well program, Weatherfordsubmits a computerized mechanical cementing aid

50.8 2.00

44.45 1.757inch Centralizer in 9'4 Inch hole

Starting Force =650 Lb.

38.10 1.50 I- Running Force =325 Lb.

31.75 1.25

I 25.40 1.00C--------+esu Ing

Stand-off / API

19.05 0.75f- //,

12.70 0.50 f- Normal Force

0.25 , I I I /6.35mms. ins. 300 600 900 1200 1500 1800 2100 2400 Lb..

136 272 408 548 680 816 952 1088 Kg..

.Weatherford

recommendation which takes into account these basicparameters (Fig. 70 A-B):

. Well and survey depth

. Hole size (includes previous casing, washouts, andgauge hole)

. Surveydata- azimuth, inclination, and measured depth

. Mud/cement fluid weights

. Centralizer type available - spring bow vs. positive bow(uses Weatherford bow performance data only)

Centralization

MEASUREDNORMAL DOGLEGOPT[MUMOPTIMUM TYPEDEPTH FORCE SEVERITYSPACING STD-OFF BOWfPOS QUANTITY

~ ~ ~~~~ ~ ~

NB: THE ABOVECENTRALIZATIONPROPOSAL[S BASEDON WEATHERFORDCENTRALIZERPERFORMANCE

Fig. 70B

Once this information is entered, the program thencalculates the stand-off the casing would have, provided aspecificcentralizer spacing is used. The example indicatesthe type of report that is made.

The calculations must be repeated until the correctspacing is determined that will give a stand-off greaterthan or equal to that required as a minimum (usually67%). As a general rule, spacings closer than 20 feet mustbe studied in detail due to the possibility of exceeding thehook-load with moving force resistance, which would, insome cases, keep the pipe from moving down hole withoutpushing it. Each Weatherford Centralizer Programprovides an estimated static, upstroke and downstrokeweight.

Float EquipmentA guide shoe is a mechanical device placed below the

first joint of casing to help guide the pipe into the hole. Itallows drilling fluid to enter the casing while pipe is beingrun. It contains no valves.

A float shoe is similar to a guide shoe except that aback-pressure valve is included which prevents any fluidduring running and cement slurry from reentering thecasing after the job is complete. Different valve designs areavailable.


Fig. 71 Guide Shoe.

While running the string into the well, a close watch isrecommended to avoid the collapse of the casing. In mostcases, the pipe is filled for every 5-10joints added.

StNSheII

Concrete

FIoatV~

Fig. 72 Float Shoes (Sure-Seal type).

Float CollarsA float collar is a device placed at least one joint

above the cementing shoe. It contains a back-pressurevalve similar to the float shoe and provides a seat for thecementing plugs.

The float collar serves an important function. Whenonly a top plug is used, cement contamination around theshoe is possible. The plug wipes the pipe clean of the mudfilm left on the inside of the casing, even though cementhas been pumped out around the shoe. With a float collar,this mud/cement mixture remains in the casing and doesnot contaminate cement around the shoe.

Float shoes and collars are the most commonequipment in use. It should be noted that the Sure Sealtype valve works much better than a ball valve. Extensivetesting has proven that the Sure Seal type valve withstandsturbulence and displacement periods much longer than aregular ball valve type.

35

0 40 0.0[ 40 96 ST illS 1014038 213 0.10 40 90 ST illS 526133 383 0.23 40 87 ST illS 186835 1512 PREVIOUS CAS[NG SHOE

7065 1332 2.74 20 76 ST illS II7396 1832 2.39 20 78 ST illS 177773 1138 3.48 20 70 ST illS 197960 745 1.77 20 82 STillS 98288 858 0.73 20 88 STillS 168616 542 1.07 20 86 STillS 169840 542 0.00 20 91 STillS 61

10985 542 0.00 20 91 STillS 57

HOOKLOAD STATIC UPSTROKE DOWNSTROKE

AT TOTAL DEPTH: 489000 806835 171165ib


In this context, it should also be noted that back flowof cementing fluids in limited volume is a normal reactionto the displacement fluid being pressurized andcompressed. When releasing the pressure from the insideof the casing a certain backflow has to be anticipated. Thevolume of this back flow can be calculated and depends onthe length, diameter of casing, pressure and gas contentswithin the fluid.

Fig. 73 Float Collar (Sure Seal Type).

Circulating Differential-fillValveA differential valve system in shoe or collar will allow

back flow, which can be considered an advantage inrunning a long casing string. It does not require filling thepipe with fresh mud from the top, but will have to beconverted to the float function prior to the cementation.Conversion to the floating mode is often made prior toentering the open hole. While acting as a differential fillvalve, an inner sleeveis free moving according to the

Open Closed Converted

Fig. 74 Differential-fillFloat Valve.

36

.Weatherford

differential pressure due to a difference of area between theupper and lower side. The casing will fill to approximately90% of the annular column.

Wiper PlugsA bottom plug should be used to wipe mud off the

casing ahead of the cement, as well as to separate the mudand the cement. Without a bottom plug, the mudsubsequently wiped by the top plug will accumulate aheadof the top plug and could easily amount to 20 to 30 feet in5t or 7" casing at 7-9,000 feet if the mud film is only asmuch as 1/32" thick.

Top plugs are used to separate the displacing fluidand the cement and provide a shut-off if the plug ispumped down to the float collar. Some local preferencesare not to pump until the plug bumps, but instead to pumponly the theoretical calculated volume down to the floatcollar. Due to air in the displacing fluid and slightinaccuracies in measuring the displacing fluid, the actualdisplacement-volume-till-bump-up is always more thanthe calculated volume (in some instances by as much as8-10%). With large diameter double plugs that will bedrilled up, an occasional practice is to leave a smallamount of cement on top of the plug to keep it fromspinning when drilling it up.

After all the cement is in the pipe, the top plug isreleased. It wipes cement film off the casing ahead of the-displacementfluid and provides a pressure-tight seal by"bumping up" against the bottom plug.

Both top and bottom plugs should be used to helpprevent contamination. Long strings of casing shouldalways employ two plugs to help insure proper cementplacement and a successfulcement job.

Diaphragm,

MoldedRubber

Cast

Insert

Bottom Plug

Fig. 75 Wiper Plugs

Stage ToolsA stage tool is a collar within the pipe string; it

contains sidewall ports which allow cement to be placed inthe annulus in multiple stages.

This tool allows the first stage cement to pass throughthe center of the collar. A free fall or pump down plugprecedes the second stage cement and opens the ports inthe side of the collar. The second stage cement is thenallowed to move through the ports and up the annulusabove the first stage cement, after which a closing pluglands on a closing sleeve,shutting the ports again.

.Weatherford

Sl1earPins

Assembled PositionBall Lock

Locking Ring

Fig. 76 Stage Tool Schematic.

Stage collars are needed to help cover weak zoneswhich cannot withstand the hydrostatic head exerted by along column of cement slurry. By using a stage tool, it ispossible to see that the first stage cement isolates the weakzone and the remainder of the casing is cemented in thesecond stage. This allows the hydrostatic head on the weakformation to be greatly reduced and avoids fracturing thezone.

More than one stage collar may be needed whereseveral weak zones are present.

t

Running In Shutoff SleeveCIooed

Fig. 77 Stage Tool Operation

When selecting the plugs that go along with the stagetool, it must be decided beforehand what kind of operationwill be chosen. The conventional stage operation utilizesthe Free-Fall Plug System. In highly deviated wells thecontinuous pumping operation is more popular.

External Casing PackersSeveral versions of this equipment are available for

isolating zones before, during or after a cement job. Themost publicized zone isolation packer is the hydraulicallyinflatable type packer. The cement job is completed in theconventional manner and the packer is then inflated. A


second version of an external packer is the formationpacker shoe or collar that is used to pack off the open holebelow it prior to cementing so that the lower interval is notcontacted by cement. The combination stage tool packercollar functions in somewhat this same manner tominimize cement loss to a seeping zone below the stagetool during and after a stage job. A liner hanger packer isalso an external casing packer intended to be set in casing.

Liner HangersLiner hangers are widely used to eliminate the need

for full strings of casing. The common approach is to hangthem off of the bottom with hangers extending 100to 200feet up into the previous casing string. The hangerassembly is equipped with a liner wiper plug, which islaunched by the engagement of a drill pipe wiper plug atthe liner hanger. The combination of plugs are thenpumped to the float collars one or two joints above theguide shoe (See also page 6).

Depending on the type of hanger, pipe can be rotated,reciprocated or both movements done together.

The hydraulic-set hanger's main advantage is thatpipe movement is not required for setting, since the slipsare actuated by applied pump pressure. They can bewashed down although excess pump pressure could set theslips inadvertently, Once set, they cannot be set lower. Inreciprocate-to-set hangers, the slips are retracted as long aslock springs attached to the slips are restrained by a stop.Movement upward frees the springs, allowing the slips tomove up on the cones when the pipe is lowered. Care mustbe taken to avoid picking up too high when pulling thedrill pipe slips going in the hole. If the packer setsprematurely, it is possible to pick up, unseat the hangerand continue in the hole, provided the tripping sleevefallsto the down position. Rotate-to-set tools are popular insome areas because of their simplicity of operation. Theycan be washed down, the slips actuated by rotation, andthen picked up to the desired depth.

Cementing HeadsOn top of the last casing joint a plug container is used

to facilitate quick release of the plugs. The double plughead is preferable whenever elevator links are long enough.Loading has to be done with utmost care to ensure that theplugs go down in correct order. All top and bottom plugsare color coded or labelled as to their purpose.

To avoid any malfunction there are several ways to"tattletale" that the top plug has left the head: amechanical flapper on the plug container, a wire tied to theplug, radioactive nails in the plug and a Geiger counter, oras a very last resort if uncertainty exists, opening the plugcontainer to check. These plug tattletales are extremelyimportant when you plan to bump the plug and of lesserimportance if plans are to pump only the calculatedvolume to the float.

37

Casing Running Procedures

.Weatherford

A primary cementation program combines allrelevant information on objectives, environments andresources, and formalizes the instructions and proceduresthat are to be employed. A thorough study of the programas wellas instruction and delegation of responsibilities areessential for a successfuloperation. At the drilling site, theprimary cementation is normally executed under the over-all supervision of the operating company's representative.

Assignment of ResponsibilitiesMany cementations fail due to the simple fact that too

many drillers are still evaluated in terms of "feet or metersper hour" over everything else. This is quite detrimental toprimary cementation. As a guideline, the following chartgives suggestions about how the workload andresponsibilities can be assigned.

OperatingcompanyToolpusher

Area

Overall supervisionInventory /CommissioningProgram instructionsLog interpretationCalculationsMonitoring/ReportingWorking condition ofpower plant, drawworks,line, handling tools,silos, tanks, pumpsManifold instrumentation

Handling rig equipmentHandling casingAssisting contractorsStabbing - MakeupTesting of casingMud propertiesVolume control

Cement mixing andpumping system,Cementing head/plugs

Drilling/PetroleumEngineerDrillerMechanic

DerrickmanFloor HandsRoustabout

Contractors

Logging

CasingServiceMudService

CementingService

Equipment CheckA carefulcheckof all equipmentto be utilizedwill

helpto minimizecementingfailures.

.Rig Equipment. Pipe racks, walks, ramp, thread protectors. Elevator, spider, slips. Power tong, pressure tester. Fill-up line with quick opening valve. Standpipe, circulation, Chiksan joints. BOP's, cilsingrams. Slush pumps (pressure and volume). Drawworks, blocks, lines. Casing alignment tool

38

Casing Equipment and Preparation. Number, identify and measure casings carefully.. Drift casings before pulling to the rig floor.. Inspect all casing accessories/wellhead equipment.. Select the length of the landing joint(s) so that a suitable

overstand to the rig floor will be obtained upon landingof the string.

. Ensure that no casing collar will be opposite the casingrams upon landing of the string.

. The composition of the shoe track (i.e., section betweenthe cement shoe and the float collar) should bespecified. Normally a shoe track of two 'range 3joints'will be required for l3i" and smaller diameter strings.

. Have sufficient mechanical cementing aids (centralizers,scratchers, etc.) available.

. Centralize the string throughout the interval to becemented.

. Pre-install casing attachments (e.g., shoes, collars, stopcollars, centralizers, scratchers) whenever possible.Tube-Lok as indicated in the Drilling Program.

. Ensure that the test slurries are prepared with the sameconstituents as will be used for the actual casingcementation.

. Prior to every primary cementation, check the efficiencyof the pump(s) that will be used for the displacement.

· If mud pits have to be used for mixing water, ensurethat the tanks are as clean as possible. Avoid anypossibility of contamination of the mixing water once ithas been prepared.

. Prepare job log with detailed instructions for thecementation operations (reciprocation, tanks to beused, volumetric data, displacement data, handling ofthe returns while cementing, pressure testing, etc.) Thisjob log should be distributed to all personnel involved.

. Recalculate cement quantities according to the actualwell geometry, based on 4-arm caliper data. Calculateexpected casing weight prior to, during and after thecementation, and the maximum pull on the casing whilereciprocating. Prepare graphs.

. Select spacers with care. Note that their prime functionis to separate the drilling mud from the cement. Theyare not often used to displace the mud. Be aware thatviscosified and weighted spacers are equally or evenmore difficult to displace by the cement than mud withsimilar viscosity and density. Their use in high-velocitydisplacements can result in reduced displacementefficiency.Water is a most efficient spacer, but caremust be taken that sufficient overbalance is alwaysexerted.

. Ensure that all above preparations for running thecasing have been carried out before pulling the bit onthe checktrip.

. Base your centralization pattern on calculation, andensure a minimum stand-off of about 70% over theentire cemented section.

. Place scratchers between stop collars over a 3 ftinterval. The spacing of scratchers is related to theplanned reciprocation stroke. Note that scratchers in

.Weatherford

combination with pipe movement are useful fordisturbing and removing the mud cake oppositepermeable formations. They are also useful oppositewashouts, even if they do not touch the borehole wall.

The Cement JobThe casing should be lowered at a controlled speed -

running speed should not exceed 2 ft/sec in gauge hole andspecial care is required when passing through tight spotsand doglegs.

As a rule of thumb, casing is usually run at a speedthat maintains the annular mud velocity to which the holehas become stabilized. Poor running practices can inducerapid borehole pressure changes that make shale slough.Surges can create borehole stresses exceeding formationelastic limits.

The velocity at which casing is lowered is governed bya number of variables including the danger of lostcirculation, the presence of bridges or key seats, crookedhole conditions, and the clearance between pipe and hole.

Periodofhighpressure

Static Pressure

Time

Fig. 78 Pressure vs Time for Running One Joint.

Figure 78 shows a bottom hole pressure situationwhen running a joint length. The casing shoe creates apiston effect that can easily turn to a swabbing effect if thecasing is not landed smoothly enough.

Before the running operation starts, the Weatherfordcementing engineer prepares a casing weight chart to allowclose weight control during the operation.

When anomalies in hookloads are encountered,indicating hole restrictions, dog-legs or other obstacles,circulation and movement of the string are necessary toestablish a normal condition. Each open hole circulationwill also clean centralizers and scratchers of materialaccumulated during running. Any possibility of pluggingor bridging the annulus will thereby be minimized.

Casing Running Procedures

Hook loads should be plotted on up/down strokeonto a casing running graph. (See Fig. 82) If clear signs ofsticking become apparent, intermediate circulationcombined with reciprocation should be carried out to freethe casing:. Mud should be filled up after every joint.. Whenever circulation is required, it should be

established carefully, at a low rate.. At least one complete hole volume should be circulated

prior to cementing at the highest possible rate.Circulation should be continued until returns are free ofcuttings/mud cake/gas. Mud property should bechecked upon completion of the circulation. Ifnecessary it should be conditioned to obtain lowestyield point and gel strength possible.

· Cementation should not commence until everybodyinvolved is at his designated position, has been briefedand understands his function.

. During mixing several samples of the slurry should betaken and marked with the slurry weight and time ofsampling. At least one person should be solelydedicated to this activity.

. One engineer must be responsible for an accurate timelog of all operations during the cementation.

. Displacement of the cement slurry should be strictlycontrolled with volumetric measurements on the mudpits.

DisplacementLaboratory work, confirmed by field experience, has

shown the following:. Cement displacement rate should be as high as possible

but at least 4.3 ft/sec. and preferably 6 ft/sec. to achievesufficient zonal isolation with a reasonable degree ofcertainty; the higher rates are a necessity when no pipemovement is employed.

. Such displacement velocitiescan be achieved over theproductive zones in most field circumstances, provideda gauge hole has been drilled. For maximumdisplacement efficiency, thin cement slurries should beemployed to minimize downhole pressures. Field-validated computer programs should be used tocalculate the highest possible displacement rate withinthe constraints imposed by formation strength andlimitations of surface and downhole equipment. Incritical cases, estimates should also be made of theswab/surge pressure created by pipe reciprocation.

. If high velocity displacement is not possible, a plug-flow .type job can be considered. This must be pumped veryslowly (0.5 to 1.5ft/sec., preferably at the lowervelocity). However, it is not possible to obtain the highdisplacement efficienciesachieved with high-velocitycementations because of the inability to remove byplug-flow filter cake and partly dehydrated gelled mud.Low velocity desplacement is therefore considered a lastresort, to be applied only when higher displacementrates cause considerable downhole losses.

39

Casing Running Procedures.Weatherford

Tests in centralized and eccentric tubings with andwithout fluid leadoff haveshown that the displacementefficiencyis proportional to the displacement velocity.Whenever possible, accurate measurements of the returnsin various stages of the job should be carried out.

Pipe MovementAt a given displacement velocity, a much improved

displacement efficiencyis achieved with pipe reciprocationor rotation, compared to the efficiency when the casing isstationary; i.e., high displacement efficienciescan beachieved at lower (practical) pump rates if pipereciprocation is employed. This is particularly important inthe large hole/casing sizeswhere pumping capacity is ofteninsufficient to pump much faster than this minimum 4.3 ft/sec. displacement velocity.

The advantage of pipe reciprocation is so great thatthis should be an important factor during the choice ofcasing equipment. For example, the type of liner or casinghanger installed should be chosen so that it can be set ifthe string becomes stuck during reciprocation. Piperotation also has been shown to improve muddisplacement efficiency.However, special equipment isrequired, and the casing connections are exposed toadditional torsional stress.

Reciprocation may have to be carried out overprolonged periods, resulting in considerable loads on thedrilling line and the drawworks.

Whenever reciprocation is applied, it should becommenced initially with a short stroke. Only after asufficient circulation rate has been established should thereciprocation stroke be gradually increased as required. Assoon as reciprocation is established over the full strokeseveral cyclesshould be timed to be completed in two tothree minutes per cycle. The weight indicator should beclosely watched; hook loads will vary as the cement slurryis displaced into the well. If the difference between the up/down stroke increases sticking is indicated. The casingshould then be landed in the slips.

It should be stressed that the pipe movement shouldnot be abandoned too quickly, since it is considered to be amost important factor for a good primary cementation.

40

Reciprocation should be carried out during the entireperiod from commencement of circulation prior tocementing until bumping of the plug, with interruptions asshort as possible.

The pipe can also be rotated, or a combination ofboth reciprocation and rotation can be applied.

Rotation should only be used in cases where lowtorques are expected and centralizers are installed that aredesigned for this method. Special self-driving rotation-typecementing heads have to be used to avoid any over-torqueing of connections.

Contact TimeThe time during which cement flows past a given

point in the annulus is called the "contact time." Thelonger this time, the greater is the chance of removing thedrilling fluid from the annulus. From previous publishedresults, minimum contact time of 10minutes isrecommended.

Only the time during which the cement is pumped athigh velocity past the highest point in the annulus wheregood zonal isolation is required should be included in thiscontact time calculation. Any time spent displacing at alow rate just before pumping the plug should be ignored. Itis common practice during liner cementation - where it isdifficult to ensure the required contact time - to pumpextra cement that is circulated out from above the linerafter completion of the job.

Landing PracticesCasing landing practice has to be especially defined

for each well to avoid buckling or parting in futureoperations.

Three variations are usually implemented:1. Casing is landed "as cemented." That means in the

position in which it was cemented.2. It can be stretched to increase tension.3. It can be slacked off to reduce tension.

Practice and degree of application depend on theanticipated changes in wellhead loading that occur duringthe life of the well.

.Weatherford

The goal of any cementation is to achieve excellentbond from casing to cement and between cement andformation.

To continually improve the cementation process, it isvery important that accurate records be kept of all primarycementations and subsequent well performances.

Three means commonly used to locate cement behindpipe are:

. temperature survey

. radioactive-tracer log

. accoustic logs

Temperature Survey

Although temperature surveys and radioactivetracers have been in use longer, they do not provide thequantitative data that bond logs do. A temperaturesurvey measures the heat generated during the setting ofcement behind the pipe. This heat of hydration raisesthe temperature in the wellbore enough that a device setopposite the cemented zone can detect and record theincrease in temperature. Such a survey can usuallylocate the top of the cement with reasonable accuracy,provided the recorded temperature anomaly is clearenough. For best results, a temperature survey shouldbe run within the first 12to 24 hours.

A B C

NormalGradient

/Cement

/TOP

Temperature

Fig. 79 Idealized Temperature Log

Figure 79 shows an idealized temperature log in ahomogeneous lithology environment. Curve Ccompared to Curve B illustrates the effect of an

Evaluation of Cementation

enlarged borehole with a corresponding increasedcement thickness (after Folmar).

Radioactivity Tracer Log

Radioactive isotopes are added to the cementslurry. Concentration will be measured after thecementation, thus determining the presence of cementin the annulus. This method will not givemore than aguess about the quantity of cement and it does notallow any interpretation of the bond quality.

Acoustic LogsThe Cement Bond Log and the Variable Density Log

(CBL-VDL) are two types of acoustic logs.

The acoustic properties of cemented casing areinfluenced by the quality of the bond from casing tocement: The waves travelling along the casing areattenuated when energy is lost to the environment of thecasing, i.e., when the bond is good.

The Cement Bond Log (CBL) is a recording of theamplitude of the first arrival of energy on the 3 ft receiver.

The Variable Density Log (VDL) is optional andsupplements the information given by the CBL; it is a full-wave display of the 5 ft receiver signal.

The 3 ft and 5 ft spacings correspond to the differentrequirements of the two logs.

The sonic tool used to evaluate the cement quality isschematized in Figure 80; the transmitter emits acousticwave trains of short duration. The signal travels throughthe casing, cement and formation before it reaches tworeceivers, 3 ft and 5 ft from the transmitter.

Transmitter

3' Receiver eBL

5' Receiver VOL

Fig. 80 CBL Tool.

41


. :.t.QQ....

11Sec.lFt.

Amplitude - MV.501 10 20

EssentiaUyNo

CementBond

75MV

/Casing

Collars~

IIII--t r--/

GoodBond

InstrumentalSaturation

Channeling?

PoorBond

Fig. 81 Schematic CBL-Log

The sonic transit time curve is presented on the left.The T recording normally corresponds to the transit timein steel (57 microsecjft) regardless of the amplitude size.The T curve shows variations when the tool passes by acasing collar. This can also be seen on the amplitude curvein the free pipe, and to some extent in cemented pipe.

15

*'~ 10icoII:c.210"c"11 5

Experimental Points

/.

o2 3 4

Cement Thickness, Inches

Fig.82 Attenuation Rate vs. Cement Thickness

The diagram (Fig.82) shows the attenuation rate vs.thickness of neat cement cured for 24 hours. Laboratoryresults indicate that only for thicknesses of :in or greater isthe full attenuation effect achieved. Therefore diameters ofcasingsshouldbechosento allowa :in minimumclearancein the drilled hole.

The relation between the amplitude and the percentageof bonded cement is a straight line. This evidence leads tothe conclusion that it might be possible to scale thereadings of the cement bond log percentage in terms ofbond index.

42

.Weatherford

The current compressive strength and percent ofcasing circumference bonded will affect the CBLamplitude. It is impossible to qualify the interpretation ofa CBL.

No cement or

cement not bonded

oo 20 40 60

% Circumference Bonded

80 100

Fig. 83 Attenuation Rate vs. Circumference Bonded.

During field testing of the cement bond log, systematicstudies of bonding vs. time were undertaken in severalwell. Fig.84 shows the results in a well where 9-§!'casingwas cemented in a 12t" hole. In this section, bonding wasnearly complete after 33 hours. However, there aredifferences in the development of bonding with time.

4 Hrs. 18Hrs.

Mlcrolog IAmplitude - MV n AmpUtudeo 50 200

33 Hrs.

MudICake

Fig.84 Time Effect on Bond.

Opposite sand sections, bonding was complete atter18to 22 hours, while an additional 12hours was neededfor sections opposite shale. Evidently, the cement loseswater to the permeable sections and sets more rapidlythere. The general rule is that the cement bond log should

100

80

.$co 60II:

.910"c

40

.g.

.Weatherford

not be run until 48 hours after the cementation in order toachieve the true cement bond reading. This again is highlydependent on the cement type and additives used in theslurry.

Fig. 85 Bond Damaged by Squeezing

It often happens that the original bond can bedestroyed by a squeezejob. The first cement bond logshows a poor cementation between 8000 ft and 9000 ft andan intermittently fair bond below this level.The formationwas then broken down with water and two squeezesperformed at 4000 psi (Fig. 85).

The second cement bond log run shows a good bondbetween 8900ft and 9000 ft, but the bond below had beendamaged.

As a matter of fact, squeezing seldom producessatisfactory results.

Casing Evaluation Tool (CET)Classical cement bond logging tools measure the

amplitude or attenuation of plate waves propagatingaxially along the casing. The design of the new CET toolovercomes previous tool limitations by using principles ofcasing thickness resonance.

The Cement Evaluation log provides information onthe cement strength and its distribution around the casing.It investigates the cement radially and gives eight separateindications of cement distribution and quality, in additionto measurements of casing diameter, casing roundness andtool eccentricity.

Eight ultrasonic transducers are positioned radiallyaround the CET sonde 4Y apart. Each transducer emits abeam of ultrasonic energy in a 300- to 600-kHz bandwhich covers the resonant frequency range of most oilfieldcasing thicknesses (Fig. 86).

The energy pulse causes the casing to ring or resonatein its thickness dimension. The speed at which thevibrations die out depends on the material behind thecasing. Most of the energy is reflected back to thetransducer where it is measured, and the remainder passes


into the casing wall and echoes back and forth until it istotally attenuated. A ninth transducer continuallymeasures acoustic travel time of the casing fluid column sothat the other eight transducer travel times can beconverted to distance measurements.

The CET log graphically displays a complete radialmap of the cement-to-casing bond and indicates allchannels in the cement sheath.

Experience has shown that when there is good cementsround the pipe, the bond to the formation is usually good,too. When the cement sheath is very thin, the CET toolresponds to formation arrivals. However, when the cementis thick, the formation reflections may be too small tomeasure. So, if good pipe bond but bad formation bond issuspected, the best interpretation can be made bycombining the Cement Evaluation log with the CementBondjVariable Density log.

liT-\

................:';'::.:':'

<;/{..,'.'.:'"::"0

~

...........:.::~:\

........

Receive Mode

Fig. 86 CET-Cement Evaluation Tool.

In general, free pipe produces large energy reflections(large amplitudes over long periods) and well-cementedpipe produces fast decay times and low energy reflections.The CET tool takes these three measurements:I. Gate WI measures the initial part of the reflected

energy. The first arrival is used in the time (distance)calculations.

2. Gate W2 measures the later arrivals; the combination ofWI and W2 allows compressive strength calculations.

3. Gate W3 measures non-exponential energy decay fordetection of fast formations.

W1

FitePulse

DT

Fig. 87 Measurements made on each Waveform.

43

Evaluation of Cementation.Weatherford

The sonde body is supported at each end by springsand roller centralizers which provide efficient centering atdeviations up to 70°without damage to the casing surface.The electronic signal processor and telemetric cartridge arelocated above the sonde and are mechanically connectedby flexjoints for use in deviated wells.

Recommended Job DocumentationWeatherford engineers have experienced that

cementation improvements rely extensively on an accurateand detailed documentation of the casing running and thecementing operation. This information is invaluable forevaluating cement jobs and it is absolutely essential ifimproved procedures and equipment are to be developed.

The following should be documented:

. Casing DetailsSize,weight, grade, equipment (centralizers,

44

scratchers, float shoes and collars, stage collars, cementbaskets, etc.), special inspection and handling procedures,joint makeup tests and procedures, running speed, detailsof movement during cementing and landing practices, etc.

. Cement DetailsVolume, type and composition, density, rheology

characteristics, displacement procedure (rate, use of topand bottom wiper plugs, preflush and spacer fluidsincluding description and volume, etc.), servicecompany,pressure and rate charts, surface circulating temperature,pumping time.

. Other DetailsLost circulation, premature build-up of pressure,

detail of any operation problems, evaluation of historicalproduction data and comparison between wells.

.Weatherford

Case 1.

A number of cementing jobs were evaluated in order toestablish whether theoretical conclusions regardingrelationships between flow patterns, centralization andpipe movement could be confirmed by field experience.The statistics below are derived at by examining a total ofover 100jobs which were cemented using identicalmethods.

Deviation of the examined wells ranged from aminimum of 10degreesto a maximum of 60 degrees.Acomputerized lateral force program based on requirementsof API Standard IOD was used to determine the mostefficient spacing of centralizers.

Only critical sections, i.e. above the casing shoe, acrosspay zonesand beneath previously set casing wereexamined and compared. On a 0-50 mv CBL scaleamplitudes exceeding 15mv were considered as poor, 5-10mv asgood and lessthan 5 mv asexcellent.

CBL/VDL Interpretation

ExcellentGoodSufficientPoor

Reciprocationa) b) c)

42 II 416 3 105 2

Flow Patternd) P L T3 13 3 10

20 22 12 223 10 5 6

5 I I

a-d = Different reciprocation periods. P = Plug flow.L = Laminar flow. T = Turbulent flow

Displacement Flow Pattern

5" 9%" Total7"

TurbulentLaminarPlug Flow

25II16

91034

392150

352045

5

5 52 53 110 100

Case Histories

Reciprocation Period

5" 7"

a) None 2 7b) During circulation 3 45c) Throughout

cement job - 26d) Continued

movement (Post Plug) - 12

%

1559197

Fig.88

30 7" CASING

Total

449

1397

1288

Scratchers/

Centralizers

23 49 45

o 40 80 120 160Number oi lIems Installed

19 28

30 9%"CASING

31

200

200

The majority of examined cementations show good toexcellent bonding. It should however, be realized that pipemovement rather than flow regime influence the quality ofa cementation.

Scratchers

Centralizers

o 40 80 120 160Number 01items Installed

45

Case Histories

Case 2.

In a large field development in the Northern North Seaarea numerous wellswere drilled, using generally thefollowing casing program:

The Weatherford Lateral Load Program was utilized todetermine the necessary centralization to achieve adequatecasing stand-off. The kick-off point for deviated wells wasat 1200'with a build up rate of 1.5degrees/IOO'for the 26"hole. This was followed by a rate of 2°/100' to maximumdeviation of 60° for the 171"hole.

7000'~NW SE

NORTH SEA AREASTRUCTURAL

CROSSSECTION

Fig. 89

The cement slurry was class G with friction reducers asrequired- slurryweightwas 15.8Ibs/gal.

Mechanical cementing aids were used as recommendedin the following manner:

Casing Av. open hole Centralizers Stopcoll. Scratchers

20"13~"9i"7" liner

1480'5900'3610'1640'

40-4570-100

120-150100-130

70-100120-150400-450 260

As a rule, throughout critical sections a minimum of 2centralizers were installed per joint of casing whendeviation exceeded 10°.Installation on 7" liners wasModified Post Plug pattern and they were reciprocateduntil displacement started. The CBL/VOL (Fig. 90) belowshows excellent bond throughout this area.

46

.Weatherford

. ~i . I' I r I I . .~ I - -

Fig. 90 North Sea Area CBL/VOL

Hole size Approx. TD Casing

26" 2500' 20"171" 8200' 13i"12t" 11800' 9i"8t" 13800' 7" liner

.Weatherford

Case 3.Various attempts were made to improvethe cementationof7i" and lOr' casing strings in the Anguille and Torpillefields offshore Gabon.

Poor cemen.tlwnding had necessitated squeezejobs andresulted in collapsed intermediate strings. Maximumdeviation ranged from 28 degrees to 45 degrees. The mostcritical part of the operation were differential pressureproblems whilst running the production string and flashsetting of cement during the displacement period.

After a feasability study it was decided to followWeatherford's recommended cementation procedures andhave the jobs attended by a Weatherford CementationEngineer. Well No. GRD 100 provides a typical examplefor the centralizer installation patterns used. A CleavageBarrier was installed over the pay zone to reinforce thecasing and to separate a water bearing formation.

Ct. loanlr.lt!C3.'c.nlr.I3JIIPP. pontPIutxxxx . a..v.. B......

Ci"-

=:x&..=~

Fig. 91

Case Histories

WELL No. G.R.M. to 07......

W.lghtChlrt

Fig. 92

Immediately above and below this a post Plug pattern wasused to provide superior bonding to the formation. For the7i" string shown a total of 108ea STIlI non-weldcentralizers and 136ea CTIA scratcherswere installed.The recommendation called for useof classG cement withaddition of retarder and fluid loss material.

During the running operation one intermediate circulationwas necessaryto normalize string weight during up- anddown stroke. The chosendisplacement rate was 7.5 bbls/min, reduced to 2.5 bbls/min when the slurry entered the9f'annulus. The string was reciprocated throughout thedisplacement period.

After the successfulconclusion of this job similarprocedures were applied for the following wells andreciprocation of casing strings becamestandard practice.

The.operating company concluded that carefullyselectedcements and additives plus the application ofWeatherford recommended installation patterns andrunning procedures including reciprocation, hadsubstantially improved cementation results.

47

Case Histories.Weatherford

N\lmberofJol"I.~41.14 'AV.)

Fig. 93 Weight Chart

The casing was reciprocated during the circulation aswell as during displacement of the 693 bbls of oil basedmud until the plug was bumped.

The operating company reported this job as thesmoothest ever and a CBL/VOL run confirmed anexcellent result of the cementation throughout criticalareas. Fig. 94

48

Case 4. i I.N 111 {;:

In Spain a string of 9i" casing was run to a total depth of. .........-1

16,456'.Expected problem areas were sticking of the stringduring the running operation and channeling due to thehigh deviation. - +.-.

The 13f' casing had been set at 9,842'. Kickoff point"

was at 2,625' with a gradual buildup to maximumI':

deviation of 69 degrees.tT

A Weatherford computer program was utilized toT

determine optimum spacing of centralizers. A hydraulicci::

program was provided to optimize the running procedure. _. 3A total of 185 NWST centralizers was installed as

follows:I I lor I I I I I -I

Joint 1-5 = 2 centralizers per jointJoint 6-15 = 1centralizer per jointJoint 16-35 = 2 centralizers per jointJoint 36-160 = 1centralizers per joint

Positive centralizers were installed below the BOP stackand above the I3f' shoe to provide the necessary standoff.All centralizers were installed over stopcollars to avoidexcessivebending forces to the buttress type connections. t-:

Total running time for the string of 400joints was 25hours; this included one intermediate circulation in theopen hole section at 12,140'.

The comprehensive Weatherford computer program wasused to calculate expected drag forces and weightdifferentials between up- and downstroke. The minimumrunning time per joint was set at 40 seconds. The casingwas run without problems to bottom and recordedhookloads corresponded with calculated calues. Themaximum hookload experience was 530,000Ibs (Fig. 93).

ICASABLANCA FIELD_SPAIN

.." I I.----1 mm.. I VP"i_______

I _.I am\

.Weatherford

Bibliography

Geoge O. Suman, Jr. and Richard e. Ellis, "Cementing Oiland Gas Wells", World Oil (1977).

George O. Suman, Jr. and Richard C. Ellis, "CementingHandbook", World Oil, Gulf Publishing Co. (1977).

Pat Parker, Clark Clement and George O. Suman, Jr., ."Basic Cementing", Oil and Gas Journal (1977).

W.e. Goins, "Better Understanding Prevents TubularBuckling Problems". World Oil (January 1980andFebruary 1980).

Clyde Cook and L.G. Carter, "Gas Communication inDirectional Wells". Drilling Magazine (July 1976).

Rudy B. Callihan, "Improved Cementing Techniques forLarge Diameter Casings", Drilling Magazine (October1976).

"Use of a Well Model to Determine Permeability", PaperSPE 8253 presented at the SPE-AIME 54th Annual FallTechnical Conference and Exhibition, Las Vegas, Nevada,September 23-26, 1979.Copyright 1979,SPE-AIME."Axial Buckling Stability of Cemented Pipe", Paper SPE8254 presented at SPE-AIME 54th Annual Fall TechnicalConference and Exhibition, Las Vegas, Nevada,September 23-26, 1979.Copyright 1979,SPE-AIME.

"Flow after Cementing: A Field and Laboratory Study",Paper SPE 8259 presented at the SPE-AIME 54th AnnualFall Technical Conference and Exhibition, Las Vegas,Nevada, September 23-26, 1979.Copyright 1979,SPE-AIME.

Weather Ford Cementing Program Handbook)

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