Cementing Handbook-George Suman

5/24/2018 Cementing Handbook-George Suman

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World il sCementing oil n g swells in luding sing h ndling pro edures

BYGEORGE o SUMAN JR ANDRICHARDC ELLIS

AcknowledgmentThis handbook is the result of a comprehensivestudy of cementing oil and gas wells including cas-ing handling procedures. The authors basic workwas sponsored by AMF Tubescope Inc.; Bakerline

a division of Baker International Corp.; DowellSchlumberger; Oil Tool Division PENGO IndustriesInc.; Lynes Inc.; Texas Iron Works Inc. and VarcoInternational Inc. The authors wish to express theirappreciation to these companies for their sponsor-ship and for the complete freedom allowed inpreparation of all material. Thanks are also duethe sponsors and many other manufacturers forproviding information and illustrations and to thosein industry who reviewed the manuscript and con-tributed many helpful suggestions.

Copyright@ 1977All rights reserved

W l ld l P.O. Box 2608 Houston Texas 77001


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ableof ontents

ementingOil and asWells HandbookPart 1 Basic functions of cement aregiven with concepts to consider in mudpipe and hole preparation to preventjob failure . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 5Part 2 Casing inspection and pipehandling methods including threadmake up control hydrostatic testinglanding practices . . . . . . . . . . . . . . . . . . . . . . .14Part 3 How basic cements and additives

can be tailored to give desired propertiesfor completion and remedial operations. . . .22Part 4 Practical interpretation ofrheology annular displacing forces.How to avoid bypassing mud duringprimary cementing .32Part 5 Guidelines for downholeequipment use stage cementingmethods new concepts for cementinglarge diameter casing . . . . . . . . . . . . . . . . . . .41Part 6 Liner applications and equipmentused for installation. Common problemsto avoid while pumping displacingcement 50Part 7 A review of cement plugplacement tubingless completiontechniques and the art and science ofcement squeezing 57Part 8 Methods for evaluating primarycementing effectiveness plus a wrapupof several new tools to improvecompletion operations 66

bout the uthorsGEORGEO. SUMAN JR. attended theCalifornia Institute of Technology andthe University of California Berkeley ,graduating with a B.SM.E. in 1952. Hespent two years with Aramco in SaudiArabia and 18 years with Shell Oil Co.working primarily with drilling, comple-tion and stimulation design and applica-tion. In 1978 he formed CompletionTechnology Co. which is actively work-ing with a number of client companiesin improving well reliability and profitability. Mr. Sumanhas authored many technical papers on well completion anddrilling techniques and he holds numerous patents and ap-plications in these specialties. He is a member of API andSPE and a registered professional engineer in Louisianaand Texas.RICHARDC. ELLIS graduated from theWisconsin Institute of Technology in1962 with a B.S.M.E. and from theUniversity of Wisconsin in 1968 withthe M.S. in mining engineering. Hespent nine years with Shell Oil Co.working on design and application ofartificial lift, sand control and wellcompletions for primary, waterfloodand thermal recovery operations, bothonshore and offshore. His latest assign-ment with Shell was production engineering section leaderfor the Western U.S. and Alaska. Mr. Ellis joined the staffof Completion Technology Co. in 1976. He is a member ofSPE and a registered professional engineer in Texas.


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Cementing oil and gas w lls includingc singh ndlingproceduresPart 1 Basic functions of cement aregiven with concepts to consider in mudpipe and hole preparation to preventjob failureGeorge o. Suman, Jr., PresidentandRichard C. Ellis, Project Engineer,CompletionTechnologyCo.,Houston10-second summary

Opening article discusses basic cement properties inrelation to ability to support casing loads and preventdamage or joint loss. Mud selection, and procedures toprevent differential pipe sticking during cementing aregiven, and examples of casing defects found in new pipeare shown to encourage careful pre-job pipe handling.

FROM THE COMPLETIONSPECIALIST Sviewpoint, properprimary cementing should be the operator s main concern.Poor displacement efficiency which leaves a substantialvolume of mud at the cement-formation interface canlead to just about every completion and production prob-lem in the book-oil and gas can be lost from the payzone, stimulation fluids and enhanced recovery chemicalscan bypass the formation, extraneous fluids may be pro-duced and the borehole may not be properly supported.

It is important to plan for the primary cement job longbefore casing is run into the hole, to avoid common prob-lems such as improperly conditioned mud and stuck pipe.And the casing string itself should be carefully inspectedand handled to avoid damage that can cause failure inotherwise properly designed strings.

This article introduces critical concepts to consider inpreparing for the primary cement job, including discus-sions of:

~ The function of the cement sheath in supportingthe formation and protecting the casing from various

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About the seriesField engineers and others who handle casing andcementing for present-day wells are responsible for oneof the most critical phases of well completion. It hasnever been so important from the standpoint of safety,environmental protection and economics to insist that thebest-available technology be applied.Unfortunately, much important research and technicaldevelopment has not been interpreted and applied directlyto the operational phase in a straightforward and concisemanner. It is the objective of the authors of this exclusivenew series to fill that large gap between research and fieldoperations.The following subjects will be covered in the eightarticles:1. Functions of cement, precautions to take duringdrilling, common causes of casing and connection failures2. Casing handling, recommendations for inspection,make-up and testing3. Cement slurry chemistry and use of additives4. Displacement mechanics and rheology considera-tions, need for pipe movement and centralization5. Primary cementing, proper use of downhole andsurface equipment6. Liner cementing, techniques, problems, how toevaluate results7. Special cementing, recent innovations, remedialsqueezes, plug-backs, tubingless completions8. Job evaluation methods, logging, how to locate topsand define bond effectiveness, tests for zonal separation.A format similar to WORLDOIL S Sand Control Series

November 1974-June 1975) will be followed in thesepresentations, including sequential development and dis-cussion of concepts and application, with frequent refer-ence to preceding material.The authors make liberal use of published literaturewith grateful acknowledgment of the original investi-gators. An extensive reference list is included, and toget maximum benefit from this series, readers are en-couraged to pursue the original works where importantconcepts cannot be adequately discussed due to spacelimitations. -Editor


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FOR E

EMENTSLURRY U;~i; ~}--; :.::: . ::,: ;: PRESSURE> :;~: ;\..=~.B : :\~ ~ ,::j:HYDRAULIC BONDm. .;. I .......... ,.. ;. .,.:..: 0 \ .:.- . .,.0- ... .:j ~~ ;: ; ;i~~:. I ..

A _.. n.....SHEAR BONDPRESSURE

/ 1f7~U ..SAWED-OFF HERE FORBOND TEST

EMENT

Fig 1-Lab tests to measure casing/cement bonding charac-teristics. Test A3 measures axial loading strength. Test B3,C and D measure hydraulic bond. In test C, after cementingunder controlled pressure, the casing is sawed off 10 checkbonding. Test D, is a direct measure of cement/pipe adhesionstrength in samples formed in a 7-inch mold.

kinds of damage such as fault shear, perforating deforma-tion, and joint loss while drilling

~ Drilling fluid selection and conditioning to improyecement displacement efficiency and prevent differentialpipe sticking during cementing, and

~ Common causes of casing failure that can adverselyaffect the cement job as well as future operations, includ-ing mill defects appearing in new pipe.

Discussions are illustrated by schematic drawings,curves, tabular data and photographs. An extensive ref-erence list appears at the end of the article.Cement used in primary cementing is normally designed:

1. To support the axial load of the casing string andstrings to be run later2. To seal intended production or injection intervals

from overlying or underlying permeable sections (zoneisolation)3. To protect the casing from damage or failure, and4. To support the borehole through the productiveinterval.

XI L LO D SUPPORTHigh axial loads may be imposed on the casing string

and/or surrounding cement by landing and suspensionmethods and later operations. And the cement strength

6

required to support such axial casing loads has been de-termined through shear bond testS.1,2.3The axial load which breaks the cement bond has been

measured with the test apparatus shown in Fig. 1(A) .In this test where the surface in question is the outerperiphery of the inside pipe, the ability of cement tosupport axial casing loads was found to be proportionalto the area of contact between cement and the casing.Therefore, support coefficient,2 shear bond3 or sliding re-sistance,4 as it is described by various investigators, is theload required to break the bond, divided by the surfacearea between cement and pipe.

Shear bond strength increases with cement tensile orcompressive strength as shown in Fig. 2.2 A fairly narrowrange of shear bond at a given tensile strength resultedfor various cement compostions tested. And a significantreduction in shear bond was caused by mud wetting ofthe pipe. Poorest results were obtained when the pipe wasmud-wetted and no attempt was made to remove the mudfilm.

Based on these worst-case results, Bearden and Lane2provided a relationship for determining support capabilityof a cement sheath, conservatively utilizing results formud-wetted and non-displaced co ndi tions. ModHyingtheir relationship to utilize compressive strength (assumedto be 10 times tensile strength), gives the formula:

F=O.969 ScdH,Where:

F = force or load to break cement bond, poundsSc = compressive strength, psid = outside diameter of casing, inchesH = height of cement column, feet.

For example: For one bonded foot of 7-inch casing,using 500 psi compressive strength cement: F = 0.969 X500 X 7 X 1 = 3,390 pounds.Required strength The load to break the cement bondduring hanging and drilling-out operations normallywould not exceed weight of the casing string (such as sur-face pipe) plus miscellaneous loads (such as weight onbit when drilling out the shoe joint). Therefore, the loadcapacity noted above, 3,390 pounds per foot of cementcolumn, provided by the relatively low compressivestrength of 500 psi, should be more than adequate tohandle anticipated axial loads.

Thus, as this example indicates, the equation permitscalculation of approximate load capacity for various pipesizes and cement compressive strengths.

Cement compositions normally can be formulated torapidly develop adequate strength for casing landingloads. This allows drilling operations to proceed withlittle or no waiting-on-cement (WOC) time.

Also, low strength filler cements, which are relativelyinexpensive and of low density-and less likely to inducelost circulation when high cement columns are required-may have adequate compressive strength to meet axialload support requirements.

In addition to water-based mud wetting of the pipe-which is allowed for in the above equation-other factors

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that affect cement shear bond performance with respectto axial load are:. Casing collars, which increase the ability of the ce-

ment to support axial loads. Low water-to-cement ratios which increase slurry

density and improve shear bond because of increased com-pressive strength, Fig. 3.4

. Radial loads imposed on cement and casing by theformation, which should increase shear bond due to theincreased friction between pipe and cement

. Oil-based mud wetting of the pipe which lowersshear bond to a greater extent than water-based mudwetting

. Mill varnish on the exterior of the casing whichlowers shear bond

. Roughness of the exterior casing surface, such asrust or special resin-sand coatings, which can increaseshear bond substantially6 (Normally such special coatingwould not be required for axial load support becauseminimum shear bond strength is adequate)

. Raw cement characteristics, such as fineness of grind,may also affect shear bond strength

. Cement contamination by mud which lowers shearbond appreciably, see Fig. 3.

. Displacement mechanics and efficiency which affectthickness and continuity of the cement sheath aroundthe casing, and

. Pressure/temperature effects which can contract thecasing diameter after the cement hardens. This factorwill be discussed in a later article.

ZONE ISOLATIONAlthough cement with a low compressive strength may

be adequate to handle axial and rotational casing loads,high ultimate strength may be required for zone isola-tion and to support the borehole. Therefore, cementcompositions should be selected which quickly provideadequate compressive strength for continued drillingoperations but which also provide adequate strength,ultimately, for production operations.

A comprehensive study of factors governing zone isola-tion under downhole conditions would be very complex.Zone isolation depends, in part, on load interactions be-tween formation, cement and casing, some of which arenot well understood. Further difficulty arises in deter-mining type and magnitude of loads imposed by fluidinjection pressures and temperatures, and production pres-sure drawdown and depletion.

For these reasons, only qualitative judgements havebeen attempted in studies to date and these usually relateto the hydraulic bond which indicates adhesion betweencasing and cement, or between cement and formation.The actual relationship between hydraulic bond mea-sured in the lab, and downhole zone isolation has notbeen reported, if such a determination has been made.Bonding test. Various investigators3,5,6 have measuredhydraulic bond. Test arrangements are shown in Fig.1(B) .3,6and Fig. 1(C) 5 Pressure is applied to the exteriorsurface of the casing causing the casing to becomeWORLD OIL 1977

350 TYPE CEMENT1. (C)2. SPECIAL (A)3. (A) 6 GEL4. (A)5. (A) LATEX6. OXYCHLORIDECEMENT7. (A) MUD WET, WATERWASHED8. EMULSION CEMENT9. 50/50 POZ., 2 GEL10. (A) DISPLACED PAST

MUD WET PIPE11. (A) MUD WET, NODISPLACEMENT

300\~ 250,ci :is 200m ,a: 150


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60004 12 CASING BEFORE PERFORATING

.4000

Ci511.:i 2000l-e )ZWa:I-CJ)W>Ci5 6000CJ)wa:11.8 4000

o .HOLLOW CARRIER JEToEXPENDABLE JET ._ PE~FORATIONPRESSURE

2% TUBING 2000

o 4000 60002000

Fig 4- Test setup to measure perforating effects on hydraulicbond with pressure from inside and outside. Targets weretested, then perforated In a separate pressurized well, thenreturned for testing as shown. Perforations were placed abouttwo inches from the bottom of the 12-lnch targets. Resultsare plotted in curves. Lower curve shows bond was usuallydestroyed when compressive strength was below about 2,000psi (after Godfrey and Methven)13.epoxy to the exterior of the pipe by the patented Ruff-Cote process. These coatings normally are rated to 300-3250 F.The pressure at which failure of the hydraulic bondoccured in the test shown in Fig. 1 C) can be increasedby:

1. Preventing formation of the micro-annulus by con-trolling pressure differential across the casing as the ce-ment sets, and/or2. Attaching seal rings of deformaJble rubber to theexterior of the casing sealing rings designed to stop mi-

gration of fluid between the casing surface and the insideof the cement sheath are available for field installation.And the above tests indicate such devices should increasezonal separation efficiency) .However, zone isolation is routinely obtained in thefield at greater differential pressures than those causingfailure in these hydraulic bond tests. Therefore, suchtests are probably not completely representative of down-hole conditions everywhere.Effects of mud wetting Further tests were conductedto more directly measure adhesion between cement andpipe,7 Fig. 1 D). These tests, do show an advantage forthe resin-sand exterior, in the mud-wetted condition,which was not apparent in the previously discussed test,see table.

However, it should be emphasized that when resin-sandcoatings are used downhole, effectiveness should be in-creased by removing mud from the casing surface usingpre-flushes ahead of the cement and cement scouring.8

Effect of mud film on bond strengthSurfaceconditionDry .Mudilm.........Dry ....Mudfilm ....Dry .Mudfilm ....Dry .Mudfilm ....Dry .Mudfilm.........

Surface coatingMill varnishMillvarnishRustyRustyAcid etchedAcid etchedSandblastedSandblastedEpoxycoated, 6-12mesh sandEpoxycoated, 6-12mesh sand

Hydraul ic bond, psi


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chaxge and the expendable 1-11/16-inch OD charge was10.0 grams.

Before perforating, hydraulic bond strength increasedwith increased compressive strength, Fig. 4.

Hydraulic bond strength was destroyed by perforatingwhen cement compressive strength was low, Fig. 4, butwas unaffected when cement compressive strength ex-ceeded 2,000 psi. Therefore, high compressive strengthcement appears best from the standpoint of zone isolation.Expandable guns vs. carrier guns. The cemen tsheath tends to minimize casing damage caused hy ex-pendable perforating charges,12.l3 Fig. 5. And expendableguns of nominal charge, for example through-tubing guns,may be used with little or no danger of serious casingdamage. Although damage may occur to flawed or milldefective casing, particularly if unsupported by cement.

However, expendable charges may split casing oll rsthat are unsupported by cement.13 And large expendableguns, over about 20 grams, frequently damage partiallysupported or unsupported casing.

Conventional hollow carrier, steel shaped-charge gunscause only slight casing deformation and essentially nodamage regardless of support, because most of the forcesfrom the exploding charges are contained by the carrierbody. However, no data has yet been reported on theeffect of using extra strength charges in carrier guns, orspecial chaxges designed to produce larger than normalholes.

As another important point, it was also determined inperforating tests12 that cement compressive strength is notan important factor in preventing casing deformation atthe perforation point, Fig. 5.

CASING SUPPORT PROTECTIONThe cement sheath between casing and borehole servesan important function in protecting the pipe from the

stresses of formation movement, and in preventing un-screwing and possible loss of bottom joints in surfaceand intermediate strings. However, certain propertiesof this cement such as its contriobutions to collapse resis-tance of the installed casing may be greatly overrated.Salt flow. Casing damage can be caused by lateral loadsresulting from flow of salt formations.14 Salt may flowin various ways depending on combinations of overburdenload and temperature. And it may not be economicallypractical to design casing for the most severe situationsof non-uniform loading which can occur, such as theflattening effect illustrated in Fig. 6 (top).

However, when the annulus is completely filled withcement, casing is subjected to a nearly uniform loadingapproximately equal to the overburden pressure, and,although modes of failure may be different, casing design,to withstand uniform salt pressure can be computed onthe same basis as designs to withstand fluid pressure.

Failure of casing by non-uniform loading in inade-quately cemented washed-out salt sections should be con-sidered a drilling and cementing problem rather than acasing design problem. Salt-saturated or oil-based drillingfluids axe often used during drilling to minimize wash-outs, and in special cases salt-saturated cement is usedduring cementing.Fault shear. Casing failure caused by formation move-

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C/) 0.5w:I:o~ 0.4zg 0.3


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LOADING

SALT FLOW

FAULT SLIPPAGE

~UDONLY

Fig. 6-Cement sheath effects with formation loading. Strong,well centralized cement sheath, top, can prevent flatteningeffect of salt flows in washed out holes (Cheatham andMcEver) . But In fault slippage zones, bottom, cement sheathmay cause more damage by holding pipe rigid through shearzone.

CEMENT SLURRYMUD FILMCASING - - ---

~MUD MUDACCUMULATIONFROMFILM

1---- -----

TOP PLUG

CEMENTSLURRY

Fig. 7-Mud film on casing should be removed by bottomplug when displacing. Drawing shows how, with top plugonly, mud is removed after slurry passes to build up underthe plug and be deposited in the critical area around theshoe joint (after Owsley) ..connections and controlling rotary speed, as discussedbelow.

To avoid loss of joints when cement is to be drilledout of the shoe, these practices should be followed:1. Select a competent formation for the casing point.

Drill-out with drilling fluid which will maintain stabilityof this formation. Avoid dogleg sections, or sharp curves10

in directionally drilled holes near the casing point.2. Weld threads on H-40 pipe with a ~-inch fillet

weld (see cautions below) or properly clean threads onJ or higher grades with volatile (not oily) solvent, andapply thread~locking compounds to both sides of thelowermost couplings, including the three to six couplingsjoining the bottom four to seven joints. When a bottomplug is used, Schuh19 recommends strengthening threecouplings; when a plug is not used, six couplings.

3. Follow other good practices to be discussed in thisseries, i.e. proper downhole casing equipment, pipe move-ment, high displacement rates, chemical washesor spacersahead of cement, adequate centralization, etc.4. Use good quality cement that will develop high

early compressive strength, and adequate shear bond,for the last portion of the slurry to fill the annulus-fromshoe upwards 200. to 400 feet or 10. of casing length) .Elevate compressive and shear bond strength of the ce-ment around lower joints by decreasing water-to-cementratio increasing density) of last portion of slurry, Fig. 3.

5. Use two plugs. Without a bottom plug, mud filmfrom the inside casing wall can accumulate beneath thetop plug and be deposited in and around the shoe joints/aFig. 7. Fill-up for various film thicknesses can be signifi-cant, for example: For 10,000 feet of 5~-inch casing,1/16, 1/32 and 1/64-inch thick films would fill 510, 260.and 130 feet, respectively.Even when a top plug is used, accurate displacementcalculations should be made to avoid over-displacementand mud or water contamination around the shoe.6. Release surface pressure following cement placementto minimize chance for a micro-annulus to form between

casing and cement. However, surface pressure is some-times used as an aspect of casing landing operation toprevent casing instability and buckling conditions.217. Do not disturb casing until cement has obtained

initial set-about three times thickening time. Keep drillpipe out of the hole until after this time. The cementcomposition should have minimum 500 psi compressivestrength some say 1,000 psi) at time of drilling-out.

8. Control rotary speed while drilling cement out ofcasing, as indicated in Fig. 8. But if the casing joints havebeen improperly strengthened, i.e. misapplied thread lock-ing compound or welded J-55 or higher grade casing,permissible rotary speed may be only one tenth or lessof values shown.el ing recommendations. Lower casing grades,H-40, present few problems. However, field personnelshould be aware that higher grades can be downgradedand sold as lower grades, i.e. up to 80,000 psi yieldstrength pipe can be downgraded to H-40. Thus gradesshould be positively identified before welding. Also, casingcollars and other downhole casing equipment are some-times manufactured of higher grade steel.Welding on high grade tubulars is critical, requiringcareful preheating and use of special electrodes P-IIO,

and C-75 should never be welded). Here are a few im-portant points to remember when welding oil field tubu-lars: 22 Use only low hydrogen electrodes. Always preheatN-80; preheating is preferable on J-55; H-40 can beWORLD OIL 1977


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welded without preheat. Preheating temperature shouldbe 500-600 F and it should not drop below 4000 F dur-ing welding. The weld should cool at ambient tempera-tures. A Tempilstik type crayon should be used to verifyand carefully control temperatures.Collapse support questionable A lowered casing de-sign safety factor in collapse perhaps 0.85 versus 1.125)is sometimes considered for casing to be used below thecement top, on the assumption that cement will provideadditional support.23 Such a practice is not valid.According to Cheatham and McEver/4 cement in theannulus between salt and casing is compressed by saltpressure, reducing stress transmitted to the casing. How-ever, this reduction is calculated to be less than 5 for8-5/8-inch casing cemented in 12-inch hole, or about 200psi for a pressure of 6,000 psi acting on the cement. Fur-ther, this load reduction depends on uniform placementof cement in the annulus-a condition which is not nor-mally achieved throughout the column.Other tests24 suggest that a cement sheath may provide

greater collapse resistance support for lower casing gradesH-40, J 55 . However, minor radial or longitudinaldiscontinuities in the cement sheath eliminate this support.Therefore, the cement sheath should have no bearingon the decision to use a low collapse safety factor.

PRECAUTIONS DURING DRILLINGFavorable conditions for primary cementing should be

established long before the actual cementing operation.It is particularly important to select hole and casing sizes,and drilling fluid properties, which maximize mud dis-placement efficiency and minimize likelihood for differ-ential pressure sticking and swab/surge pressures.Drilling fluids should be selected and drilling operationsconducted-so as to minimize borehole washouts. For

instance, the ideal drilling fluid:1. Is non-thixotropic little or no gel strength) with

low plastic viscosity and yield point, to maximize dis-placement efficiency and minimize swab-surge pressures.2. Has low weight with low solids content and lowfiltration loss with a thin cake to minimize likelihood

of differential pressure sticking, and3. Is compatible with cement composition.Such conditions cannot always be attained in actual

practice. For instance, in deep, hot wells it is difficultto maintain low gel strength, yield point and plasticviscosity-particularly with weighted muds. These con-ditions, combined with long trip time and casing runningtime, lead to mud properties that can be most unfavor3lbleby the time the job is initiated. However, when effectivecementing is important, and it is feasible to maintainlow density fluids, an effort should be made to achievethe conditions noted above. Other factors influencingfavorable mud displacement and swab/surge pressureswill be discussed in a later article.The differential pressure sticking concept 5 26.27 isvery important to understand, and this problem mustbe prevented if casing movement reciprocation and/orrotation) is planned during cementing operations. Other-wise the casing may become stuck after being run toWOR OIL 977

500

.@~ :E300Cl CL>a:a:.a;~ ;;1100~~ 90:E 8070604 5 5 12 6 6 12 7 7 12 8

DRILL COLLAR SIZE, INCHES9 10

Fig 8-Maximum safe rotary speed for drilling out cementand cementing equipment for all grades of casing strength-ened with thread-locking compound, and for H-40 gradecasing strengthened with a full-circumference weld (afterSchuh) . Note: If joints are not properly strengthened, safespeeds can be one-tenth those shown.

Fig 9-Differential sticking of casing occurs in a permeablezone when pipe contacts mud cake as shown, left, thenfiltrate loss causes cake thining, right, which increases con-tact area, (1) to (2), in turn increasing force holding pipeto wall (after Outmans) .bottom and before completion of cementing, and move-ment during that most critical period28 may not bepossible.Differential pressure exists across a mud cake, with

pressure on the inside consisting of mud column weightplus pressure increase due to annular flow. External pres-sure is the pore pressure of the surrounding permeableformation. This differential pressure causes water in themud to continuously flow through the filter cake into theformations.While the casing is in motion, contact with the filter

cake is lubricated by a thin layer of drilling mud, whichcontinues to supply filtrate. When pipe movement isinterrupted or stopped, the casing seals off the cakefrom the filtrate supply in the contact area and thecake begins to thin as water continues to be driven intothe surrounding permeability, see Fig. 9. As the cake thins,the contact area increases, the pipe is pressed againstthe wall with greater force, and the contacted surfacechanges from mud to sol clay particles.This pressure loading effect and the high friction

factor between pipe and cake solids can increase hookload until the casing cannot be moved.How to prevent sticking During cementing, differential

11


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A

B cFig. 10-Defects rolled into the pipe wall at the mill. PhotoA shows pits left by mill slugs that penetrate 0.210 inchinto a 0.337-inch wall. Photo B shows the hole left by abroken-out metal fold (lamination) that was rolled into the wallbut did not fuse. Photo C is another example of pitting causedby removal of foreign material rolled into the outer surface.

, * ;~,->c. *.ra;,.:~~~> ..

A

B cFig. 11-Longitudinal imperfections in new pipe. Photo Ashows part of an eight-foot long seam penetrati ng 0.110-inch in a 0.217-inch wall. Seam was detected by magneticparticle inspection; depth was measured by grinding asshown. Photo B shows internal grooving in seamless pipecaused by pieces of hard metal adhering to the plug. Theexternal longitudinal gouge in Photo C could be mill ortransit damage.

sticking tendency may also increase because of thedisturbance and reformation of filter cake caused bysome preflush fluids, change-over of fluids and/or me-chanical cake removal techniques.Things to remember regarding differential pressure

sticking are:. Sticking occurs opposite permeable formations, par-ticularly where pressure is depleted and/or high mud

overbalance pressure exists12

. Sticking generally occurs after an interruption ofpipe movement or long interruption of circulation, ordisturbances of wall cake. Circulation, if interrupted, can be restarted afterthe casing becomes stuck. This helps identify sticking,as opposed to wall caving, which would likely preventcirculation. A small clearance between casing and borehole isconducive to /Wall sticking because it tends to increasecasing/film cake contact area. This contact area can bereduced by using centralizers and/or designing the wellto have a larger borehole.. High deviation of the borehole also tends to increasecontact area, and. High weight, high water loss and high-solids-contentfluids can increase the friction factor between casing and

filter cake. Muds are available which provide cakes withlower coefficients of friction.29CASING FAILURE CAUSES

Obtaining an effective casing/cement installation re-quires proper inspection, care and handling, and make-upof the casing itself. Without such treatment, even prop-erly designed casing may fail. Texter30 and Casner,31and others, have identified a variety of potential casingfailures such mill defects, mishandling, borehole doglegsand corrosion. From such information, API has developedrecommended practices for the care and use of casing32and has defined the principal causes of trouble in other-wise properly designed casing strings, see below.Principal causes of failure in otherwiseproperly designed casing strings. Mishandling in mill, in transport and in the field. Poor running and pulling practices. Improper landing tension. Improper cutting of field-shop threads.. Poorly manufactured couplings for replacement. Leaking joints. Drill pipe wear. Wireline cutting from swabbing, etc., and. Corrosion.Principalcauses of connection failures. Under or over) tonging. Dirty threads, galled threads. Improper engagement cross-threading). Excessivemakingand breaking. Improper joint inake-up at mill. Casing ovality or out-of-roundness. Improper cutting of field-shopthreads. Wrong thread compound or mis-application. Over-tensioncasing, and. Dropping the string.A survey conducted by the API Southern DistrictTubular Goods Committee a number of years ag033 re-

vealed that over 80 of tubular string failures occurredin the connections. Common causes of connection leakageunder external or internal pressure as identified by API/2are also shown in the above table. Most of these causesfor leaking joints can be avoided through proper inspec-tion and make-up practices, many of which will be dis-cussed in the next article.

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Mill defects in casing. Imperfections may be found innew casing as delivered by a mill. Such imperfections,shown approximately in decreasing likelihood of occur-rence are as follows:Defects found in new casing. Seams. Laps. Eccentricity. Rolled-in-slugs. Pits

. Gouges. Plug scores. Weld area cracks. External, longitudinalcracks

. Upset, transversecracksCasing joints containing such imperfections may be

identified and segregated by non-destructive testing andinspection techniques. Examples of the above imperfec-tions are shown in accompanying photographs taken dur-ing field inspections, Figs. 10-13.

Although such imperfections may not actually lowera casing joint's burst, collapse or tensile strength belowacceptable limits because of size, orientations, etc., APIconservatively considers an imperfection to be a defectif it penetrates deeply enough so that less than 87~% ofspecified wall thickness remains.

However, if the imperfection can be removed by grind-ing and the remaining wall thickness is equal to or greaterthan 87%% of the specified wall thickness, the joint isconsidered to meet API specifications. Otherwise the por-tion containing the defect must be cut off. The remainingjoint continues to meet API specifications if it is withinone of the permitted API length ranges.

API specifies that high strength casing (P-llO) beinspected by non-destructive test methods at the mill.Imperfections that penetrate over 5% and less than12%% of the wall thickness must be removed by grinding.Coming next month: Casing inspection and handling,joint make-up, use of thread compounds, hydrostaticpressure testing and landing practices. .

LITERATURE CITED'Farrisl R. F. Method for Determining Minimum Waiting-on-CementTime,' Trans. AIME (1946), 165, pp. 175-168., Bearden, W. G. and Lane, R. D. Engineered Cementing Operationsto Elimmate WOC Time, API Dril ling and Production Pract ice (1961),l' 17., Evans, G. W. and Carter, L. G., Bonding Studies of CementingCompositions to Pipe and Formations, API Drilling and ProductionPractice (1962), p. 72. Becker, iI. and Peterson G., Bond of Cement CompositionsorCementing Wells, Proc..::,]..ixth World Petroleum Congress, Frankfurt,Germany, June 10-26, T~3. Bearden, W. G., Spurlock , J. W. and Howard, G. C., Control andPrevention of Inter-Zonal ~Iow, Journal of Petroleum Technology (May1965), pp. 579-584.Evansb G. and Carter, G., New Technique for Improving Cement Bond,API rilling and Production Practice (1964), PI'. 33-38.1Scott, J. B. and Brace R. L., Coated Casing-A Technique for ImprovedCement Bonding, APi DrillinK and Production Practice (1,966). PI'. 43-47.8 Ferd W. H., Pilkington P. E. and Scott, J. B., A Look at CementBond Logs, Journal of Petroleum Technology, June 1974, PI'. 607-61'7. Oliphant, S C. and Farris, R. F., A Study of Some Factors AffectingGun Perforat ing, Trans. AIME (1947), 170, PI' . 225-242.I. Morgan, B. E. and Dumbald, G. K;, A Modified Low-Strength Cement,Trans. AIME (1951'), 192, PI' . 165-1/0.11Godfrey, W. K., Effect of Jet Perforating on Bond Strength of Cement,Journal of Petroleum Technology (November 1968), PI'. 1301'-1314.12Ben, W. T. and Shore, J. B., CasinK Damage from Gun Perforators,API Dril ling and Production Pract ice (1964), PI' . 7-14.Godfrey, W. K. and Methven, N. E., Casing Damage Caused by JetPerforating, Paper SpE 3043, 45th Annual Fall Meeting, Houston, Oct.4-;, 1970.

.. Cheatham, Jr., . B. and McEver, J. W l Behavior of Casing Subjectedto Salt Loading,_' Trans. AIME (1%4), 231, 1'1'. 1069-1075.ISMcCauley, T. V. PlanninJI Workovers in Wells wit lt Fault-Damaged Cas-ing_-South Pass i 1ock 27 I ield, Journal of Petroleum Technology (July1974), p. 739.I. Roberts, D. L., Shear Prevention in the Wilmington Field, API Drillingand Production Practice (1953), p. 1' i6.

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A

';~

)B CFig. 12-Types of cracks occasionally found in new pipe.Photo A is a longitudinal, external crack detected by magneticparticle inspection. The example in Photo B illustrates a trans-verse crack on the pipe upset with a grind mark showingpenetration. The etched and enlarged sample in Photo C is awall cross section through an arc weld with a hook-crack thathas penetrated the pipe 00. This is caused by a layering inthe plate edge that turns toward the surface (10 or 00) duringwelding.

Fig. 13-Example of eccentricpipe that failed in collapsebecause one side was too thin.

11Suman, G. O. Jr., World Oil's Sand Control Handbook, Gulf PublishingCo. (1975).18Suman, G. O. Jr. \. . CasinR Buckling in ProducinJt Intervals, PetroleumEngineer, (April 19/4), p. 36... Schuh, F. J., Failures in The Bottom Joints of Surface and IntermediateCasing Strings, Journal of Petroleum Technol0y,y, January 1968, PI'. 93-1\)1.'0 Owsley, W. D., Improved Casing Cementing, , The Oil and Gas Journal,Dec. 15, 1949.

Dellinger, T. B. and McLean, J. C., Preventing Instability in Partially-Cementea Intermediate Casing Strings, SPE Paper 46066 ,resented at 48thAnnual Fall MeetinJI SPE of AIME, Las Vegas, Sep. 3 -Oct. 3, 1973. Dalrymple, D. H. Personal Communication. Calvey, H. J., Casing Designs and Programs Considered in the AnadarkoBasin, Paper SPE 3909, 1972 Deep Drill ing Symposium, Amarillo, Sept.11-12, 1972.Evans, G. W, and Harriman D. W., Laboratory Tests on Collapse Re-sistance of Cemented Casing,' SPE Paper 4088, 47th Annual Fall Meeting,San Antonio, Oct . 8-11, 1972.soHelmick, W. E. and Longley, A. J., Pressure Differential Sticking ofDrill Pipe and How It Can Be Avoided or Relieved, API Drilling andProduc/lon Practice (1957), PI' . 55-61.26Outmans, H. D., lVlcchanics of Differential Pressure Sticking of DrillCollars, Trans. AIME (1'958), 213, PI'. 265-274.Outmans, H. D., Spot Fluid QUIckly to Free Differentially Stuck Pipe,The Oil and Gas Journal, July 15, 1974, PI'. 65-68., . Barkis, B., Primary Cementing, the Critical Period. B&W Publicat ion.29Annis, lvl. R. and Mona~han, P. H., Differential Pressure Sticking-Laboratory Studies of Friction Between Steel and Mud Filter Cake, Journalof Petroleum Technology, May 1962, PI'. 537-543.30'texter, H. G., Oil-Well Casing and Tubing Troubles, API Driling andProduction Practice (1955), p. 7. Casner, J. A., Care and lIandin/( of High-Stren/(th Tuhular Goods, APIDrilling and Production Practice (1196'r) PI'. 169-1'76.::2API Recommended Practice for Care and U c of Casing and Tubing, APIRP 5Cl, Tenth Edition, March 1975.Oxford, W. F., API Southern District Tubular Goods Committee Summaryof Inspection for Period Jan. 1, 11963to Jan. I, 1964, Houston, March1966.

13


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Cementing oil and gas wellsPart 2 Casing inspection and pipehandling methods including threadmake up control hydrostatic testinglanding practicesGeorge o. Suman, Jr., President,and Richard C. Ellis,Project Engineer, Completion Technology Co., Houston15-second summaryHow electronic inspection at the mill, pipe yard or rigsite finds serious metallurgical defects. Pipe handling dis-cussion tells why torque cOlitrol alone is inadequate forthread make-up. Axial load in slips is explained as arehydrostatic rig floor tests for connection leaks andlanding practices to correct for future load changes.HIGHER EQUIPMENT and service costs and the trend

towards completion of iWells in deeper, more severeenvironments emphasize the need for strict attention tocasing quality control and handling before cementing. Inone study, over 5 of 33,000 casing joints inspected didnot meet API specifications because they contained de-fects. In another example, rig floor testing revealed 1.4of the joints tested leaked.This article tells what can be done to prevent the run-ning of defective casing, including:i~ Casing -inspection methods: Need for, and results of,

field casing inspection, and techniques and principles ofnon-destructive inspection in the pipe yard, rig site or milli~ Pipe handling: Recommended procedures for trans-porting and running casing; rig floor practices to avoid

slip and tong damage~ Casing make-up: Functions of threads and thread

compounds in sealing-off fluids; factors affecting torquerecommendations, and systems to control make-up .foroptimum connection performance, and~ Rig floor connection testing: Internal and external

hydrostatic tests for leakage; how thread configurationaffects test application; casing landing practices.Many casing problems are directly related to casing

condition existing prior to cementing/a, 32,34,35 usually asa result of: Metallurgical flaws, damage in transit or onlocation; improper connection make-up, or poor runningpractices.

CASING INSPECTIONCasing inspection can mean anything from visual rigcrew checks of pipe body and threads while running, to

extensive non-destructive inspection NDI) of each joint,including threads and couplings.

14

Fig. 14-Magnetic particle inspection defines mill imperfectionsthat are otherwise not visible. Before-and-after photo of 5V2inch, N-aocasing segment, shows how seam in the metal wasdetected by inspection.

LONGITUDINAL IMPERFECTION SEARCH COIL TRANSDUCER

~G 1 [lIQAGNETIC SOURCE PIPEFig. 15-Schematic of transverse electromagnetic-diverted-flux,search coil EDFSC.)system illustrates how flux diversion de-tects seams, etc. oriented along pipe axis.Seams, rolled-in-slugs and eccentricity are some imper-fections that are not visible without aid of some type of

NDI; an example is shown in the with-and-without mag-netic particle inspection of the same section of pipe,Fig. 14. Obviously in this example, visual inspection alonewould not be adequate.The cost for NDI of pipe body and end areas varieswith location and other factors. But, generally, cost for

complete inspection of casing is less than 10 of totalcasing cost, as shown in the table on following page.

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Inspection costs vs. casing costs

ee for inspection. Pipe manufacturers have exten-sive quality control procedures, and API specificationscall for nearly 30 separate tests during the manufactureof casing.36.37.38 Most manufacturers utilize in-line NDIequipment. And such inspections are required for P-1IOgrade casing.However, a study of an independent service company's

casing inspection statistics, compiled over a 12-monthperiod in 1975/1976, shows that 1,861 joints of a total33,562 inspected (5.54%) failed to meet API specifica-tions, see table below:

Note: API defines a efe t as any imperfection thateffectively reduces the wall thickness of any grade pipeto less than 871'2% of the spe ifie wall thickness.36 Inlower casing grades, no action is required for imperfec-tions that do not classify as defects; however, in high-strength casing (such as P-11 0) an imperfe tion pene-trating 5% or more of the specified wall thickness mustbe removed by grinding. Only such imperfections areincluded in the table,38

Over 80% of the problems included in the a:bove studyoriginated in the mill; the remainder was handling dam-age. Casing of all grades was included in the study. How-ever, grades were mostly N-80 or higher, as shown helow:Number of defects by casing grade

Anadditional821 imperfections were notedfor this grade.Industry efforts. It is estimated that only 15-20% ofoil field casing and tubing is currently inspected by inde-

Thlnwall,eccentric33171041261

182

New casing inspection results*Location,ype of Imperfectlon**

Casing No.lengths External InternalSize Inspected bodywall bodywall Connection Drift,othert4 h 934 116 25 4,629 287 52 266 45 h 8,369 354 25 109 4t7 6,874 271 26 94 22t7% 2,772 124 4 64 12t9% 7,147 305 20 220 25t10% 1,416 36 4 2211% 7513% 1,109 2 1 22 116 114 .... 1 220 123 2 .... 1Total 33,562 1,497 132 801 70

Typical Inspection Percent of casingcosts per length, * cost, f.o.b. pipe mill**Ca.sing TotalSize, Body- End costIn. wall area per foot* K-55 N-80 p-no13% 19.00 5.50 0.612 4.23 2.489% 14.70 4.95 0.491 5.06 3.68 2.597 13.90 4.70 0.465 7.41 4.37 3.605 h 12.45 4.40 0.421 9.60 5.32 4.39* Range3 casing,approx.0 lengths.**Typical casing costs, Jan. 1977.

No. Endafea,lengths Total Body othefGrade Inspected defects defects defectK-55&H-40.................... 2,536 82 41 41Percent. . . . . . . . . . . . . . . . 100.0 3.2 1.6 1.6C-75, N-BO,S-95.. . . . . . . . . :::::: 24,001 1,377 719 658Percent.. .. . . . . . . . . . . . . . . . . . . . . . 100.0 5.7 3.0 2.7P-llO, other. . . . . . . . . . . . . . . . . . . . 7,025 402 293 109Percent........................ . 100.0 5.7 4.2 1.6Total.. .. .. .. .. .. .. .. .. .. .. .... 33,562 1,861 1,053 808Percent........................ . 100.0 5.5 3.1 2.4

TotalTotal defectiveImperfect lengths118 40642 467509 373517 259205 152596 47963 5926 263 33 3

2,682 1,861Descriptionof bodywall,connectionImperfections

Casing Seam Lap Roll-Inslug Pit Gouge Crack,cut Plntt CoupllngttSize Ext Int Ext Int Ext Int Ext Int Ext Int Ext Int Mfg Hdg Mfg Hdg4 h 71 11 1 23 3 32 1 25 3 117 41 24 31 2 11 12 5 7 4 251 45 h 86 10 156 4 43 6 51 6 24 3 14 23 41 37 87 64 99 4 46 1 6 6 3 5 12 1 57 18 1870/8 78 1 21 2 14 1 10 5 2 3 6 23 34 190/8 162 3 60 2 53 9 1 10 1 10 55 94 49 2210% 14 2 20 1 2 9 1311%130/8 1 1 1 17 516 .. .. 120 2 .. 1Total 575 17 466 53 204 18 121 17 85 8 46 19 101 251 396 53* Source:AMFTuboscop,ereports to several operators on newcasinginspectionin various yard andfield locations,1975/1976.** SeeAPI definitionof 'imperfection and defect intext.t Includes1-3 lengths ofwronggrade or wrongweiht.tt Analysisof connectiondamageby manufactureror 10handling.

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pendent service companies utilizing NDI techniques.One possible reason that manufacturers' NDI does notdiscover all problems is that sensitivity of plant equipmentis adjusted to detect defects, as defined by API, that pene-trate 12~ or more of the specified wall thickness on ago, no-go basis, whereas, an independent inspectioncompany usually adjusts equipment to a higher level ofsensitivity, then relies on detailed examination of the im-perfection to determine if it is .within API specifica-tions.36, 38Non-destructive inspection techniques. The semi-automatic non-destructive inspection units that manyinspection companies have developed feature: Two elec-tromagnetic-diverted-flux, search coil (EDFSC) testingsystems; a radiation wall thickness measuring device; andan electronic metal comparitor. These systems are usedto detect imperfections in the pipe body as the pipe movesthrough the NDI unit at a constant speed.Units are available that can handle tubulars of 1.315to 14-inch aD. Various units have inspection or scan-ning speeds that vary from less than 30 seconds to over 60seconds, per Range 3 length. Most units are portable andcan be used at the well site, pipe yard or mill.Principles of EDFSC systems are illustrated in Figs. 15and 16. A magnetic flux field is induced into the wall ofthe pipe. This field flows in one direction and divertsaround imperfections. Flux diversion or leakage occursthrough air near the pipe surface.

Search coils, cut through these diverted flux fields andgenerate electrical impulse. The recorded magnitude andpattern of these impulses indicate imperfections.

A large number of variables affect EDFSC sensitivity,i.e. shape and orientation of an imperfection; magneticflux field energy level; shape and orientation of the searchcoil with respect to the imperfection and direction ofdiverted flux field. Specific combinations of the controlla-ble variables are proprietary information of inspectioncompanies.Wall thickness of 0.75-inch or more reduces EDFSCsensitivity to intern l body wall defects. In critical appli-cations where thick-wall casing is used, additional inspec-tion with internal magnetic particle techniques, or otherspecial methods, may be required.Radiation wall thickness measuring is an efficientmethod for inspecting oil field tubulars for general (notlocalized) wall thickness variations like eccentricity withina joint, or change of weight betiween different joints ofthe same grade. This system is not used to detect cracks,pits or other surface imperfections. The radiation sourceand detection equipment does not come in contact withthe pipe being inspected.

There are three common arrangements of source anddetector for gamma-ray thickness gaging, Fig. 17.40Thesesystems are sensitive to distance between pipe wall andsource, between source and detector, and between detectorand pipe /Wall. Precise alignment must be maintained toavoid inaccurate readings.

Pipe movement vs. rotational speed of the gamma-.rayunit affects the percentage of pipe actually scanned, asthe path of investigation is a helical trace around thecircumference, like the stripe on a barber's pole. Rota-

16

SEARCH COIL TRANSDUCERELECTRIC COIL ~, _\I ..

-:':-

~LONGITUDINALMAGNETIC FIELD

TRANSVERSEIMPERFECTION

Fig. 16-Schematic of longitudinal EDFSC system used todetect transverse imperfections.

ROTATION GAMMA SOURCEOETECTOR / SHIELD

SHIELDRADIATION BEAMSINGLE-WALLBACKSCATTER THROUGHSINGLE-WALLTHROUGHDOUBLE-WALL

Fig. 17-Radiation wall thickness measurement uses a highlyfocused beam to irradiate the casing wall as system rotatesaround pipe. Drawings indicate three common arrangementsof source and detector after Kahil). .

tional speed of the single-wall system can be faster thanbackscatter or double~wall systems. However, all threesystems can detect general wall thickness variation.Electronic metal comparitors electronically comparethe grade of pipe being inspected with a grade standard.This system induces eddy current into the pipe which isadjusted until balance is achieved with the standard. Thenas the pipe is inspected, variation in the balance is anindication of metallurgical change. The technique is verysensitive and even different heats of pipe of the samegrade can be detected.

This comparison is a quick and easy, positive identifica-tion of grade change. However, it is only qu lit tive Itdoes not define either magnitude of metallurgical changeor direction of change, i.e. increase or decrease in grade.

This system is most commonly used for inspection inthe yard and at the rig, where mixing of grades may haveoccurred, or for inspection of used tubulars.End area magnetic particle inspection is a procedureseparate from those performed by the NDI unit.This method is based on the same diverted magneticflux principles of the EDFSC system, except that dry ironpowder that is sprayed onto the surface is magneticallyattracted to flux leakage occurring at imperfection. Theseparticle accumulations are visually located.

The end area being inspected must be cleaned with asolvent, to a dry surface, to prevent powder accumula-tions on moisture, grease, thread compounds, etc. Priorto inspection, threads should be visually examined fortears, cuts, shoulders or other imperfections breaking thecontour of the threads; these are also defects.41 And, while

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it is not always essential, sand blasting will improve mag-netic particle inspection sensitivity.How to find imperfection depth Further examina-tion of imperfections is required to determine if they are-in fact-a defect, as defined earlier.

When NDI units indicate presence of an imperfection,magnetic particle inspection, as was described, is fre-quently required, to locate the imperfection in the pipebody.

Once located, imperfections on the pipe's outer diame-ter are measured by grinding to the base of the imperfec-tion. If 87Y of the specified wall thickness remains, inany grade, the pipe complies with APJ.36 However, withhigh strength (P-IlO) casing, any imperfection ,that pene-trates 5% or more of the wall thickness must be removedby grinding.38 The ultrasonic wall thickness spot checkdevice is usually used to determine remaining wall thick-ness.

Unfortunately, there is no commonly used, non-destruc-tive method to thoroughly examine imperfections on theinternal diameter surface. Although this is a disadvantage,it is not a significant problem as most surface metallurgyimperfections in ne.w casing occur on the outer diameteras a consequence of the manufacturing process. Forexample, less than 5% of the defects in the major studypreviously discussed are internal. .Ultrasonic wall thickness instruments use a compres-sion-wave source and a detector to spot check wall thick-ness. These instruments can be accurate to + O.005-inchwhen the sonde is properly coupled to the pipe.

In application, a liquid couplant-like water, oil orantifreeze that contain no gas, solids or fibrous materials-is applied to the clean pipe surface and the ultrasonicsonde is pressed firmly against the moistened pipe.Length diameter hardness Mechanical measure-ments are made to verify that joint lengths meet industryspecifications and/or will be satisfaotory for a specificapplication. And occasionally when a larger than stan-dard drift diameter is desired, special drift mandrels areused to cull the pipe stock. This and other special inspec-tions requested by an operator should be performed inthe pipe yard or mill to avoid transporting a large numberof unusable lengths.

Hardness testing is commonly used to verify a restrictedrange of yield strength for casing that is to be used in sour(H2S) environments (except C-75 grade casing which hasbeen manufactured for this application). 39 Such tests canhe conducted anywhere. However, consistently accuratedata are difficult to obtain in less than lab type environ-ments. Accuracy will depend on surface preparation,clamping systems, etc.

Significant industry effort Was expended to developC-75 grade materials for severe sour gas environments.Methods for specifying and inspecting these types of ma-terials are available in the literature.42Identification bands Pipe thaJt has been inspected isusually identified by stenciled information and color codedbands, above right. The stencil usually states who didwhat type of inspection and when. While this is not anofficial code, it represents common practices used by mostinspection companies.WOR OIL 1977

Recommended inspected tubulargoods identificationIndicatesMeets API specsImperfections not repaired as perAPI Std 5AXImperfections repaired asper API std 5AXID imperfections, depths cannotbe measured accuratelyID or OD defects that failAPI acceptance specsDefective box or pin

Red Near boxRed Aroundcoupling,adjacent tothreads

Nearcouplingor box endLength fails to passAPI drift mandrelOrange,zig-zagpattern

Where to inspect pipe The most common locationsfor non-destructive casing inspection are pipe yards andwell sites. Occasionally independent company inspection isconducted at the pipe mill. Inspection close to the pipesource cuts the cost of transporting defective pipe. How-ever, well site inspection minimizes the running of casingthat was damaged after yard or mill inspection. Thus,choice of location 'should be based on operator control ofpipe prior to well site delivery.

Lack of space at the Well site may preclude use ofNDI. However, some type of inspection is required atevery well, if it is only cleaning and visual inspection bythe rig or casing crew and application of compound to pinand coupling threads prior to running. In any case,Planning for well site equipment and pipe rack arrange-ments should include the well site inspection program.

When NDI units are to be u'sed at the site, the piperack arrangement and casing location should he compat-ible with the inspection program and NDI unit capability.Some units have single pass capability while others requirepipe to pass through the unit in both directions. An extrapipe rack may simplify the job. Also, it is extremely diffi-cult to do a good inspection job on casing ends thatoverhang the mud pit. Preliminary planning greatly re-duces time required for well 'site inspection.Inspection equipment must be maintained in excellentoperating condition to provide consistently accurate re-sults, and people operating the units have to be competent.The operator should demand optimum performance. Atleast two of the larger service companies provide technicalseminars for operating company personnel.

CASING HANDLINGDuring the past 40 years, recommendations for proper

care and use of casing have been defined and encouragedby APJ.32 But casing is still subjected to damaging han-dling practices in many locations.

Some of the more important handling practices areshown in the following table. More complete handlingprocedures are documented in the literature.31. 3 43Recommended casing handling practices. Move casing only when thread protectors are in place

Type paintband LocationWhite Near boxYellow Near boxYellow and Near boxwhiteBlue Near box


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. Store or rack casing only on wooden or metal surfaces freeof rocks, sand or other debris

. Use spreader-bar and choker-chain arrangement near eachend to prevent crushing when handling bundles of casingjoints with a crane

. Do not unload pipe by dropping. When unloading by hand,use a rope sling to control pipe momentum and prevent pipe-banging after rolling down the skids. Even with protectors inplace, pipe threads can be damaged

. Avoidall rough handling.Running casing Design details identifying variousweights and grades for each section of the string shouldbe available. If weight and grade of a joint cannot beclearly identified, it should be set aside until positiveidentification can be made.

Casing ID can readily be checked (drifted) as it ispulled into the derrick, by dropping a drift mandrelthrough the joint. Drifting at this time removes any debristhat could interfere with cementing equipment. It alsoprevents the running of a joint with a restrictive ID.

For short, lightweight, casing strings where collar-pullelevators are used, the bearing surface should be inspectedto be sure that the load will be uniformly distributed.Side load on a collar could j ump the collar off.

Slip-type elevators and spiders are recommended forlong casing strings. It is critical that the casing be grippedso that no permanent deformation results from the grip-ping forces.Axial loads in slips Where casing is gripped by wedgesor tapered elements with slip-type equipment, as inFig. 18,44axial load (F) due to casing lWeight tightens thegripping elements with radial force (W) due to wedgingaction of slips in the tapered bore.Critical axial load (Fe) for slip-type equipment, wherepermanent deformation of the casing occurs, is deter-mined as follows: 45Fe (lbs.) = C X A X TWhere

T = yield strength of the casing, psiA = Cross sectional area of the pipe body, in2[ rK (rK ) 2J 1/2C =Crushing factor = 1/ 1+ L + LAnd: r= Outside casing radius, in.L = Slipgripping length, in.

K =Transverse load factor = 2.636, based on ac-cepted API slip bowl taper of 2 inches per footand minimum coefficient of friction (0.2) forlubricated hardened steel against hardenedsteel at the slip-bowl interface.

For a given size, weight and grade of casing, slip length(L) is the primary variable controlling critical load.Example calculation: For 9 -inch, 47 pound/foot,N-80 casing, using 14-inch slips:A = 13.57 in2C = 0.606T = 80,000psi, andFe= 0.606X 13.57X 80,000= 657,000pounds.

Slips used for heavy casing 'Strings should be checked 8

SLIPS

SLIP BOWLANGLE a

RADIALFORCE W)

.AXIAL LOAD F)

Fig 18-Slip configuration and symbols used in calculatingcritical axial load where radial force starts to deform thecasing.for adequate length and bearing area to minimizedamage.Radial force (W) is related to axial load (F) by slipgeometry and the coefficient of friction p. between slipand bowl. This relationship is

I-p.tan.aX FW (lbs.) = p.+ tanaWhere: a = Slip bowl taper angle, Fig. 7po= 0.2 (usually)Slip marks damage the integrity of high strength orsour service casing. To minimize this damage, slips shouldbe clean, in good repair and they should be selected tofit casing OD closely. In rare instances where odd-sizecasing is required, special slips should be provided. Slipsshould all lower together and seat properly in the slipbushing or bowl. Slip marks should be examined periodi-cally for uniform impressions.

CASINGMAKE UP TORQUEThe thread protectors should not be removed until

joint is ready to be stabbed into the box end of the pre-ceding joint. The joint then should be lowered carefullyto avoid thread damage. Vertical alignment should bemaintained and the casing should be rotated very slowlyat first to assure thread alignment.Tong dies should be examined for wear prior to runningcasing. The back-up line should be positioned on theback-up post so tong gripping surfaces exert an even loadand minimum bending force on the casing.

The back-up line must be lined up at a 90-degree angleto the power tongs to obtain an accurate indication froma torque gage that measures tension in the back-up line.The torque gage should be reliable and in calibration sothat irregularities in torque required for casing make-upcan be observed.The development of power tongs in the 1940s providedthe means for improving make-up practices as well asreducing rig time required to run casing. However, the

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VANISHING POINT MAKE-UP :tTW~,,~~RE~D TURNS OK IPOWERTIGHT BEARING PRESSURE

MAKEUP API ROUND THREADHANDTlGHT

MAKE-UP,

HANDTIGHTBUTTRESS THREAD

Fig. 19-Thread configuration and basic make-up positions ofAPI 8 round and Buttress threads (after API Spec 5A).practice of using torque lone as the means for make-upcontrol was never intended by API.The two most important factors that influence leakresistance of threaded pipe joints were identified, over 30years ago, as joint make-up and thread compound.43The basic sealing principle for API 8 round threadedconnections, Fig. 19,46 is that contact (bearing) pressurebetween pin and box, produced by make-up, forms sev-eral metal-to-metal seals, and that solids from threadcompound fiU the void space between the threads. Thesesolids are required to transmit bearing pressure from onethreaded surface to the other. The connection seal ismaintained only as long as bearing pressure is greaterthan the internal or external differential pressure.Sealing ability-as well 8.'Sthe influence on friction-ofdifferent thread compounds varies greatly. Pressure testshave shown that marked variation in sealing ability existsbetween different brands of API Modified thread com-pounds as well as with specialty compounds.46Non-API connections. Several different types of non-API tubular connections are commonly U'sed. Descriptionsof these have been reported in the literature,48 and latestdata on premium thread designs are available from manu-facturers or COMPOSITECATALOG.

Such connections employ several different basic typesof thread designs. They can have both shouldering andnon-shouldering connections with metal-to-metal seals,while other connections rely on a 'Supplementary, resilientTeflon seal.

Obtaining a pressure seal in connections that rely onmetal-to-metal sealing requires make-up, to force the pinand box mating surfaces together.Theoretically, the pin should be stressed to about the

yield point to obtain maximum leak resistance. This keepsthe connection in the ela:stic stress range and produces themaximum amount of bearing pressure between matingsurfaces for leak resistance.49.5o A precise make-up pro-cedure is required to achieve these maximum leak resis-tance conditions.API torque recommendations. Although it was neverintended, development of power tongs made it very con-venient to use torque as the only guide for make-upcontrol. However, variations in thread design, surfacefinish, thread compounds and the size, weight and gradeof pipe all interact and influence make-up torque.WOR OIL 1977

The API round thread pullout strength formula wasthought to contain several variables that affect make-uptorque. 51 And when API conducted tests that measuredtorque required to make up API 8 round threaded con-nections lubricated with API Modified thread compound,it was found-emperically-that these torque values wereabout 1 of the calculated pullout strength.

Therefore, the recommended torque values listed inAPI RP 5CI are calculated from the following relation:

Torque (ft. lbs.) = 0.01 Minimum joint strength (lbs.).API RP 5C1 further states that torque W8.'Sselected togive optimum make-up of API 8 round connections undernormal conditions and should be considered satisfactoryonly if the face of the coupling is within plus or minustwo thread turns of the last thread scratch (vanishingpoint), Fig. 19.

When using API RP 5C1 recommended make-up torquetables, use API Modified thread compound and observethe m ke up position of each connection.For Buttress threads, API recommends:1.Determine torque required to make-up each of sev-

eral connections to the proper position, then2. Use that torque to make-up the balance of the same

weight and grade pipe in the string, but3. Continually observe make-up position for verificationof proper make-up.Buttress thread connections have triangles stamped on

the pin ends. Proper make-up is achieved when the cou-pling face is opposite any portion of the triangle, Fig. 19.Effect of thread compounds. Torque required to prop-erly make-up connections depends primarily on frictionbetween pin and box threads. For clean, damage-freethreads, make-up torque is significantly affected by typeof thread compound. Use of different compounds cancause make-up torque variations of up to 500 .52Such large variations indicate that, to establish maxi-mum bearing pressure between pin and box mating sur-faces-and not risk overstressing pin or box-a more accu-rate means of measuring make-up (than torque alone) isrequired. Two methods for making such measurementswill be discussed.

An API subcommittee is currently reviewing threadcompound standards, attempting to develop more precisestandards for friction and leak resistance performance.Careful selection of compounds for each set of condi-tions, on the basis of friction and leak resistance charac-teristics, is encouraged. These characteristics should beclarified by discussions wi th both pipe and Iub r i can tmanufacturers.Make-up control Torque-Turn . During 1963, theAPI Southern District Tubular Goods Committee con-ducted a survey of tubular string failures.33 This survey(still the only comprehensive study published) showedthat 86 of reported casing failures occurred in connec-tions.

In 1967, Exxon began licensing its newly developedTorque-Turn make-up control device, 47.49.52 an auto-mated make-up monitoring system for API type connec-tions that cross-checks torque with turns (make-up posi-tion) to determine connection acceptability.Make-up control with this system involves pre-setting


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of reference minimum and m ximum torque, and lowminimum and high turns.These torque and turns settings vary with size, weight

and grade of casing, thread compound and type of con-nection. Specific setting are considered proprietary in-formation of various licensees.

The system can accommodate single-end or double-endconnection make-up. Double-end make-up is used whenthe mill provides collars separately or hand-tight (float-ing) which need to be made-up on the rig floor. Thesystem is available in most U.S. steel mills for installingcollars, if specified. Where the system is to be used on therig floor, collars made-up in the mill should utilize thesame control so that the first-half of the connection isnot disturbed.A new make-up control system recently developedby AMF Tuboscope provides a method to evaluate thecondition of pin and box threads before casing is runinto the well, and measure connection make-up. 53

To apply AMF's Torque at Proper Engagement(TAPE) control system, protectors are removed andthreads are cleaned. Then, API ring and plug gagesare run on both threads to the hand-tight plane usinga power driven tool with controlled torque, Fig. 20. Thelocation of the gage on the threads is checked per APIStandard 5B.

Torque reference marks are inscribed around pipecircumference and coupling if the relative position of thehand tight plane agrees with API. Thread compoundis applied and cle ned thread protectors are replaced.When casing is run, each connection is made up to aspecified torque load and the distance between pipe andcoupling reference marks is checked with a special gagecard on which the mark shows in an acceptancewindow when proper make-up position is achieved, Fig.20.

Torque is recorded on a chart and used to verifyproper thread engagement and make-up. This newdevelopment will be available initially in California.

RIG FLOOR LEAK TESTSHydrostatic testing of casing connections on the rig

floor is a technique used to prove leak resistance of con-nections. Tools are currently available that provide forinternal testing of up to 8 -inch casing, and externaltesting of up to 16-inch casing.Hydrostatic tests have been proven capable of detect-ing (on the surface) connections that will leak underpressure. Such a detectable leak could easily result in acasing leak downhole.

There are advantages and disadvantages of both in-ternal and external testing, for example: The small fluidvolume used in external testing increases sensitivity andshortens test time; however, visual inspection of a leakingconnection is not possible with external testing. Also, theinternal system can test the entire joint.Connection geometry has a significant effect onwhether a connection is more subject to leaking due tohigh internal or high external pressures. To preventleakage, connection bearing pressure must exceed pressuredifferential from either direction. But the same pressuredifferential, in turn, has an energizing effect on thebearing pressure that can alter the true leak resistance ofthe connection. And this effect varies greatly with direc-20

Fig. 2D-New make-up control system uses controlled-powerunit, left, to run ring and plug gages to hand-tight positionsto check pin and box thread quality. Reference marks, right,then are applied to pin and box, and make-up position isverified on the rig floor using calibrated window in specialcard, right (courtesy AMFTuboscope).

P,

t.uia:::>enenwa:Q.

IIrIIIIIIIIIeI) _____: II ;'~ _.,,.. ,-,.- ,I B(BEARING PRESS.: AT SEAL POINT) . T (PIN)II P(INTERNAL)

P (EXTERNAL) CASING OD.. -c'

Fig. 21-Energizing effect of pressure applied across a con-nection. On the curve representing the thin-pin, thick-boxconnection in the drawing, B, is initial bearing pressure frommake-up in the metal-metal inner seal, PE and p, are theoreti-cal external or internal pressures required to initiate a leak atthe seal, and e is a function of connection geometry. Whenthicknesses are nearly equal, as in API connections, e ap-proaches zero and the energizing effect of pressure in eitherdirection is not significant.

tion of the differential pressure and connection geometry,Fig. 21.External testing, for example, can be more effective indetecting leaks in premium type connections that have

a metal-to-metal seal surface at or near the tip of the pin.Insufficient make-up position-wise due to damaged ordefective threads or seal surfaces can result in lowinitial bearing pressure even with pp rently dequ tetorque. In such connections, the metal is much thinnerin the pin than in the collar, at the sealing point. There-fore, higher internal pressure energizes the otherwiseinsufficient seal by expanding the pin into the box, in-creasing bearing pressure. Conversely, increase in externalpressure has very little energizing effect on the seal, Fig.21. In this thin-pin, thick-collar situation, a lower ex-ternal pressure would detect the problem.

Test procedures. For API, non-premium connections,in which pin and collar thickness difference is less sig-nificant, test procedures used may be of more importancethan the test method internal or external.The length of time that test pressure is held on theWORLD OIL 1977


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connection varies widely in practice, as do opinions onthe subject. Many leaks have not been detected in less.than 10 seconds, and many testers recommend that 10seconds be the absolute minimum even in low pressurese.vvice. For pressures over 2,000 psi, 20-30 seconds (ormore) would give. more reliable results.

Leakage depends on time because of the tortuous pathfluids may follow through voids between threads and/orbecause of the slow displacement of viscous but non-sealing thread compound.

Use of a strip chart pressure recorder is a simple wayto obtain a permanent record of connection testing. Itallows development of more dependable test durationstatistics. And the strip chart can be retained as a perma-nent record of test time and leaks found.

Recommended test pressure also varies with applica-tion and with operator. Most testing companies recom-mend that test pressure be 80 of pipe yield pressure.And-attempting to duplicate downhole conditions-some testers recommend that pressure be applied andreleased at least once before performing the test, andthat all testing be conducted with the connection intension.

Since there are no industry standards for hydro-statically testing casing connections on the rig floor, and'because practices vary widely,55 it is recommended thatequipment and procedures be carefully examined beforeeaoh job. CASING LANDING

Casing landing practices should be specifically definedfor each well to minimize chances of buckling or partingduring future ope.ra:tions. Practices effectively used in onefield may not be appropriate for another.

Three variations are usually implemented:1. Normally, casing is landed in the wellhead in theposition in which it was cemented, i.e. as cemented2. It can be stretched to increase tension, or3. It can be slacked off to reduce tension.Which procedure is used and to what degree slack-off

or tension is added is a function of anticipated changesin wellhead loading that will occur during the life of thewell.Wellhead loading is affected by: Changes in tempera-ture and pressure; internal and external fluid weightvariations; and location of the permanent (and tem-porary, if any exists) freeze point (free point). Equations,useful nomographs and analytical procedures in the litera-ture can be used to determine appropriate landingprocedures. 56. 51

'two methods that can be used to adjust wellheadloading offshore where ocean bottom suspension pre-cludes use of conventional onshore landing practices are:Increase height of the primary cement column; and/orhold an internal pressure on the casing until cementsets.58

Increasing height of cement is usually more economicalas it requires less rig time. However, certain problemformations or lost circulation zones may not toleratehigh cement columns.

Holding internal pressure normally results in a net

WORLD OIL 9

lengthening of casing as the piston effect causes morelengthening than the shortening effect of swelling (bal-looning). This stretch is cemented in when the cementsets. However, swelling that increases casing diameterslightly may create a micro-annulus between cement andcasing when pressure is released after cement has set.

Because of an increasing awareness of bonding andmicro-annulus problems, operators in certain geographicalareas are reluctant to hold pressure on casing greaterthan the differential required to support the densercement column in the annulus.

In any case, it is necessary to anticipate changes indownhole conditions that may occur during well life todetermine correct adjustments or landing procedure.Severe conditions such as arctic (permafrost), ultra deep,thermal or geothermal environments, of course, requireeven more careful evaluation and perhaps specializedlanding practices.Coming next month: Cement slurry composition, classi-fications, types and availability of additives, applica-tions in common downhole problems, special cementsfor special purposes.

LITERATURE CITED.. Kettenbur~, R. } . and Schmieder, F. R., Oil-well Casing Failures,API Drilling an Production Practices 1945, p. 195.Davis, S. H. and Nippert, H. W., Why High-Strength Tubular GoodsFail Oil & Gas Journal April 13, 1964, p. 84.3. API Specification for Casing Tubing and Drill Pipe, API Spec SA,.Thirty-third Edit ion, March 1976.31 API Specification for Restricted Yield Strength Casing and Tubing,

API Spec 5AC, Tenth Edition, March 1976.38 API Specifications for High-Strength Casing, Tubing and Drill Pipe,API Spec SAX, Tenth Edition, March 1976.3. Hamby, T. W., Jr., Broussard, L. P. and Taylor D. B., ProducingMississippi's Deep High-Pressure Sour Gas, JPT June 1976, p. 629.40Kahil, K. l?~ 'Automatic Nondestructive Testing of Oil Field TubularGoods, ASME Paper 7S-Pet.42, presented at the Petroleum MechanicalEngineers Conference, Tulsa, Okla. , Sept. 21-2S, 1975.41 API Specifications for Threading, Gaging and Thread Inspection ofCasing, Tubing and Line Pipe ,Thread, API Standard 5B, Ninth Edition,March 1974.'2 Swanson, T. M., Experience With High Strength Steel Oil Field TubularGoods in Sour Service presented at the Srmposium on Line Pipe andTubular Goods, API 1976 Stand. Conf., Dallas, Texas June 1~-18, 1976p. SS-4:3.'3 Kemler, E. N. Factors Influencing the Leakage Resistance of ThreadedPipe Joints, API Drilling and Production Practice 1946, p. 275... Develol'ment of Casin , Handling Equipment for Ultra-Deep Gas andOil Wells, report ava.lable from Varco Oil Well Tools, Box 6626,Orange Calif ... Spiri, W. H. and Reinhold, W. B., Why Drill Pipe Fails in the SlipArea, World Oil October 1969... Grenawalt, J. J., Pallante N. L. and Roblin, M. J., Relative SealingCharacteristics of Thread Compounds, presented at the Petroleum BranchASME Meeting, Philadelphia, Pa., Sept. 17-20, 1967, also R&D report ofYoungstown Sheet & Tube Co.41Weiner P. D. and True M. E. Unique Device Eliminates Leaks inAPI Connections, World Oil July 1969... Anon, 1976.77 Tubing Tables World Oil January 1976... Weiner, P. D. and True, M. E., A Method of Obtaining Leakproof APIThreaded Connections in High-Pressure Gas Service, API Paper 926-14-M,presented March 1969.55Eaton, B. A., Detecting Leaks in Oil Field Tubular Connections,Worla Oil September 1973.51 Formulas and Calculations for Casing, Tubing, Drill Pipe, and LinePipe Properties, API Bul 5C3, Second Edition, November 1974.52Weiner, P. D. and Sewell, F. D., New Technology for ImprovedTubular Connection Performance, JPT March 1967... TAPE Control: The New Reliable Method of Evaluating ThreadedConnections and Controlling Makeup, AMF Tuboscope Factsheet Vol.76, No.6... Hasha, M. H. and Snyder, R. E., External Testing Finds Hidden Con-nection Leaks, World Oil February 1971-.55Kerr.. H. P., Thread Leaks in Tubing and Casing Stringo, API Drillingand rroduchon Practice 1965, p. 14.55Cox, W. R., Key Factors Affecting Landing of Casing, API Drill ingand Production Practice 19S7, Pl'. 22S-2S0.., Chesney, A. J., Jr., and Garcia, J., Load and Stability Analysis ofTubular Strings, Paper 69-Pet-lS, presented at the ASME PetroleumMechanical Engineering Conference, Tulsa, Okla., Sept. 21~25, 1969.51Dellinger T. B., and McLean, J., Preventing Instability in PartiallyCemented Intermediate casing Strings, Paper SPE 4606, presented at theFall Meeting of SPE 1 AIME, Las Vegas, Nev., Sept. 30-0cl. 3, 1973.


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CementingoilandgaswellsPart How basic cements and additivescan be tailored to give desiredproperties for completion and remedialoperations

George o. Suman Jr. President, and Richard C. EllisProject Engineer, Completion Technology Co., Houston10 second summary

API's classification of basic cements is presented,commercial additives are listed and effects of slurryformulation on properties such as thickening time, com-pressive strength and density are discussed. The functionof various cement compositions in typical and specialdownhole applications is explained.CEMENT SLURRYcomposition can be tailored-by

selection of the correct API-classified cement, proper useof one or more additives and addition of the desiredvolume of water-to meet demands of nearly any modernwell completion. Examples of applications where specialcement formulations may be needed are: High pressuregas containment, squeezing and plugging, extreme tem-peratures and lost circulation conditions. This articlecovers these important considerations with discussions of:

~ Basic cement properties: Chemical and physicalcharacteristics; API classifications and geographical ap-plication; how to calculate slurry density, yield and cost

~ Cement additives: A listing of what's availableunder what trade name; how additives are used to developslurry properties such as fast or slow thickening time,high or low density and fluid (filtrate) loss

~ Properties of set cement: How cement compositionaffects strength and expansion characteristics, and:~ Special cements: A discussion of salt cement; form-ulations for high/low temperature conditions.

SIC CEMENT PROPERTIESNeat oil well cement-the basic powdered material,without additives-is commonly called Portland cement

after the small town in England where it was first made.It is manufactured from limestone, clay, sand and ironore, which are finely ground and blended, then fired in arotary kiln to about 2,600 F. These materials semi-meltinto glass-like balls or clinkers of complex calcium silicatewhich then are re-ground with gypsum.

Portland cement consists primarily of: Tricalciumsilicate, dicalcium silicate, tricalcium aluminate andtetracalcium aluminoferrite. In addition, it contains freegypsum (CaS04) magnesia (MgO) and lime (CaO).59

The percentage of these components in the final blendcan affect early strength, sulfate resistance, hydration,swelling and cracking during cure and/or rate of harden-ing. API has established cement classes, with maximumpercent of the above chemical components designated. GOAPI has developed physical requirements as well, includ-ing: water addition, soundness, fineness, minimum thick-ening time, minimum compressive strength and freewater content.

Soundness is a measure of the expansive properties ofa cement, and fineness is the particle size to which aclinker is ground. Particle size can affect setting time,early strength and water addition.

API also has specifications for certain additives suchas bentonite, barite and fly ash.Cement classifications provided by API for nine classesof cement allow for various pressure/temperature condi-tions, early strength, sulfate resistance, adaptability tomodification with accelerators and retarders and avail-ability, as follows:PI cement classes

.As manufactured. ased on normal s ize cement job in wel l wi th geothermal gradient of1 5 F per 100 teetThe nine classes cover applications to depths of 16,000

feet (4,800 m), as manufactured, and a wide variety ofdepth and temperature/pressure conditions with additionof accelerators or retarders.

Because sulfate salts have low solubility at tempera-tures above 140 F, sulfate resistance is not normally aconsideration at that temperature or higher.Some 40 manufacturers around the world are author-

WORL O L 9

AvailableDepth range, . sulfateClass ft. resistance Characteristics,availability-A 0-6,000 Ordinary Common(construction),widely avail.B 0-6,000 Moderate Special (construction), avail. California,CanadaC 0-6,000 Ord.,mod.,high High early strength, fine grind, widelyavail.0 6,000-10,000 Mod.,high Coarse grind, retarded, not avail. NorthAmericaE 10,000-14,000 Mod.,high Sameas DF 10,000-16,000 Mod.,high Sameas DG 0-8,000 Mod.,high Basiccement, no chemicalretarder, avail.West.U.S.H 0-8,000 Moderate Basiccement, coarse grind no chemicalretarder, GulfCoast Mid-ContinentJ 12,000-16,000 High Resistsstrength retrogression,min. temp.2300F


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J:I-( )ZWa::I-w>c;;wa::a.::;;o()

8,000

,4,000NOT PUMPABLE PUMPABLE

30 46.~WATER CONTENT,

I50

Fig 22-Compressive strength of cement is reduced nearly inproportion to amount of water in slurry. Approximate pointsfor water required for hydration, minimum water and maxi-mum water are also indicated..'

ized to use the API monogram for one or more classes ofcement; still, only a few classes are available in a givenarea. However, two basic cement classes can be modifiedwith accelerators or retarders to cover a wide variety ofpressure/temperature conditions-Class G (available inColorado, California and Alaska) and Class H (availablein Mid-Continent and Gulf Coast).Depth ratings of cement are based on lab determinationsof thickening time and minimum compressive strengthdevelopment, in which samples are subjected to simu-lated temperature/pressure behavior representative of alarge percentage of actual jobs.61

Thickening time is the time required to reach theapproximate upper limit of pumpable consistency. Mini-mum thickening time specifications (and maximum forclasses G and H) are based on pumping times from fielddata.

Minimum compressive strengths are specified after 8and/or 24-hour curing times for samples subjected topressure (3,000 psi except for 1,000-foot and 2,000-footsimulations) and temperature (based on a geothermalgradient of 1.5 F per 100 feet).Since actual geothermal temperature gradient, bottom

hole circulating temperature and time requirement maydiffer from those used in the lab to establish depthratings, such ratings will not always be applicable. Forinstance, geothermal temperature gradients range fromabout 0.8 to 2.4 F per 100 feet in various parts of thesoutheast United States.

Where the gradient is low, depth rating might beextended; conversely, depth rating might have to bereduced where the gradient is high.

A recent (1976) compilation of subsurface temper-ature data by the American Association of PetroleumWORL OIL 9

Geologists and Uni~ed States Geological Survey has beenpublished in two map sets Subsurface Temperature Mapof North America and The Geothermal-Gradient Mapof North America. These maps are available throughthe Branch of Distribution, U.

Documents

Cementing Handbook-George Suman