WorldOil's

Cementing oil and gaswells. . . including casing handling procedures

BYGEORGE o. SUMAN, JR. .AND RICHARD C. ELLIS

Acknowledgment

This 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 Industries,Inc.; 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

WOl'ld Oil P.O. Box 2608 Houston, Texas 77001

Tableof Contents

CementingOil and Gas Wells HandbookPart 1-Basic functions of cement are

given, with concepts to consider in mud,pipe and hole preparation to preventjob failure . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 5

Part 2-Casing inspection and pipehandling methods, including threadmake-up control, hydrostatic testing,landing practices . . . . . . . . . . . . . . . . . . . . . . .14

Part 3-How basic cements and additivescan be tailored to give desired propertiesfor completion and remedial operations. . . .22

Part 4-Practical interpretation ofrheology, annular displacing forces.How to avoid bypassing mud duringprimary cementing .32

Part 5-Guidelines for downholeequipment use, stage cementingmethods, new concepts for cementinglarge diameter casing . . . . . . . . . . . . . . . . . . .41

Part 6-Liner applications and equipmentused for installation. Common problemsto avoid while pumping, displacingcement 50

Part 7-A review of cement plugplacement, tubingless completiontechniques and the art and science ofcement squeezing 57

Part 8-Methods for evaluating primarycementing effectiveness plus a wrapupof several new tools to improvecompletion operations 66

About the authorsGEORGEO. 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 companies

in 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.

Cementing oil and gas wells...includingcasinghandlingprocedures

Part 1-Basic functions of cement are

given, with concepts to consider in mud,pipe and hole preparation to preventjob failure

George o. Suman, Jr., PresidentandRichard C. Ellis, Project Engineer,CompletionTechnologyCo.,Houston

10-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 can

lead 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

WORLD OIL 1977

About the seriesField engineers and others who handle casing and

cementing 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 failures

2. Casing handling, recommendations for inspection,make-up and testing

3. Cement slurry chemistry and use of additives

4. Displacement mechanics and rheology considera-tions, need for pipe movement and centralization

5. Primary cementing, proper use of downhole andsurface equipment

6. Liner cementing, techniques, problems, how toevaluate results

7. Special cementing, recent innovations, remedialsqueezes, plug-backs, tubingless completions

8. 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

5

FORCE

CEMENTSLURRY Uf;~i; ~}--;':'

.

:::

.'

::,:';: PRESSURE>':;~: ;\..=~.

B ':':\~ "~',::j:

HYDRAULIC BOND

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.

.

..

..

....".' ,..';. .,.:..:

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':.- . ." ,.0-' '.'".. ."':j ~~';

:"; " ;i~~:. I .'.

A'" '_.. n.....SHEAR BOND

PRESSURE

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SAWED-OFF HERE FORBOND TEST

'C

CEMENT

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 later

2. To seal intended production or injection intervalsfrom overlying or underlying permeable sections (zoneisolation)

3. To protect the casing from damage or failure, and

4. To support the borehole through the productiveinterval.

AXIAL LOAD SUPPORT

High axial loads may be imposed on the casing stringand/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.1,2.3

The 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, pounds

Sc = compressive strength, psi

d = outside diameter of casing, inches

H = 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 bond

during 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

WORLD OIL 1977

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 slurrydensity 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 ISOLATION

Although cement with a low compressive strength maybe 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 become

WORLD OIL 1977

350 TYPE CEMENT1. (C)2. SPECIAL (A)3. (A) 6% GEL4. (A)5. (A) LATEX6. OXYCHLORIDE CEMENT7. (A) MUD WET, WATER

WASHED8. EMULSION CEMENT9. 50/50 POZ., 2% GEL

10. (A) DISPLACED PASTMUD WET PIPE

11. (A) MUD WET, NODISPLACEMENT

300\

~ 250,ci :

is 200m ,

a: 150<Cwffi 100

50

oo 50 100 150 200 250 300

CEMENTTENSILESTRENGTH,PSI

Fig. 2-Effect of cement tensile strength and mud wettingon shear bond. Most cements fall in narrow range exceptwhere mud is not removed (after Bearden and Lane)'.

CIZ0'm

~IwtJ:;en

-FRESH WATER MUD---SALT WATER MUD-'-RED MUD

~-OIL EMULSION MUD.,~.:.~

,,,.............. ~...."......................... -" '", .

..

0=,0.2 0.4 0.6 0.8

WATER/CEMENTRATIO5 10 15VOLUME MUD, %

20

Fig. 3-Water content and mud contamination lower shearbond strength. Absolute value of shear bond is not shownbut the scale is linear so that percent change can be esti-mated (after Becker and Petersen)'.

smaller in diameter and "pull away" from the cement,forming a micro-annulus which permits leakage.

Hydraulic bond strength in the test shown in Fig. 1(B)ranges from 100 to 1,200 psi for water and from 45 to450+ psi for gas (nitrogen) depending on roughness ofthe exterior pipe surface and type of mud wetting, seebelow. No fixed correlation between cement compressivestrength and hydraulic bond was found.

Hydraulic bond YS. casing surface andtype of fluid wetting3,6

Cement: API Class AWater Content: 5.2 galjskCuring temperature: 80°FCuring time: 24 hoursCasing size: 2" inside 4"

Hydraulic bond strength is improved by resin-sandcoatings, as shown above, only when there is no mudwetting. Such coatings consist of graded sand bonded by

7

Type Hydraulic bond (psi)mud -

Surface finish wetting Water Gas

New mill-varnished."" , '" " . None 200-250Varnishremoved(chemical).. . . None 300-400Varnishremoved(sand-blasl).... None 500-700 150Varnishremoved(sand-blast)... . Fresh water 100 50Varnishremoved(sand-blast).... Invert oilemulsion 100 50Varnishremoved (sand-blast).... Oilbase 100 50

Resin-sandcoat (new,sand blast) None 1,100-1,200 450Resin-sandcoat (new, sand blat) Fresh water 100 55Resin-sandcoat (new, sand biast) Invert oilemulsion 100 45Resin-sandcoat (new,sand blast) Oilbase ICO 45

6000

4'12" CASING BEFORE PERFORATING

.4000

Ci511.

:i" 2000l-e!)ZWa:I-CJ)W>Ci5 6000CJ)wa:11.:::E

8 4000

o .HOLLOW CARRIER JEToEXPENDABLE JET .

_ PE~FORATIONPRESSURE

2%" TUBING 2000

o4000 6000o 2000

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/or

2. 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 strength

Surfacecondition

Dry .Mudfilm.........Dry ....Mudfilm ....Dry .Mudfilm ....Dry .Mudfilm ....Dry .Mudfilm.........

Surface coating

Mill varnishMillvarnishRustyRustyAcid etchedAcid etchedSandblastedSandblastedEpoxycoated, 6-12 mesh sandEpoxycoated, 6-12 mesh sand

Hydraulic bond, psi

<20<20

350-45020-50

250-40040-50

500-60050-60

700-950500-600

Curing time: 24 hoursCuring temperature: 120 F

And casing using the Ruff-Cote process should be wellcentralized to avoid imbedding mudcake or shale intothe roughened surface. Preventing such imbedment mightnot be possible in irregular, doglegged or high angle hole,or where mud is poorly conditioned.

One important advantage of the resin-sand treatmentwould be that formation of a micro-annulus under certain

pressure/temperature conditions might be prevented. Thisresult appears to be verified by cement-bond logs.8

Cement-formation bond. Still other tests have beenconducted to examine the bond between cement and for-mation. In one lab investigation3 in which cement wasplaced into contact with formation cores and the inter-face was tapped by a simulated perforation, the effectof various contact surfaces (dry, mud layer) and appliedsqueeze pressure was evaluated.

Bond strength was found to depend on degree of con-tact between cement and formation. When a mud cake

was present between cement and formation, bond strengthwas greatly reduced for all cases examined. When cementwas squeezed against dry cores, bond strength approachedor exceeded formation compressive strength.

Test results were not provided for low compressive and/or low tensile strength formation materials such as un-consolidated sands and some shales. Presumably, little orno bond strength would be indicated for these materials-yet zone isolation is obtained in the field.

Although these results may be indicative of various re-lationships, tests more closely simulating downhole con-ditions might provide further insight into the require-ments for zone isolation.

Cement vs. perforating damage. Operators have gen-erally considered cement with 2,000 psi or less compressivestrength optimum for perforating-a belief based on ap-pearance of targets perforated with bullets and/or jetsat the surface, under simulated downhole conditions.9.loVisual inspection of such perforated targets containinghigher strength cement revealed cracks in the sheath.

Application of results of these tests is wrong because:Atmospheric tests of explosives are more damaging thanthose performed under pressure due to greater expansionof detonation gases, and cement with hairline fracturesmay still prevent fluid leakage.

Godfrey11 measured shear and hydraulic bond strengthson samples before and after perforating with single hol-low carrier and expandable jet charges, under simulateddownhole pressure conditions (3,000 or 5,000 psi). Thetest arrangement, Fig. 4, prevented creation of a micro-annulus and the cement was loaded in compression fromouter and inner surfaces, as well as from the bottom.The 1-9/16-inch OD hollow carrier gun used a 3.2 gram

WORLD OIL 1977

i

fl I!:\:.:.

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 collarsthat 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 PROTECTION

The cement sheath between casing and borehole servesan important function in protecting the pipe from thestresses 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 the"flattening" 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-

WORLD OIL 1977

C/) 0.5w:I:o~ 0.4z

g 0.3<I:::!Ea:~ 0.2wo

~ 0.1en<I:o o

o 10 20 30STRENGTH FACTOR x 10'

(WALL THICK x YIELD)

40

Z 0.3o~~ffi0.20:1:LLO~~ 0.1(!)zen

t3

r--

o 1 2 3 4 5 6CEMENTCOMPRESSIVESTRENGTHx 1,000, PSI

7

Fig. 5-Cement support minimizes casing deformation causedby expendable perforating guns as shown by curves, top,from tests with 20 gram charges, at 1,000 psi and 1800 Fconditions. The three cases represent no cement, a :lA-inchsheath held by thin steel and a strongly encased sheath.Compressive strength of the sheath was less important, asindicated by second curve, bottom (after Bell and Shore)."

ment along natural or induced fault planes-as opposedto salt flow-is best handled by elimination of cementthrough the affected interval and perhaps opening thehole to enable fault slippage to take place without load-ing the casing in shear/s,lG Fig. 6 (bottom).

Other downhole conditions, such as borehole doglegsand sand control failure,17 also may cause casing damagesimilar to the types described above. The type of loadcondition may be deduced through geology, petrophysics,and operational correlations and measurements of thedamage configuration.18 Tools are available for establish-ing the cross-section (collapse) and deflection (bucklingor shear) of moderately damaged pipe. Knowledge offailure mechanism is essential to selection of the failureprevention method, i.e. cement sheath or no cementsheath.

Casing joint loss. Adequate cement strength and goodcementing and operational practices may be required toprevent parting or other failure in the bottom joints ofsurface and intermediate casing strings.19 In most cases,failure in the bottom few joints of casing is not discovereduntil electric logs show that the bottom one, two, orthree joints have parted from the string and slipped downthe hole. In other cases, the parted section uncovers ahigh pressure or lost circulation zone, or it shifts laterally,restricting passage of drilling equipment.

Analysis of possible causes of such failure19 indicate thatthe casing is unscrewed rather than broken. The un-screwing occurs because of short-lived, high-level torqueimpulses transmitted to the casing by the bit as it hangsup while drilling cement and cementing equipment outof the bottom joints. The problem is normally preventedby welding or using thread locking compounds on the

9

LOADING

SALT FLOW

FAULT SLIPPAGE

~MUDONLY

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 SLURRY

MUD FILM

CASING - - ---

~MUDI

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 curves

10

in directionally drilled holes near the casing point.

2. Weld threads on H-40 pipe with a ~-inch filletweld (see cautions below) or properly clean threads onJ-55or 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 highearly 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.21

7. Do not disturb casing until cement has obtainedinitial 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.

Welding recommendations. Lower casing grades,H-40, present few problems. However, field personnelshould be a ware 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 be

WORLD OIL 1977

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 grades(H-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 DRILLING

Favorable conditions for primary cementing should beestablished 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) withlow 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, and

3. Is compatible with cement composition.

Such conditions cannot always be attained in actualpractice. 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 concept25. 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 to

WORLD OIL 1977

500

.@

~ :E300Cl)CL>a:a:.<5b0200a:.....w:::!

~~150Cl)Cj:Ez=>a;~ ;;1100~~ 90:E 80"

7060

4 5 5'12 6 6'12 7 7'12 8DRILL COLLAR SIZE, INCHES

9 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, withpressure 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 filtercake 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 solid clay particles.

This pressure loading effect and the high frictionfactor between pipe and cake solids can increase hookload until the casing cannot be moved.

How to prevent sticking. During cementing, differential

11

A

B c

Fig. 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 c

Fig. 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 pressuresticking are:

. Sticking occurs opposite permeable formations, par-ticularly where pressure is depleted and/or high mudoverbalance pressure exists

12

. 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 andfilter cake. Muds are available which provide cakes withlower coefficients of friction.29

CASING 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)

. Excessivemaking and 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 causes

for leaking joints can be avoided through proper inspec-tion and make-up practices, many of which will be dis-cussed in the next article.

WORLD OIL 1977

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, transversecracks

Casing joints containing such imperfections may beidentified 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 Operations

to Elimmate WOC Time," API Drilling and Production Practice (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 CompositionsforCementing Wells," Proc..::,]..Sixth 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.·Evans

b 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 Perforating," 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 Drilling and Production Practice (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 witlt 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.

WORLD OIL 1977

A

';~

)B C

Fig. 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 Anadarko

Basin," Paper SPE 3909, 1972 Deep Drilling 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 Publication.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

Cementing oil and gas wellsPart 2-Casing inspection and pipehandling methods, including threadmake-up control, hydrostatic testing,landing practices

George o. Suman, Jr., President,and Richard C. Ellis,Project Engineer, Completion Technology Co., Houston

15-second summaryHow electronic inspection at the mill, pipe yard or rig

site 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 trendtowards 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 1.4%of 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 mill

i~ Pipe handling: Recommended procedures for trans-porting and running casing; rig floor practices to avoidslip and tong damage

~ Casing make-up: Functions of threads and threadcompounds in sealing-off fluids; factors affecting torquerecommendations, and systems to control make-up .foroptimum connection performance, and

~ Rig floor connection testing: Internal and externalhydrostatic tests for leakage; how thread configurationaffects test application; casing landing practices.

Many casing problems are directly related to casingcondition 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 INSPECTION

Casing inspection can mean anything from visual rigcrew checks of pipe body and threads while running, toextensive 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 5V2-inch, N-aocasing segment, shows how seam in the metal wasdetected by inspection.

LONGITUDINAL IMPERFECTION SEARCH COIL TRANSDUCER

~G' 1([lIQMAGNETIC SOURCE PIPE

Fig. 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 ofNDI; 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 forcomplete inspection of casing is less than 10% of totalcasing cost, as shown in the table on following page.

WORLD OIL 1977

Inspection costs vs. casing costs

Need 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'scasing 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 defect as any imperfection thateffectively reduces the wall thickness of any grade pipeto less than 871'2% of the specified 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 imperfection 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

"An additional821 "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,eccentric

3317

1041

261

182

New casing inspection results*

Location,type of Imperfectlon**

Casing No.lengths External InternalSize Inspected bodywall bodywall Connection Drift,othert

4!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 25t

10% 1,416 36 4 2211% 7513% 1,109 2 1 22 116 114 .... 1 220 123 2 .... 1

Total 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-no

13% 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.40I lengths.** Typical casing costs, Jan. 1977.

No. End afea,lengths Total Body othef

Grade Inspected defects defects defect

K-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 defective

Imperfect lengths

118 40642 467509 373517 259205 152596 47963 59

26 263 33 3

2,682 1,861

Descriptionof bodywall,connectionImperfections

CasingSeam Lap Roll-Inslug Pit Gouge Crack,cut Plntt Coupllngtt

Size Ext Int Ext Int Ext Int Ext Int Ext Int Ext Int Mfg Hdg Mfg Hdg

4!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 22

10% 14 2 20 1 2 9 1311%130/8 1 1 1 17 516 .. .. 120 2 .. 1

Total 575 17 466 53 204 18 121 17 85 8 46 19 101 251 396 53

* Source:AMFTuboscop,ereports to several operators on new casinginspection in various yard and field locations,1975/1976.** SeeAPI definitionof 'imperfection"and"defect" in text.t Includes1-3 lengths of wronggrade or wrongweiht.

tt Analysisof connectiondamage by manufactureror 10handling.

WORLD OIL 1977 15

pendent service companies utilizing NDI techniques.One possible reason that manufacturers' NDI does not

discover 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 a"go, 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, 38

Non-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 1.315

to 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 EDFSC

sensitivity to internal 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. 17.40 Thesesystems 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 TRANSDUCER

ELECTRIC COIL ~, _\II ..-:':-

~LONGITUDINAL

MAGNETIC FIELD

TRANSVERSEIMPERFECTION

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

ROTATION GAMMA SOURCE

OETECTOR / SHIELD

SHIELDRADIATION BEAM

SINGLE-WALLBACKSCATTER

THROUGHSINGLE-WALL

THROUGHDOUBLE-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 qualitative. 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

WORLD Oil 1977

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 87Y2% 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-inch

when the sonde is properly coupled to the pipe.In application, a liquid couplant-like water, oil or

antifreeze 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.42

Identification 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.

WORLD OIL 1977

Recommended inspected tubulargoods identification

Indicates

Meets API specs

Imperfections not repaired as perAPI Std 5AX

Imperfections repaired asper API std 5AX

ID imperfections, depths cannotbe measured accurately

ID or OD defects that failAPI acceptance specs

Defective box or pin

Red Near box

Red Aroundcoupling,adjacent tothreads

Nearcouplingor box end

Length fails to passAPI drift mandrel

Orange,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 HANDLING

During the past 40 years, recommendations for propercare 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. 32, 43

Recommended casing handling practices. Move casing only when thread protectors are in place

17

Type paintband Location

White Near box

Yellow Near box

Yellow and Near boxwhite

Blue Near box

. 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 "jump" 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. 18,44 axial 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: 45

Fe (lbs.) = C X A X (T

Where

(T = yield strength of the casing, psiA = Cross sectional area of the pipe body, in2

[rK

(rK

)2

J1/2

C =Crushing factor = 1/ 1+ L + L

And: r = Outside casing radius, in.L = Slip gripping 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 = 0.606(T = 80,000psi, and

Fe= 0.606 X 13.57X 80,000= 657,000pounds.

Slips used for heavy casing 'Strings should be checked

18

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.+ tana

Where: 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-UPI 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

WORLD OIL 1977

VANISHING POINT MAKE-UP

\ c :tTW~,,~~RE~D TURNS OK~! I

POWERTIGHT BEARING PRESSURE

MAKEUP API ROUND THREAD

HANDTlGHT

MAKE-UP<J OPPOSITE ANYiPART

! / OF STAMP OKIII

TRIANGLE STAMP[>,

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 alone 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.43

The 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 is

maintained 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.46

Non-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 theyield 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.

WORLD 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 make-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, then

2. Use that torque to make-up the balance of the sameweight and grade pipe in the string, but

3. Continually observe make-up position for verificationof proper make-up.

Buttress thread connections have triangles stamped onthe 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%.52

Such 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 with both pipe and Iub r ican 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

19

of reference, minimum and maximum torque, and low,minimum and high turns.

These torque and turns settings vary with size, weightand 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 cleaned 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 TESTS

Hydrostatic testing of casing connections on the rigfloor 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 AMF Tuboscope).

P,

tQ.uia:::>enenwa:Q.

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

I 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 havea 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 apparently adequatetorque. 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 the

WORLD OIL 1977

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 cemented"

2. It can be stretched to increase tension, or

3. It can be slacked off to reduce tension.

Which procedure is used and to what degree slack-offor 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 1977

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 Edition, 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 API

Threaded 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 Drillingand 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 01 AIME, Las Vegas, Nev., Sept. 30-0cl. 3, 1973.

21

CementingoilandgaswellsPart 3-How basic cements and additives

can be tailored to give desiredproperties for completion and remedialoperations

George o. Suman, Jr., President, and Richard C. Ellis,Project Engineer, Completion Technology Co., Houston

10-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 SLURRY composition can be tailored-byselection of the correct API-classified cement, proper useof one or more additives and addition of the desired

volume 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.

22

BASIC CEMENT PROPERTIES

"Neat" 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:

API cement classes

.As manufactured. Based on normal size cement job in well with geothermal gradient of1.50 F per 100 teet.

The nine classes cover applications to depths of 16,000feet (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-

WORLD OIL 1977

AvailableDepth range, . sulfate

Class 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, widely

avail.0 6,000-10,000 Mod.,high Coarse grind, retarded, not avail. North

AmericaE 10,000-14,000 Mod.,high Same as DF 10,000-16,000 Mod.,high Same as DG 0-8,000 Mod.,high Basiccement, no chemicalretarder, avail.

West. U.S.H 0-8,000 Moderate Basic cement, coarse grind no chemical

retarder, GulfCoast&Mid-ContinentJ 12,000-16,000 High Resistsstrength retrogression,min. temp.

2300F

J:I-(!)ZWa::I-enw>c;;enwa::a.::;;o()

8,000

,4,000

NOT 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 modified

with 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 determinations

of 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, bottomhole 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 Petroleum

WORLD OIL 1977

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.S. Geological Survey, 1200South Eads St., Arlington, Va. 22202 (or same office,Box 25286, Federal Center, Denver, Colo. 80225) at aprice of $4 per set. Service companies can also supplysuch data.

Water is added to cement to make the slurry pump-able, and provide for hydration (the chemical reaction).Although only 25% water by weight of cement (Fig. 22)may be needed for hydration (a slurry density of about18.3 ppg), normal water content is higher to provide forpumpability, as shown below:

Neat cement slurries

* Basedon absolute vol. per sack cement equal 3.59 gals.

The normal water content differs for various classes

according to fineness of grind. Excess water should beavoided to prevent cement-water stratification. APIrequires that Class G and H slurries have less than 1.4%top settling (free water) as measured in a 250 ml gradu-ate in two hours.

Care should be taken to add the proper amount ofwater for the cement to be used. For example, Class His sometimes inadvertently handled like Class A, and theresulting mix has reduced strength, retarded thickeningtime and excessive free water.

Free water content is usually higher at increasedtemperature due to thinning, and lab tests at elevatedtemperature are sometimes required. Free water can beminimized by: Limiting the amount of mix water, addingbentonite in small quantities or selecting and controllingquantity of other slurry additives.

How to calculate yield, cost. To estimate job cost,price per sack is not as important as cost per cubic footof slurry because the latter varies with yield due to dif-ferent water contents.

Slurry density, yield and cost can be calculated, givenspecific gravity, bulk weight and water required by thecement-or additive-and cost of the material, as follows:

Given:

. One sack (one cubic foot) of Class A cement weighs94 pounds

. Cement cost is $3.75 per sack

23

Percent

I Gals.waterSlurry Slurry

Class water per sack den., ppg* yld., ft.'/sk*

A. . . ..... ........ .. 46 5.19 15.6 1.17B............ ........ 46 5.19 15.6 1.17C................. .... 56 6.32 14.8 1.32D..... . .. .. '" .... 38 4.28 16.4 1.05E....... .. ... ... 38 4.28 16.4 1.05F............. ... 38 4.28 16.4 1.05G..... .. 44 4.96 15.8 1.14H. ... ... 38 4.28 16.4 1.05J. ... 38-43.5 .28-4.91 16.0-15.4 1.09-1.17

. 5.19 gallons of water required per sack

. Specific gravity of water is 1.0, density is 8.34 ppg

. Specific gravity of cement is 3.15, absolute density is3.15 X 8.34 ppg =26.21 ppg, and

. One cubic foot equals 7.48 gallons.

Then:

. Absolutevolume of cement = 94/26.21 = 3.59 gallons

· Weight of water per sack=5.19 X 8.34 = 43.28 pounds. Absolutevolumeof water = 5.19 gallons.

And:

. Slurry density = Weight/volume = (94 + 43.28) /(3.59 + 5.19) = 15.6 ppg

. Yield = gals. per sack/gals. per ft.' = 8.78/7.48 = 1.17ft.' per sack

. Slurry cost = $3.75 per sack/I. I? ft.' per sack = $3.21per it.'

Most slurry additives are expressed as percent byweight of cement. One exception is salt which is expressedas percent by weight of fresh water.

When additives such as bentonite are used in the mix-ture, this calculating method must be expanded. Densi-ties and water requirements of most additives are includedin the accompanying table. Service companies can alsoprovide such information to customers, with density andyield already calculated for most mixtures.

Another source of information concerning the chemicalaspects of cement and additives is the SPE Monograph,Cementing, by Dwight Smith.62

CEMENT ADDITIVES

Almost all cement used in oil and gas wells is Portlandcement. However, "neat" cement is seldom used through-out a job as various additions are usually made to modifythe following properties of either slurry or set cement:

Slurry

Thickening TimeDensity (yield)Friction during pumpingFluid loss (filtrate)Lost circulation resistance

Set cement

Compressive strengthStrength retrogressionCement strength downholeExpansion

----10

8API CLASSAS NOTED

2

o40 8060 140 160

A listing of selected additives available from major U.S.

service companies is shown in the accompanying table.And the following discussions explain functions of these

additives in modifying cement composition.

Mud contamination also acts on the slurry to affectsome or all of the above properties; these effects will bediscussed in a later article.

Thickening time. may be varied using accelerators orretarders. The most common accelerators are: Calcium

chloride, sodium silicate, sodium chloride (low concentra-tions), seawater, gypsum and ammonium chloride.

Additives that retard are: Calcium lignosulfonate,organic blends, carboxy methyl hydroxy ethyl cellulose(CMHEC), borax, sodium chloride (high concentrations)and most fluid loss agents.

Thickening time is a function of both temperature andpressure, Fig. 23.63 Thickening time can also be shortenedby interruption of pumping (loss of agitation). And APItests can be done in this manner to simulate actual inter-

ruptions during squeezing (tentative).Thus, thickening time of a slurry must be esta:blished

for realistic conditions to ensure adequate pumping timefor slurry placement. Avoid excessive thickening time toprevent: Delays in resuming drilling operations, settlingand separation of cement slurry components, formationof free water pockets, loss of hydrostatic head and gascutting.

Increased water lengthens thickening time of unretardedcement (Classe A, C, G, H). However, with retardedcements (Classes D, E, F) increased water or solids mayshorten thickening times by reducing the concentration ofretarder.64

Thickening time can be measured using pressurizedconsistometers. API has developed schedules, for pressure/temperature increases versus time, that simulate cementplacement conditions for different types of cementingoperations such as squeeze cementing (also plug back),liner cementing (tentative), casing cementing and alter-nate hesitation squeeze cementing (tentative). Thickeningtime tests can also be tailored to individual well condi-

- -----------

CLASS A

5180 o 4

Fig. 23-Effect of temperature and pressure on thickening time of Portland cement. At atmospheric pressure, left, thickeningtime is reduced by high temperature. At constant temperature, right, thickening time is reduced by pressure (after Bearden)..'

24 WORLD OIL 1977

5,'

4

00a:J: 3W:2i=

2Q:EI-

14QOF-180°F

I I

2 3

Selective products of major U.S. service companies

Basic cements' (Class A, B, C, D, G, H): Specific gravity 3.15, bulk density 94 Ibs';sack (80 in Canada).See accompanying table for water requi remenl.

Note: "None" means water required is not significant or is not intended to be used." . ." means data or trade name is unknown, product may be available.This table is not a complete listing of available products. Please check with local service companies.

tions by service companies, if the published API schedulesare not applicable.

Note: These measurements are made in metal vessels

which prevent any fluid loss. Thickening time valuesdetermined are therefore higher than they might be oppo-site a permeable zone, after partial dehydration.

Slurry density may be reduced with extenders such asbentonite, pozzolan, diatomaceous earth and anhydroussodium meta-silicate. Gilsonite and crushed coal also

reduce density. And special calcined shale--cement (suchas Trinity Lite-Wate or Texas Industries Light Weight)are used for this purpose.

Low density is frequently desired, to decrease likelihoodof breaking-down the formation and causing lost circula-tion. In addition, such slurries cost less per cubic foot, asyield per sack is increased.

Density decrease results in large part from increasedwater content. Extenders permit water addition withoutseparation. However, cement strength is reduced approxi-mately in proportion to water content increase, Fig. 22.

WORLD OIL 1977

However, as was discussed in Part 1, high cement strengthis not always required.Bentonite has for years been the most commonly usedadditive for "filler" type cement.65 In addition to itseffect on density, yield and cost, bentonite increases vis-cosity and gel strength, which reduces settling of highdensity particles (weight material, cement) or floatingof low density particles (Perlites, pozzolan, gilsonite,crushed coal).

Bentonite al:;o reduces API fluid loss. However, cements

containing bentonite are more permeable and have low-ered sulfate resistance.

Pozzolans increase slurry viscosity and provide lowpermeability. Sodium meta-silicate provides a very low-density slurry with early compressive strength; this mate-rial and calcined shale-cement are becoming popular,particularly offshore. The latter is a special cement, notan extender, as mentioned earlier.

Light-weight cements are listed in the accompanyingtable which separates slurry compositions providing more

25

Bulk Water TradenameSpecific density, required,

Product gravity Ibs./ft3 gal./sk OJ-Hughes Dewell Dresser Halllburten Western

AcceleratorCalcium chloride. . . . . . . . . . . . . . . . . . . . 1.75-1.96 50 None A7,A7-l, A6 SI CaCI, CaCI, CaCI,Salll-6%.............. ............ 2.16-2.17 70-71 None A-5 D44 Salt Sail SaltNaCl,CaCI, mixture....... ...... .... . 2.00esl. 50 esl. None

A8D43

HA-5..

CH.CI, CaCI, blend. . .. . . .. . .. . .. .. . 2.00esl. 50 esl. Noneil57

MA-2illacel ASodiumsilicate. .. . .. .. . ... ........ 2.62 60 None DiacelA DiacelA DiacelA

RetarderCalcium lignosulfonate... . . . . . . . . . . . . . . 1.5-1.56 35 None R-5 MlR-3 HR-4 WR-2Calc. ligno.(Kembreak).......... .... .. 1.23-1.30 30 None R-5 DI3 MlR-I HR-7 WR-IHightemp. blend. . . . . .. . . .. . . . . . . . . . . 1.22 23 None Rll, R14-l D28, D99, D100 MHR-8 HR-12, HR-20 WR-6lignin-liquid. . . .. .. .. .. .. .. .. .. .. .. .. 1.26 .- None R-IOl D81 MlR-l HR-6l WR-ll

CMHEC(carboxymethyl hydroxyethyl cellulose). . .. . .. . .. ... .. .. .. 1.36 29 o (up to 0.7%) R6 (Diacell Wl) D8, lWl MFlR-7 Diacell Wl Diacell Wl

Salt (saturated)......... ... .. . . . .. .. 2.16-2.17 70-71 .. A-5 D44 Salt Salt SaltBorax............................. . 1.73 65 .. Borax D93 MHR-9 Borax BoraxThixotropiccml. retarder. . . . . . . . . _. . 5.47 .. .. .. D74 .. .. WR-IO

ExtenderBentonite........................... . 2.65 60 1.3 (2% gel) BJ Gel Gel D20 M-Gel Gel Bentonite

Diatomaceousearth. . . . . . . . . . . . . . . . . 2.10 16.7 8.2 (cu. II.) DiacelD D56 DiacelD DiacelD DiacelD

POllolan:10%-5.0gal

Flyash. . . . .. .. .. .. .. . .. .. . . .. . .. 2.46 74 3.6 DiamlxF (74#) 035 (74#) Magco POI A POlmixA (74#) POlmentA (74# )Natural pOl. (S. Tex.). . . . . . . . . . . . . .. .. ..

ilin (47#)Magco POI N .. ..

Natural poz.(Calit.)..... .. .. .. .. ..2:66

.. DiamixA (47#) .. .. ..Flyash (NewOrleans, Houston)....... 60

10.9(max.).. D48(60#)

Eeonoblend Hallib.light..

CementPouolan and Bentonite.. . . . . . 2.89 87.0Trinity ll. WI.

litepoz 300

TLWi TXI Lt. WI.Calcinedshale-cemenl.. . . . . . .. . . . . . . 2.71 75 7.66 (max.) D49, Tl W, Dl W Trinity ll. WI. Trinityll. WI.Anhydroussodium meta-silicate. . . . . . 2.40 .. 6-6.8(2% sil.) lodense D79 Thrilly mix Econolite Thrlty lite

Weight materialOttawa sand. . . . . . . . . . . . . . . . . . . . . . . . 2.63 100 0 Frac sand 20/40 Sand MS-3 Sand SandBarite............................ . 4.25 135 2.4 W-l D31 Mcobar Barite BariteHematite (iron oxide). . . . . . . . . . . . . . . 4.93-5.02 165-193 0-0.36 W-5 D76 M -2 HiDense3 Hematite

gal/IOO Ibs.Ilmenite. . . . .. . . . . . . .. . . .. . . . . . . . . . 4.45 150 None .. D18 MW-I .. Ilmenite

Fluid loss additiveH............................ 1.36 29 o (up to 0.7%) R-6 D8 MFlR-7 DiaceI l Wl Diacell Wl

CEMAD-I(Amer.Cyananid).......... 1.36 Noneil59 MFl-5

CEMAD-I CEMAD-IOrganicpolymers................... 1.22 37-40 None Halad 9, 22A CF-I, CF-2,CF-6

OrganicpOIr,merblend.... .. ... . _ ...1.31 40 None D-19 D60 MFl-4 Halad 14 CF-3(ultra low)

Lost clrculat on materialGilsonite................ _.......... 1.07 50 2.0 (50 Ibs.) 0-7 D24 Gilsonite Gilsonite GilsoniteCrushedcoal (Kolite)................ 1.30 50 2.0 (50 Ibs.)

Cello-FlakeD42

Cell-O-Seal Cello-SealCellophane.. . . . . . . . . . . . . . . . . . . . . . . . D29 FloceIeWalnutshells. . . . . . . . . . . . . . . . . . . . . . . 1.28 50 0 Tuf-Plug J51 Nut Plug TUf-PIU Tuf-PlugPerlite expanded.. . . . . . . . . . . . . . . . . . . 2.40 8 4.0 (cu. II.) BJ Perlite 072 Perlite egoPerlite semi. expanded. . . . . . . . . . . . . . 2.40 43 6.0 (cu. fl.) Oil Patch Nine .. Perlites Perlite Six ..

HIi::r;:::.t.re................... . 2.63 70 4.8 (100Ibs.) D-8 D66 MS-I SSA-I SF 3Silicasand. . . . . . . _. . .. . . . . . . . . . . . . . 2.63 100 None D-8C D30 MS-2 SSA-2 SF 4

DispersantOrganic.. . . . . . . . .. . . . . . . .. . . . . . . . . . 1.30-1.63 40-43 None D-31 D65 MCD-3, MCD-4 CFR-I,CFR-2 TF-4liquid.. .. .. .. .. .. . .. .. . .. .. . . .. . .. 1.18 .. None D-31l D80 MCD-l CFR-22L ..

Special materialsExpanding cemen!. ... . . . . . . . . . . . . . . . 3.15 94 6.3 Chem Comp Chem Comp ChemComp ChemComp ChemCompDefoamers(Powder,liq., other)... _ .. .. .. 0-6, D-6l, 0-21 D46,D47 MFP-5, l NF-P NF-I AF-8,AF-l

D-Air1,2 'Gelagent blend (SloFlo)....... ... .. 2.26

Gyp-SealD71 .. VCT

Plaster paris (Gygsumcement). . . _. . .2.70 75 4.8 D53,RFC .. Cal-Seal Thixad

:r:xu.t . 'n:: : : : : : : : : : : : : :2.90esl. 75 4.0 Arcticset Permafrost II

CLX-I1.1090

0 0-5 D-15 MCl-2 latex lA-2Aluminate(CimentFondu,lumnite)... 3.20 4.5 lumnite lumnite

Hard Set I, 2lum. C.F. lum., C.F.

MudKiI(lo temp. and hi temp.)... . . .1:23

None Firm Set I, 2 Mud KiII, 2fda. Ii 2Nylonfibres... .. .. .. .. . .. .. . . . . .. . . None VisqueezMK-II 094 .. ..

Dieseloilcement (additive). . . . . . . . . . 0.90-1.00 NoneMudSweep

M54,F33 ..g2-- DOC-IO Excello-GelPrefiush-thick.................. _...

I.Ui'esl...

Swcer 1000Preflush-thin................... _... .. .. MudClean C 7, CWlOO MMW-l MCA, Mud Flush WMW-IOilmud spacer. . .. . . . . . . . . . . . . . . . . . 1.10esl. .. .. Unimul OBMSpacer MCS-2,MCS-3 SAM-4 APS-I, APS-2

:2 25Il.(XI

uiI-«a:

~ 1% ORGANICDISP. ADDEDc::::::J WITHOUT DISPERSANT

3i:o..JU.

..J«oi=a:o o

CLASSE

50/50POZ

CLASSA

Fig. 24-How dispersants reduce yield point to allow turbulentflow at reduced pump rates in a 5V2-inch casing by 7\18-inchwellbore annulus.""

than, and less than, 500 psi compressive strength.66 Thelowest-weight slurries providing more than 500 psi com-pressive strength are Class C cement with gel, andClass C cement with silicate.

Common light weight cements

Extender, % by wt. cementDensity, ppg, forcompo strength:1-.-.--.-.-.-

Type cement

GelClassH... ..

Gel

Sodiummeta- I IDlacel IAbove IBelow

Salt I sll. Water D 500psi SODpsi-1-1-1--1-1-

48

121648

121.5.2.0.2.5.3.0.3.5.4.0.4.5.

14.113.1

Class C" . .. . . . . . . . . . '13".i12.5

'l,i.213.712.8

Prehydrated gel. . . . . .

'l'2j12.111.810.7

Pozzolan and lIyash 50/50. . . 2

61018

Calcined shale-cement.. . . .

13.112.412.0

12.411.711.0

13.312.812.4

'i.o'2.03.0

Silicate......

Pozzolan andbentonitef

Class H . . . . . 6f6f6f6fClassC... .. .. . .. ..

DlacelD... ... .. .. ..

.Perc ent by weight water.. Trin ity Lite-Wate data. Similar cement available from Texas Industries.

f 65/ 35 cement and Pozmix A, % gel based on combined weight.

Density may be increased with weight material suchas sand, barite, hematite or ilmenite, and/or salt dis-solved in the mix water, as shown in the following table:66

Weight material for cement

26

A density of 22 ppg can be obtained with hematite orilmenite plus friction reducing additives. Fine barite (325mesh grind used in mud) requires a large amount ofwater, which reduces compressive strength and retardsthickening time, and therefore is rarely used.

A slurry weighted with solids must have viscosity andgel strength needed to carry and suspend high specificgravity solids. And it should be noted that some additivestend to significantly thin or thicken a slurry (fluid lossagents, retarders, water content)_

Pretesting of such high density slurries should includedensity, thickening time, compressive strength, settling,free water and viscosity measurements.

High density (up to 17.5 ppg) may be obtained byadding dispersant to the slurry to provide pumpability atlower than normal water/cement ratios. This approach ismost expensive, but results in highest compressivestrength. Cement densified in this manner also may needan additive to reduce filtrate loss because further reduc-

tion in water content may make the slurry unpumpable.Also, densification tends to accelerate curing time.

Friction reduction. Dispersants can also be used to reducethe yield point (consistency index) of the slurry, whichreduces friction and allows turbulence to occur at reduced

pump rates, Fig. 24. Common dispersants are: Alkyl arylsulfona~e, polyphosphate, lignosulfonate, salt and organicacid.

Turbulent flow additives tend to cause settling andexcessive free water. These effects should be tested in the

lab prior to field use.

Fluid 1055 (filtrate). Addition of fluid loss agents hasimportant application in: P reven ting gas leakage, insqueeze cementing and, occasionally, to maintain pump-ability in primary casing and liner cement jobs.

Fluid loss additives may also reduce likelihood of dif-ferential pressure sticking where stuck pipe has beenassociated with mud cake removal. Fluid loss additives

might be considered when there is little or no mud cakeon the borehole wall-for example, when drilling withwater. In normal primary cementing, high fluid losscement does not dehyrate significantly in permeable zonesbecause filtration is controlled by the mud cake.

The API fluid loss test on cement is conducted at 100

or 1,000 psi differential pressure through a 325 meshscreen. 1,000 psi is used when the slurry has been elevatedin temperature and pressure in a consistometer in accord-ance with one of the API simulation schedules. Testingconditions .need to be identified for the true meaning ofthe data to be known. In addition, many 100 psi testsare mistakenly run on No. 50 Whatman paper instead of325 mesh screen.

Water dehydrates almost instantly from a neat cementtested in the above manner. The 30 minute fluid loss

(100 psi) of neat Class A cement is about 1,000 ml.Early in 1960, significant progress was made in devel-

oping cement additives that lower fluid loss with a highmolecular weight, synthetic polymer.68 Such additivesmay provide fluid loss in a low range. These additivesusually are affected by temperature, Fig. 25. Generally,thickening time is retarded and, at low temperature, this

WORLD OIL 1977

14.1

'1.1.212.5

I I

....

65 .... 13.785 12.895

115

74 I I 13.683

104104

. io' I '13'.2203040

Max. Extra Elf. on Elf. onSpeci fie Grind density, water compo pumping

"'aterlal gravity (mesh) ppg needed strength time-- - - - -Jttawa sand....... 2.63 20-100 18 None None None3arite.. . ... .. . .. .. 4.25 325 19 20% Reduce Reduce:oarse barite. . . . . . 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

retardation may have to be offset by accelerators.Concentration and/or combination with other fluid loss

materials may have to be adjusted accordingly. For mostcement squeezing and gas leakage applications, 50-150 mlfluid loss cements (30 minutes at 1,000 psi) are used.Bentonite and CMHEC are also used to reduce filtrateloss.

Fluid loss vs. gas leakage. Under certain conditionsassociated with gas sand cementing, formation gas canmove through the pipe/borehole annulus as the cementsets. This leakage can pressure-up the annuli betweencasing strings or between pipe and formation; it can causefailure of liner laps, even blowout of surface pipe.69

Such gas entry into the cement column occurs70 whena column-supporting seal forms in the slurry in the an-nulus above the gas zone, and water from the slurryseeps through the mud cake into permeable formations,lowering column weight. The effective hydrostatic pres-sure may be reduced by this mechanism to less thanreservoir gas pressure.

Another mechanism for gas entry would be for thehydrostatic pressure of mud, preflushes and cement-before any water loss-to be less than reservoir pressure,but this can, of course, be avoided by proper design.

The annular seal may be caused by: Bridging fromcement dehydration; fast setting of a portion of thecement column; gelation (or a significant viscosity in-crease) of the column from slurry chemical reactions;and/or bridging due to caving or sloughing formations,or removed mud cake/cutting debris.

A most important aspect of gas leakage prevention isreduction of cement fluid (filtrate) loss. In addition,steps may be taken to ensure that the cement slurryopposite the gas sand will set up faster than other slurryin the annulus. Allowance may have to be made for thepossibility that after lengthy circulation, cement slurrytemperature may be highest some distance off bottom.71

Fluid loss in squeeze cementing. Control of cement

fluid (filtrate) loss can be important in this application.When pressure is applied, water or fluid will be forcedfrom the slurry if it is in contact with a permeablesurface free of mud cake. The solid particles becomecompacted and slurry density increases. If the cementcontains no fluid loss control agents, the cement particlesmay eventually bridge and prevent further slurry movement.

This concept was demonstrated in a core taken throughcement remaining in the borehole following the squeezeof a perforated interval.72 Density measurements showedsignficant slurry dehydration across and somew ha tabove the upper portion of the perforations, Fig. 26. Therewas no cement across lower perforations-althoughsqueeze pressure exceeded fracture pressure-as the de-hydrated neat API Class E cement had bridged-off thecasing. A low filtrate loss formulation may have pre-vented such dehydration and bridging.

Highly successful results are obtained when squeezeoperations are conducted with: Low fluid loss cement,clean completion fluids (such as salt water) and relatively

WORLD OIL 1977

"\ 0°/0

~O~ i~;~"''''''''''

...........................

...,.."" ",......

",.."..".".".

.,.,..",...",.,.,

5030 40

FLUID LOSS(ML/30 MIN., 1,000 PSI)

Fig. 25-High molecular weight, synthetic polymer greatlyreduces fluid loss. Example shows effect on API Class Ecement (after Stout and Wohl).'"

~u.~I-0.Wo..J..JW;: 9,760

TOP OFc,

w-.a PERFS.

c'" 'Cc~ ::'C[J:~ 0 BOTTOM-- -C :. . '.' OF CORE.d'.~.

--- ~ BOTTOMg g OF CEMENTn n- BOTTOM

y .J>I- OF PERFS.

--------------

9,77017 18 19 20

CEMENT DENSITY,PPG

Fig. 26-Results of a core test through cement following anattempted perforation squeeze indicates slurry dehydrated atthe top of the perforations. There was no cement in the bottomof the perforated interval (after Beach, et al)."

low final squeeze pressures. Squeeze techniques and ap-plications will be discussed in a later article.

Lost circulation. Drilling fluids or slurries are usuallylost to either natural or induced formation fractures.

These fluids may also be lost through highly permeableformations-starting at about 5 darcies for drilling fluidwith a maximum particle size of 0.002-inch (300 mesh).Cement with its larger particle size (neat cement has2.6-18% particles larger than 200 mesh) is less suscep-tible to loss in permeable formations.

The best time to treat the formation to reduce such

fracture or formation permeability-and thus increase thedownhole pressure at which circulation is lost-is duringdrilling when high concentrations of bridging materialsand various types of plugs (pills) may be utilized.73

During primary cementing, concentrations of suchmaterials must be more carefully controlled to avoidbridging the casing or liner/borehole annulus, or pluggingof downhole equipment such as bottom wiper plugs, smalldiameter storage tools and float equipment.

The subject of lost circulation during drilling is dis-cussed briefly below, in relation to cement formulations

27

220

II.. 200°

a.::::i:w 180I-w...J0J: 160:::i:0l-I-0CD 140

12020

TOP OF.-.1 CORE"

"I I..CEMENT

---- ---TYPICAL L.C.M.

FIBROUS

o 16

CONCEN1:RATION,LBSJBBL.

20

Fig. 27-Granular lost circulation material was most effectivein sealing simulated downhole fractures in lab tests (afterHoward and Scott)."

and additives that might be considered for such applica-tions. However, a complete review of the lost circulationproblem during drilling is beyond the scope of this series.Control of lost circulation during primary cementing willbe discussed in greater detail in a later article.

Types of lost circulation additives available for cementare blocky-granular materials (walnut shells, gilsonite,crushed coal, Perlite-expanded and Perlite-semi ex-panded) which form bridges; and lamellated materials(cellophane flakes) which form flake type mats.

Fibrous materials (such as nylon fibers) are effectivein drilling fluid for sealing large openings but are notnormally used in cement because of the tendency to plugsurface and downhole cementing equipment. Also, mostother fibrous materials contain organic chemicals thatcan seriously retard cement thickening time. On the basisof lab work by Howard and Scott,74 granular materialwas found best for bridging fractures (slots), Fig. 27.

Cement plug formulations may be selected on the basisof these characteristics: Quick-gelling, low density (highyield), rapid set, fluid loss (filtrate), and cement plugdrillout rate. The product also should be easy to handleand "weevil-proof."73

The following compositions are used as cement plugs(pills) :

1. Thixotropic cements. Blends of Portland cement and gyp-sum, these cements are thin while beinl{ pumped, but developgel strength quickly when pumping stops.'"' '" Field experiencehas shown that quick-gelling cements stay closer to the wellbore(within surrounding fractures, etc.) in lost circulation applica-tions. The cement also has high filtrate loss.

Note: Fluid (filtrate) loss is important when dealing with mudor slurry loss to fractured, permeable formations. Assuming thatfrac pressure exceeds reservoir pressure, high filtrate loss cements(such as untreated thixotropic or neat) can dehydrate and bridgewithin such fractures, thus blocking further fluid loss.

2. Neat or low density cements. As discussed above, neat andthixotropic cements have high filtrate loss. However, low densitycements mayor may not have high filtrate loss.

3. Mixtures with diesel-oil. Various compositions-diesel andbentonite; diesel, bentonite and cement; or diesel, bentonite and

28

polymer-can be effective when water bearing sands are present.In application, these materials are pumpable until they set up orexpand upon contact with water.

4. Gypsum cement. A quick setting hard cement for use atshallow depths, it differs from construction gypsum in that it issemi-hydrated to control pumping time. Soluble salts in mixingwater can greatly accelerate thickening time. Therefore, pumpingtime should be checked before the job, considering the water onlocation. Gypsum is considered a temporary plugginl{ material asit is water soluble after it sets up.

5. Other cementicious, high-water-loss, high-solids slurries suchas Diaseal M and barite. plugs. The latter can be formulated to21 ppg.

Bridging materials can be used in most of the above composi-tions when loss is severe.

PROPERTIES OF SET CEMENT

Cement compressive strength increases as a functionof temperature, pressure and time to an ultimate valuewhich depends on cement composition. Compressivestrength measurements are obtained on the basis of 11API pressure/temperature/time schedules, for depthsfrom 1,000-20,000 feet. A temperature gradient of 1.5° F

r

2,000

1,000

o180 200 220 240 260 280 300 320 340

CURING TEMP. of

CURING PRESS., PSI

. -- - --- - - -. ..Fig.28-Effect of curing pressure and temperature on com-pressive strength. At constant temperature, bottom, 24-hourstrength changes little above 3,000 psi. Slow set, Class Ccement, top, shows significant strength retrogression as curingtemperature increases ('curing pressures)."

WORLD OIL 1977

.18

ciw .16:...J«w00 .14Wa:

.12()« .1a:

I-.080

...J00

.06wC)a:«...J

- - - -..--10,000_ "9,000 1- K};' , , *72HR

8,000 II-I\,x 9,000 PSI

I ,{" 1,000PSI, \7,000 \ \ CLASSC

(i5\ CEMENTa..

6,000:i'I-C)z 5,000wa:I-00 4,000 /'I0..:::20 3,000()

10,0001B

(i5a.. "nnnL / A:i'I-C)ZWa:

J/I- ASTM TYPE 1000..:::2

,uuu n/ C00a::J:

Voq- AT 200°FN

0

ATMOS 2,000,,"., ,,

4,000 6,600 '8:000

per 100 feet is provided-for in each schedule. The pres-sure is 3,000 psi for all schedules except the two shal-lowest (1,000 and 2,000 feet) for which it is less.

The reason why API tests are run at 3,000 psi or lessis that compressive strength changes very little abovethat pres'Sure level, Fig: 28, bottom. However, at high tem-peratures (about 250-3000 F) pressure effect may bemore significant than those of Fig. 28. Tentativp dataindicates, at least, that actual well pressure should bemore closely simulated.

Recommended curing periods are 8, 12, 18, 24, 36, 48and 72 hours, depending on job requirements (such aswaiting-on-cement time or strength retrogression). Usu-ally, com pres'Si ve strength is very close to ultimatewithin three days. Early strength is increased withcalcium chloride, 'Sodium chloride, ammonium chlo-

ride, "minimum" water and heat. Early strength isdecreased with lignosulfonate, CMHEC and "maximum"water. Compressive strength inf orma tion is availablethrough service companies.

Strength retrogression. Four variables-composition,temperature, pressure and time-affect compressivestrength.77 However, at high temperature, cement com-positions may retrogress (lose strength) after reaching ahigh value and never attain the strength reached at lowercuring temperature; Fig. 28, top, illustrates one severeexample.

This strength retrogression is accompanied by increasedcement permeability, i.e. a neat retarded cement with0.02+ md permeability at 2900 F after three days mayhave 8+ md at 3200 F after seven days.78

Retarded cement for high temperature application,and high water content cement, seem particularly subjectto strength retrogression (Fig. 28). For cement typesused in deep and/or hot wells the phenomenon begins ataround 2600 F, and becomes severe at 2900 F. Generallycomplete strengt!1 retrogression has taken place withinseven days.78 Although remaining compressive strengthmay be adequate for many applications, addition ofsilica flour to the slurry provides a way !o maintainstrength.79

--

:~I

_0c::::J20

I

PERCENT

~ 30 SILICA

3 1 7 3230'F 260'F 290"F

CURINGTIME(DAYS)I CURINGTEMPERATURE

Fig. 29-Silica flour inhibits strength retrogression at hightemperatures as indicated for Class E cement. For example,20% silica increases the 2,000 psi, 7-day compressive strengthof neat cement to 12,000 psi, at 2900 F (after Ostroot).'.

Silica flour in high percentages inhibits strength retro-gression and produces compressive strength far in excessof neat cement, Fig. 29.79 Silica flour also reduces perme-ability of set cement; for instance, its addition to cementcured at 3500 F reduces permeability to less than0.001 md.

Maximum strength cccurs at 300-4000F when 30-50parts of silica flour are added to 100 parts of cement.80

Usually 35% silica flour is used. Silica sand ground to200 mesh reacts with cement in the same way as fineground 325 mesh silica flour. Silica sand is used whenhigh density is desired and silica flour when low densityis adequate.

Compositions containing silica sand or flour can beretarded effectively for high temperature wells.79 Class Jcement does not require silica flour and can be used toabout 16,000 feet without retarder-this class should notbe used at less than 2300 F.

Most nonreactive additives (salt, weight materials,crushed coal, mica and other bulking agents) can beadmixed with a silica stabilized cement without adverselyaffecting temperature stability.80 Bentonites, diatomace-ous earth and expanded perlite should not be added toPortland cement for use above about 2500 F in concen-

5 10 15 0

EFFECTIVE CONFINING PRESSURE, 1,000 PSI- --- -

Fig.30-Under confining pressure, ultimate strength of cement, left, is similar to that of typical reservoir rocks, right (afterHandin).81

WORLD OIL 1977

---I

10

29

I-II 50

I

I(j) 400..00q

'XI-(!JZWa:

}j) 20wI-«

5 10;:!

trations of 5-15% without adding about 20% extra silica.Natural pozzolans and fly ashes produce a strong mate-

rial with silica stabilized cements up to 450° F. At atemperature of 600° F, fly ash and-to a lesser degree-natural pozzolans, cause cement to weaken and becomemore permeable.80

Strength at downhole conditions. Handin conductedtriaxial compression tests on various cement samples withindependently applied external confining pressures andinternal pore pressure such as encountered downhole.81These tests show that strength increases, Fig. 30, and ismore or less comparable to rock for similar conditions.

Large variations in the standard compressive strength,as measured at zero confining pressure, tend to disappearunder load; and oil well cements become very duc-tile, even under low confining pressures. However, forrapidly applied strain associated with gun perforating,ductility might be small.

Cement can be highly compactible under confiningloads, Fig. 31. Bulk volume reduction (of lab 'Samples) of30% or more are attainable for some formulations. Neatcement shows least compactability.

Expansion. Saturated salt cement, Pozzolan cement,Gypsum-Portland blends and several other formulations,some proprietary, expand during setting.82-85 Suggestedas a benefit of this expansion, is elimination of the micro-annulus at the cement/casing interface.

Cement expansion may increase thickness of a cementsheath by a few thousands of an inch. However, cementexpansion and/or contraction would appear to be ofminor importance, relative to the magnitude of otherdownhole effects such as: Inadequate mud displacement;mud cake thickness; borehole elastic/plastic deformation,and cement loading conditions, ductility and compact-ability.

SPECIAL CEMENTS

Unique cements and additives are available for non-conventional or extreme service applications such as hightemperatures found in geothermal wells and other ther-mal projects, and low temperatures in Arctic permafrost.

301 CLASS A, 100% DIAMIX A, 30% BENTONITE,

7.5% NASILICATE2 INcaR, 8% GEL

2 3 CLASS A, 40% DlACEL D, 4.0% CAC"4 CLASS A, MODIFIED 12% GEL5 CLASS A, NEAT

(SAMPLES CURED AT 3,000 PSI, 200°FEXCEPT 1,3 AT 110°F)

?J?

u.iC)z« 20J:ow:2:::J...Jo>~ 10...J:::JIJJ

7,500 PSI EFF.CONFINING PRESS.

.o

2,000 4,000 6,000 8,000

COMPRESSIVE STRENGTH, PSI

Fig. 31-Compactibility of cement samples under confiningpressures. Bulk volume reduction is significant except for neatcement. At higher confining loads, 15,000 psi, certain othercompositions had over 30% volume reduction (after Handin)..'

30

Salt cement is now used fairly extensively; some impor-tant characteristics of salt cement are shown in Fig. 32and the accompanying table.66, 86,87,88

Characteristics of salt cement. Osmotic pressurewill causewater from sand or shale to migrate to the saltcementcausingexpansion which improves bond log..'

. Theoretically less disruptive to swelling and non-swelling clays, thereby minimizescleavage, softening or sloughing of shale beds.

. Clay dispersion is minimized to aid well productivity should cement filtrate loss be signifi-cant. However, original mud cake normally prevents such filtrate loss.

. Salt is an accelerator in low concentrations and it retards at high concentrations, buttheeffect is neutral throughout a broad range in between, Fig. 32. This tolerance can, inmany cases, permit use of either fresh or seawater for mixing without affecting thick-ening time.

. Salt in small concentrations tends to increase early compressive strength, Fig. 32, buthas little or no effect on ultimate strength. In high concentrations, it reduces earlystrength and can cut ultimate strength in half.

. Saturated cements minimize solution of formation salt sections.

. Can increase slurry weight by as much as 1.7ppg.

. Inthe3-5% range, reduces turbulence-critical-flow velocity through dispersion and re-duced viscous properties. At higher concentrations, over 18%, this effect is minor andtypical dispersants may not be effective.

High temperature cements are now required for condi-tions which extend beyond the upper (in-situ combustionand some geothermal steam) effective limits of basicPortland cement.

The upper limit for silica-Portland cements is around700° F. This cement has application in deep, hot wellsand many thermal recovery and geothermal wells.89

Calcium aluminate cement (Ciment Fondu or Lumnite)has been used in in-situ combustion wells where temper-atures may reach 2,000° F. Calcium aluminate cementis manufactured from limestone and bauxite ores. Neatcalcium aluminate cement has high heat of reaction andattains almost full compressive strength of some 12,000psi in 24 hours. Admixes are fire brick, fly ash and silicaflour. This cement is used as a mortar for fire boxes.

In Arctic permafrost, permanently frozen subsurfaceformation, the surface temperature is so cold that under-lying formations do not reach 32° F for several hundredfeet. Permafrost is some 300 feet thick in the Mackenzie

River Delta, about 2,000 feet on the North Slope.Cementing conductor pipe and surface pipe in perma-

frost presents a special problem because neat Portlandcement will not set up and provide strength before itfreezes.66 This problem is overcome in hard rock areasby heating the hole with warm drilling mud, then cement-ing with heated cement and mix water. The heatingdelays freezing of the cement until after it has set up.

This method cannot be used through unconsolidatedformations held together by ice because the hole willenlarge and create a void between cement and formation.

Loose permafrost is cemented with either: Calciumaluminate cement/fly ash mixture or Gypsum-Portlandcement blend. These mixtures will set up and providemore than 500 psi compressive strength in 24 hours. Atpresent, the latter is in greater use.

Gypsum-Portland cement blends90-92 are availablethrough several service companies. These blends containdispersant, retarder and enough salt to depress the freez-ing point to about 20° F. The slurries will set up at15-20° F, have a low heat of hydration, no free waterseparation and they are stable under freeze-thaw cycling.

The cement will develop about 500 psi compressivestrength in 1-3 days and have 1,000-2,000 psi compres-sive strength in 7-28 days. The early strength comes from

WORLD OIL 1977

the gypsum, later strength from the Portland cement.Cementing operations at Prudhoe Bay have been dis-

cussed in the literature.93 And API has established Arctic

cementing testing procedures including freeze-thawcycles.61, 94

Other special cements and additives available for non-

conventional appliCations include: The Trinity Lite-Wateand Texas Industries Light Weight cements mentionedearlier, pozzolanic-lime cements, gypsum cement, latexcement, resin cement and cement containing nylon fibersfor reinforcement.95 Information is available through theservice companies.

Radioactive tracers are sometimes used in cement for

location purposes following primary cementing or squeez-ing. Also, additives such as defoamers and those which

offset the retarding effect of mud contamination, areavailable.

Critical cement iobs for difficult wells should be plannedin detail and the slurry must be carefully designed. Dueto the large number of possible combinations of cementtypes and additives, variable operating conditions, varia-tions in manufacture, inconsistent field water character-istics, etc., the only way to verify thickening time forcritical jobs is to test the planned slurry at anticipatedactual pressure/temperature conditions.

The test mixture should use water from the location.And after preliminary design work is complete, the spe-cially compounded cement should be blended at the bulkstations at least a day prior to use, to allow time for asample to be lab tested.

Coming next month: The displacement process duringprimary cementing: Flow theory; fluid behavior; whatcauses channeling; how to improve mud displacement.

ACKNOWLEDGMENTThe authors wish to acknowledge the contribution of Mr. Kerr Godfrey of

Atlantic Richfield Co. who provided valuable information and data includedin this article.

LITERATURE CITED.. Ludwig N. C., "Chemistry of Portland Cement Used in Oil Wells,"

Oil-Well Cementing Practices in the United States, API, 1959, pp. 27-37... "API Specification for Oil-Well Cements and Cement Additives," API

Sp,ec lOA, 18th Edition, Jan. 1974... 'API Recommended Practice for Testing Oil-Well Cements and Cement

Additives," API RP lOB, 19th Edition, Jan. 1974... Smith, D. K., "Cementing," SPE Monograj>h Series, Vol. 4, SPE of

AlME, 6200 N. Expressway, Dallas, Texas 75206."Bearden W. G., "Effect of Temperature and Pressure on Ph

'Jsical Proper-ties of CemenU," Oil-Well Cementing Practices in the Unite States, API,1959, Pl'. 49-59.

.. Anon., "Applied Engineered Cementing," Manual, Byron Jackson Inc.,Vol. 1.

.. Morgan, B. E. and Dumbould, G. K., "Recent Developments in the Useof Bentonite Cement," API Drilling and Production Practice, 1953, pp.163-176.

.. Godfrey, W. K., Atlantic Richfield Co., Persocnal communication, 1977."McLean, R. H., Manry, C. W. and Whitaker, W. W., "Displacement

Mechanic. in Primary Cementing," Journal of Petroleum Technology,Feb. 1967, 251-260.

.8 Stout, C. M. and Wahl, W. W., "A New Organic Fluid-Loss-ControlAdditive for Oilwell Cements," Journal of Petroleum Technology, Sept.1960.

.. Stone, W. H. and Christian, W. W., "The Inability of Unset Cement toControl Formation Pre.sure," Paper SPE 4783, Presented at the AIMESymposium on Formation Damage Control, New Orleans, La., Feb. 7-8,1974.

10Carter... G. and Slaglel K., "A Study of Completion Practices to MinimizeGas '-'Ommunication,' Paper SPE 3164, Presented at Central PlainsRegional Meeting, Amarillo, Texas, Nov. 16-17, 1970.

71Holmes, C. S. and Swift, S. C., "Calculation of Circulating Mud Tem-l'eratures," Journal of Petroleum Technology, June 1970, Pl'. 670-674.

"Beach, H. J., O'Brien, T. B. and Goins, Jr., W. C., "The Role ofFiltration in Cement Squeezing," API Drilling and Production Practice,19&1,pp. 27-35.

"Messenger, J. U., "How to Combat Lost Circulation," Oil and GasJournal, Three Part'Series, May 13, 20, 27, 1968.

"Howard, G. C. and Scott, Jr., P. P., "An Analysis and The Control ofLost Circulation," Transactions of AIME. Vol. 192, 19.'H, Pl'. 171-182.

WORLD OIL 1977

Fig. 32-Effect of sodium chloride (salt) on cement properties.Small concentrations shorten thickening time, bottom, andthere is a broad range where the effect is minimal before saltretards set-up. Early compressive strength is increased bysmall salt concentrations, top. Data taken from tests of re-tarded oil well cement (after Ludwig)."

"Spangle, L. B. and Calvert, D. G., "Improved Primary and RemedialCementmg with Thixotropic Cement Systems," Paper SPE 3833, Presentedat Rocky Mountain ReglOnal Meeting, Denver, Colo., April 10-12, 1972.

"Clement, C'~A"A Scientific Approach to the Usage or Thixotropic Cements,"Paper SPE bUll, Presented at the 51st Annual Fall Meeting, New Orleans,La., Oct. 3-6, 1976.

1TMid-Continent District Study Committee on Cementing Practices andTesting of Oil-WeII Cements, "Effects of High Pressures and Temperatureon Strength of Oil-We II Cements," API Drilling and Production Practices,1954, Pl'. 72-81.

18Carter, G. and Smith, D., "Properties of Cementing Com~ositions atElevated Temperatures and Pressure," Transactions of AIME, Vol. 213,1958, Pl'. 20..27.

TOOstroot, G. W. and Walker, W. A., "Improved Compositions for Cement-ing Wells with Extreme Temperatures," Journal of Petroleum Technology,March 1961, pp. 277-284.

so Eilers, L. H. and Root, R. L., "Long-Term Effects of High Temperatureon Strength Retrogression of Cements," Paper SPE 5028, Presented at49th Annual FaII Meeting, Houston, Oct. 6-9, 1974.

81Handin, J., "Strength of Oil WeII Cements at Downhole Pressure-Temper-ature Conditions," Journal of Petroleum Technology, Dec. 1965, pp.341.347.

.. Carter, L. G., Wag~oner, H. F. and George, C., "Expanding. Cementsfor Primary Cementmg," Journal of Petroleum Technology, May 1966.

.3 Root, R. L. and Calvert, D. G., "The Real Story of Cement Expansion,"Paper SPE 3346, Presented at Rocky Mountain Regional Meeting, Billings,Mont., June 2-4, 1971.

fWBeirute, R't "Expansive and Shrinkage Characteristics of Cements UnderActual Well Conditions," Journal of Petroleum Technology, Aug. 1973'.

55Beirute) R., "True Expansive Characteristics of Commercially AvailableExpansIve Cement Under Actual Well Conditions," Paper SPE 6013,Presented at 51st Annual FaII Meeting, New Orleans, La., Oct. 3-6, 1976.

.. Slagle, K. A. and Smith, D. K., "Salt Cement for Shale and BentoniteSands," Journal of Petroleum Technology, 1963.

81Cunmngham, W. C. and Smith, D. K., "Effect of Salt Cement Filtrateon Subsurface Formations," Journal of Petroleum Technology, March 1008.

88Ludwig, N. C., "Effects of Sodium Chloride on Setting Properties ofOil-Well Cement.," API Drilling and Production Practice, 1951, pp. 20-27.

.. Ostroot, G. W., and Shryock, Jr., S., "Cementing Geothermal Wells,"Paper SPE 904, Presented at The 39th Annual Meeting, Houston, Oct.11-14, 1964.

90Cunningham, W. C., Fehrenbach, J. R. and Maier, L. F., "ArcticCements and Cementing," The Journal of Canadian Petroleum Technology,1972.

91Maier, L. F., Carter, M. A., Cunningham, W. C. and Bosley, T. G.,"Cementing Materials for Cold Environments," Journal of PetroleumTechnologYJ Oct. 1971.

.. Kljucefl. N. ¥"J Telford, A. S. and Bombardieri, C. C., "Gypsum-CementBlend \'Yorks \'Yell in Permafrost Areas," World Oil, March 1973.

93Anon., "How BP Alaska Cements Through Permafrost," Petroleum Engi-neer, April 1973.

H Anon., "Cement Blends Can Be Tested for Arctic Environments." Petro-leum Engineer, Feb. 1977.

.. Carter, L. G., Slagle, K. A. and Smith D. K., "Stress CapabilitiesI':'1J>roved by Resilient Cement," API Drilling and Production Practices,1968, Pl'. 29-37. .

31

7

:z:6l-

e!)ZWa::....: 5I-CI)Cl)Do

'0Doo::2:0 40":U

3Va:: CURINGJ: TEMP.'<t"'"

2100 200 300

SALTCONC., 1,000 PPM

6

5CONSISTOMETER

DEPTHSena:: 4J:ui::a: 3i=

2U:i:I-

1

0100 200 300

SALTCONC., 1,000 PPM

Cementing oil and gas wells

Part 4-Practical interpretation of

rheology, annular displacing forces.

How to avoid bypassing mud during

primary cementing

George O. Suman, Jr., President, and Richard C.Ellis, Project Engineer, Completion Technology Co.,Houston

1O-second summaryBasic principles of mud and cement slurry behavior in

the annulus, as mud is being displaced, are explained.Fluid design factors and guidelines for improving the dis-placement process to prevent mud channeling are given.

A COMMONCAUSEof failure in primary cementing is in-complete displacement of drilling muds, which can leavevertical, mud filled channels in the cement. This mudmay be displaced later under producing conditions tocreate open channels that permi t formation fluidsto migrate vertically behind the casing. Even with gooddisplacement procedures, some residual mud pockets likelywill remain in irregularities in the borehole.

The displacement process and key factors for improv-ing displacement efficiency are described in this article.

FLOW, DISPLACEMENT PRINCIPLES

Two basic forces associated with drilling mud displace-ment during primary cementing are: Differential pres-sure, and cement-on-mud (fluid-on-fluid) drag forces.96To effectively displace muds, oil well cements mustexert a combination of differential pressure and dragforces of sufficient magnitude to overcome forces resistingdisplacement.

These resisting forces are pressure, and casing-mud orborehole-mud (solid-on-fluid) drag forces, Fig. 33.96, 91The resisting pressure is related to properties of the mud,i.e., density and gel strength. The resisting drag forcesare some function of mud gel strength and viscosity anddistance between casing and borehole wall.

Drilling mud and cement slurry fluid properties varyin the well bore due to lack of uniform makeup and tem-perature/pressure effects. Annular flow area also variesas a result of decentralized casing, washouts, filter cakethickness changes, directional changes, formation swelling,etc.

For most muds and cement slurries, effective viscosity(a measure of a fluid's resistance to flow) decreases asflow velocity increases.98 And with constant displacement

32

DRAG FORCE FROMCASING MOVEMENT (POS.) CASING

ECCENTRIC ANNULUS

PRESSURE DUETO MUD COLUMN

WEIGHT (NEG.)

DRAG FORCE, CEMENTON MUD (POS.)

BY-PASSED MUDCHANNEL

CEMENT SLURRY

DRAG FORCE, MUDON WALL (NEG.)

DIFFERENTIAL PRESS.MOVING CEMENT ALSO ACTS

ON MUD (POS.)

BUOYANCY EFFECTOF DENSER CEMENT

(pOS.)

Fig. 33-Various forces acting to displace, and resist displace-ment, of a by-passed vertical mud column during primarycementing .,

ena.

FLOW REGIMES

TURBULENT

~'%JRANSITION

ZONEenenwa:I-ena:«w::J:en ISLOPE IS CONSTANT

- '\ .LAMINARenenwa:a.

~ INTER~.EPT AT ORIGIN

FLOW, BPM (SHEAR RATE)

Fig. 34-Newtonian fluid flow starts when pressure is applied.Flow regime and velocity profile inside pipe are shown insmall drawings.

rate, flow velocity changes with variations in flow area.Such velocity changes have significant and complexeffects on pressure required to maintain flow in thesefluid systems.

Newtonian, non-Newtonian flow. The character offlowing fluid is described by the relationship between flowrate (shear rate) and pressure (shear stress), that caused

WORLD OIL 1977

FLOW REGIMES

TURBULENT

~enC/)WII:I-C/)II:«wJ:~enD..

uiC/)WII:D..

TRANSITION

LAMINAR-TRANSITION

FLOW BEGINS (G~L STR,ENGTH! NO FLOW

FLOW, BPM (SHEAR RATE)

Fig. 35-Non-Newtonian fluids exhibit resistance to flow whenpressure is applied. Velocity profiles of various types of floware shown.

SPRING FACTOR, N = 1DENSITY = 12.2 PPG SLOPE PROPORTIONAL

TO PLASTIC VISCOSITYf/) 30CJzisi5 :II: 20...J«is

Oil

Fig. 36-Example use of Fann V-G meter to calculate plasticviscosity (/lp) and yield point (t,) for Bingham Plastic Modelequations. For data shown, /lp = 600 rpm reading - 300 rpmreading = 30 - 25 = 5 cpo And t, = 300 rpm reading - /lp = 25- 5 = 20 Ibs.l100 ft.'

the movement. There are two basic fluid types, New-tonian and non-Newtonian. Newtonian fluids, such aswater, exhibit a straight-line relationship between flowrate (shear rate) and pressure (shear stress) while thefluid is in laminar flow. A Newtonian fluid begins to flowwhen pressure is applied. As pressure increases, flowvelocity increases, from laminar, through a transition zone(part laminar and part turbulent), to fully developedturbulent, Fig. 34.

Non-Newtonian fluids are more complex; they mayexhibit resistance to flow (gel strength) when pressureis applied. Fluids with gel strength can flow at very lowrates in a solid or plug-like manner.OO Non-Newtonian

fluids thus can have three flow regimes-plug, laminarand turbulent-with transition zones between each, Fig.35.

Drilling muds and oil well cement slurries are non-Newtonian. Extensive study has developed mathematicalmodels that can be used to predict flow properties andpressure-velocity relationships of such muds and cements.The Bingham Plastic Model and the Power Law Modelare most commonly used. The former has been utilizedfor drilling fluid anaysis since the mid-1940s.100 Power

WORLD OIL 1977

Law Model equations-presented in the late 1950s_101are generally considered to be more accurate than thoseof the Bingham model.

A recently proposed yield-pseudoplastic model thattheoretically improved the above, is not widely used.102

Such models attempt to describe the relationship ofshear rate and shear stress for muds and slurries. Ex-

tremely useful in analyzing the displacement process,they are not precise techniques.

They should be used to determine flow regime andpressure requirements for displacement. But, resultsshould be interpreted as more qualitative than quantita-tive. That is, if the analysis indicates a potential displace-ment problem, believe it. If it shows acceptable displace-ment conditions, do all that can be done to enhance thedispacement process anyway.

Fluid property measurement. The Fann V-G (vis-cosity-gel) meter is used to measure plastic viscosity,yield point and gel strength of mud, and cement slur-ries.103 Field models have two speeds, to develop shearrate at 300 and 600 rpm; lab models have six speeds: 3,6, 100, 200, 300 and 600 rpm. The lab model canmeasure properties over a range of speeds. However,the two speeds of the field instrument are enough tomeasure plastic viscosity (p.p) . and yield point (ty) usedfor pressure drop and flow regime determination withthe Bingham model, as in Fig. 36.100

The Power Law Model requires two different fluidproperty descriptions. Consistency index (K') and flowbehavior index (n') are also determined from the FannV-G meter readings. Fann dial readings and rotationalspeeds are converted to shear stress in lbs./sq. ft. andshear rate in sec.-I, respectively.

These data then are plotted on log paper and (n') isthe slope of the line through the converted readings at600 and 300 rpm and (K') is the intercept of the extra-polated straight line at unity rate of shear, Fig. 37. De-tails on operation of the Fann V-G meter are availableelsewhere.103 104

Flow analysis calculations. Basic equations for flowanalysis of Newtonian and Bingham/Power Law modelsof non-Newtonian fluids, and relevant nomenclature, are

10

t:61C/).....(Jj!XId.

~.1iW 'II:I-C/)II:«WJ:f/)

SPRING FACTOR, N = 1DENSITY= 12.2PPG (\'

S\.O~::::::::J. FANNV-GMETERSHEAR DIAL SHEAR

RPM RATE READING STRESS

K' 600 1022 30 0.3300 511 25 0.25200 341 23 0.23100 170 19 0.19

6 10 10 .013 5 8 .008

~___~I~ I I 11,,1111 , I I I 111_1110 100 1000

SHEAR RATE (SEC.-')

.011.1

Fig. 37-Example use of Fann V-G meter, with readings andspeed, to calculate flow behavior index (K') and fluid consis-tency index (n') for use in Power Law Model Equations. Fordata shown: n' = 3.32 (Iog,o 600 rpm read.l300 rpm read.) =3.32 X log,o30/25 = 0.26288. And K' = N (300 rpm read.)1.066/100 (511)"'= 1 X 25 X 1.066/100 X 511° 288= 0.05173.

33

RPM DIALREAD.

600 30300 25200 23100 19

6 103 8

I600

Summary of flow equations for fluids in casing/wellbore annulus

Newtonian fluids Power Law Model

Non-Newtonian fluids

Bingham Plastic Model

V = 17.15 Q/(DhZ-DpZ), Q = V (DhZ-DpZ)/17.15 For all fluids and models

V. = 1.62 I1P+ 1.62 [I1pZ + 8.2 (Dh-Dp)Z typ)I/Z(Db-Dp) p

PI = I1pVL/1,500(Dh-Dp)2 + ty L/225 (Db-Dp).Where: V < V.

P, = f L VZp/25.6 (Db-Dp), Where V ~ V.

NR. = 2,965 (Dh-Dp) V p/l10

PI = 11VL/1,5OO (Db-Dp)Z,Where: V < V.

Pt = fLVZpj25.6 (Db-Do). Where: V ~ V.

NR. = 928 (Db-Do) V pill

*Y. = [NR.' K'96-'/1.86 (Db-Do)-' p]1/(Z-n')

P = 0.039 L p V2f'/(Dh-Dp)

*Power Law Model V. calculations frequently assume NR.' = 3,000.Since NR.' for critical flow varies as a function of n', the following values are sometimes used (Source Fig. 39):

Nomenclature for flow equationsDb=Ho)e diameter, in.

.Dp= Casing OD, in.f = Friction factor (Bingham-Newtonian, Fig. 38)f' = Friction factor (Power Law, Fig. 39)

K' = Consistency index (Fig. 37)L = Length, ft.p.= Viscosity, cp

p.p= Plastic viscosity, cp (Fig. 36)n'= Flow behavior index (Fi~. 37)

Nn. = Modified Reynolds Number (Bingham and Newtonian)Nne' = Modified Reynolds Number (Power Law)

P = Pressure drop, psiP1= Pressure drop, laminar flow, psiPt = Pressure drop, turbulent flow, psiQ = Pumping rate, bpmp = Density, ppgt7= Yield point, Ibs./l00 {t.' (Fig. 36)V = Velocity of fluid in annulus, ft./sec.

V. = Critical velocity, min. for full turbo flow, ft./sec.

shown in accompanying tables. These equations can beused to calculate pressure drop, critical flow rates andto determine flow regimes.105

Complete pressure drop and flow analysis calculations,even with electronic calculators, are tedious but accept-able results can be obtained. Computer facilities in mostservice companies, and many operating companies, havemade more detailed flow analyses practical. For example,variations of flow area due to borehole irregularities, andpresence of more than one type of fluid can be easilyconsidered. However, with computerized analyses, theanalytical procedure, the type of mathematical model

Example flow calculation results

Hand calculated for 12 bpm flow over 1,000 ft. in two different annuli, usingfluid data from Figs. 36 and 37.*

*11= 5 cp; ty = 20 Ibs./100 ft.z; p = 12.2 ppg; n' = 0.26288; k' = 0.0517258.**5~" casing in 7U" and 8~" wellbores.tReynolds Number = 3,000.ttReynolds Number = 4,000, selected from Fig. 39.

~Note close correlation of hand calculations to service company computercalculated results shown in text.

34

used and input data should be comple~ely understood, toavoid misleading results.

Shown below are some example computer calculations,by various service companies, of critical velocity (Vc)of fluid, described by Fann V-G readings from Fig. 36and 37. Note that they correspond closely to similar datacalculated by hand, as shown in the accompanying table.

Service Co. Critical velocity in two differentannuli, ft./sec.

5Y2" x 7%," 5Y2" x 8Y2"5.2 5.0 ft./Sec.5.62* 5.46*5.31 5.146.60* 6.37*

BJ HughesDowellHalliburtonWestern

'*Computer output presents critical pump rate. For com-parison, these data have been converted to criticalvelocity.

Flow regimes, pressure drop determinations. Plug,laminar, turbulent flow and transition zones for any non-Newtonian fluid are functions of velocity and fluid prop-erties. Mathematical determinations of veloci~y at whichturbulence is fully established have been based on someform of Reynolds Number for both models. In the Bing-ham model, 3,000 was used to derive critical velocity-the minimum velocity that will maintain full developedturbulent flow.

In the Power Law Model, Reynold's Number hasvaried; 2,100 and 3,000 have been used although thelatter is more generally accepted. More than one or-ganization prefers to use a sliding value based on flowbehavior index, n', Fig. 39.

Pressure drop determinations with Power Law equa-tions or the Bingham model for turbulent flow use frictionfactors taken from a Stanton-type diagram. The Modi-fied Reynolds Number (Bingham model) is calculatedand used to find friction factor (f) as shown in Fig.38.106 The Modified Reynolds Number (Power LawModel) is used to find friction factor (f'), Fig. 39101

Displacement pressure. A non-Newtonian fluid ineither turbulent or plug flow has a flatter velocity profile,across the area of flow, than when it is in laminar flow.Thus, cement in turbulent or plug flow will exert a more

WORLD OIL 1977

n' NRe/ n' NRe' n' NRe'

0.2 4,800 0.5 3,500 0.8 3,2000.3 3,500 0.6 3,500 0.9 3,1000.4 3,500 0.7 3.400 1.0+ 2,900

Function Bingham Plastic Model Power Law Model5 X 7U** 5 X 8** 5 X 7U 5 X 8

V 6.48 4.9 6.48 4.9V. 6.23 6.17 5.29

5.11+40'" .

6,25 t 6.03 tPI N.A. ...... ......P, 56.5 N.A.

23"Piii,340

34.5Na. N.A.

'2,789'NRe' ...... ...... 4,262

.02

a: .01o .008....~ .006

u. .004ICLMN INTERNALFLUSH~ .003 TUBULARS~ .002a:u.

.0012,000 10,000 100,000 1,000,000

REYNOLDS NUMBER, NREFROM BINGHAM PLASTIC OR NEWTONIAN EQUATIONS

Fig. 3S-Friction factors for use in Bingham Plastic Model orNewtonian fluid equation, see table. Example use: For calcu-lated N". of 111,340, read f = 0.0067 (after Ormsby).'"

0.0011,000 4,000 10,000 20,000 40,000 100,000

REYNOLDS NUMBER, NRE'(FROM POWER LAW MODEL EQUATION)

Fig. 39-Friction factor, f', for use in Power law Model equa-tions. Note that NRC'for critical velocity varies with n'. Exampleuse: For n' = 0.26288, derived from Fig. 37, and calculatedNRc'= 4,262, read f' = 0.0041 (after Dodge et al).'o'

>-....o 1.29 100%STANDOFF~ 1.0 (CENTERED)ci 0.8>~ 0.6

~ 0.4I I I 33'13'/.>-....oo-'w>

W:~HOLE 10(1)

~SING 00 (2)wO,MIN. STANDOFF

6" CASING IN 9" BOREHOLEFLUID DENSITY= 10 PPGPLAST. VISC. = 10 CPYIELD STR. = 10 LB.l100 FT.'

Fig. 40-How decentralization affects velocity on the narrowside of the annulus in relation to over-all rate of flow for oneset of fluid and hole conditions. Example use: With 50%standoff, fluid in narrow side will not move before averageflow exceeds 10 bpm; above 20 bpm, it is never more than60% of total flow rate. Standoff % = 100 Wn/radius (1)-radius (2). (after McLean et al)."

uniform displacing force against the mud in the casing-wellbore annulus. In laminar flow, cement has a para-bolic velocity profile across the area of flow and it islikely to "telescope" through the mud, leaving bypassedchannels.

Knowing displacement pressure and flow rate that willkeep a slurry in turbulent or plug flow in the annulus isessential for primary cement job design. Physical limitsof pumping equipment and well bore formation strengthalso have to be considered to determine what flow regimecan be established and maintained. These will be dis-

WORLD OIL 1977

cussed later in this article.

Drag force is the other basic mechanism that displacesmud from the casing-wellbore annulus. Drag forces thataid in displacement exist between mud and cement atthe fluid-to-fluid interface or contact plane. Displacementdrag forces increase with increasing velocity of cementat the contact plane and with increasing pressure betweenmud and cement. These forces develop after a portionof mud has been bypassed and a cement-mud contactplane exists, in alignment with the direction of flow.

Resisting drag' forces exist at contact planes betweenmud and borehole wall and between mud and casing.When casing is not centered, resisting drag force effectswill not be uniform across the annular flow area. Thisdifference increases with decentralization and increases

the likelihood of bypassing mud on the narrow side ofthe annulus. An indicator of the degree of decentraliza-tion is percent standoff, and investigations have shownthat standoff increases the velocity required to initiatemud flow from the narrow side of the annulus, Fig. 40.96

Resisting drag forces have an effect on displacementefficiency that is also proportional to mud gel strength,i.e. higher gel strength increases differential resistance toflow across a non-concentric annular area.

Under conditions that contribute to mud bypassing inan eccentric annulus, drag forces at the cement-mud in-terface should cause erosion of the bypassed mud. Thiserosion will reduce the area of contact between mud and

casing and mud and borehole. If cement-on-mud dragforces are high enough to cause mud erosion, and contacttime is long enough, complete mud removal should beachieved. However, those conditions are most likely toexist when cement has adequate "contact time," with ahigh velocity difference between cement and mud -achieved only with cement in turbulent flow.lo7 Contacttime is defined as the period during which a position inthe annulus (generally above the zone of interest) re-mains in contact with a cement slurry that is in turbulentflow, Fig. 41.

The resisting drag force between mud and casing can

BOREHOLE

NEAT TAilSLURRY

..."1

TOP PLUG

.'~',"

CASING

TURBULENT

lEAD SLURRY

TIME, T1 TIME, T2

Fig. 41-Mud displacement is improved by additional contacttime, the period during which a point, A, is in contact withslurry in turbulent flow. Contact time in minutes = T, - T,= VT/235.6Q; VT = Volume of slurry in turbulent flow, Q = dis-placement rate, gal./min. (after Brice et al).'07

35

"- 0.01' ... --- --- n'

g5 0.008b 0.006

z 0.0040i= 0.003()

if 0.002

be altered to a positive mud displacing force by rotatingthe casing while displacing cement.96 This positive effectis illustrated in Fig. 42. Reciprocation-moving casingup and down-exerts a somewhat less-positive displacingdrag force. However, reciprocation also affects velocity ofcement and mud, as will be discussed later.

HOW TO IMPROVE MUD DISPLACEMENT

It is necessary to operate within limiting conditions ofthe borehole, and control certain variables, to developbest displacement pressure and most positive drag forcesduring primary cementing. The following is a discussionof: Conditions that limit different aspects of displacementand controllable variables in the system.

Centering pipe in the borehole creates a uniform an-nular flow area perpendicular to flow direction, and mini-mizes variation of resistive drag forces across this flowarea. This concept has been encouraged for over 30years.108

Centralizers do not provide perfect casing-borehole con-centricity. But they will subs~antially improve standoffconditions, as casing without centralizers will lie againstthe borehole wall.

Mechanical centralizers are available for nearly everypossible casing-hole size combination. However, use ofthese devices is strongly resisted-under certain condi-tions-by some drilling personnel. Generally, this resist-ance is due to a concern that they will "hang up" andprevent casing from being run to desired depth.

Unfortunately, conditions that generate greatest con-cern about centralizers-like highly deviated wells withnumerous washouts-are, many times, the very conditionsthat make their use one of the key requirements forsuccess. In some cases, centralizers can actually increasechances of getting casing down, i.e. where differentialsticking is a problem, see Part 1 of the series.

Rotating vs. reciprocal casing movement. Eithertype of pipe movement alters drag effects between mudand casing, to a positive displacement force from a re-sistive displacement force. But based on model studies/6rotation appears to be more effective than reciprocation

.in removing bypassed mud, where casing is severely offcenter. In addition to the mud-casing drag forces, thereare cement-casing drag forces that also aid displacement.During rotation, cement-casing drag forces are moreeffective than during reciprocation, as they tend to "pull"the cement into the bypassed mud column instead ofalongside it.

Rotating casing at 15-25 rpm provides more pipemovement relative to annular fluids than reciprocating20 feet on a one minute cycle. Therefore, in addition tothe more effective direction of casing related drag forces,rotation generates more total drag force during displace-ment.

Reciprocating can cause lateral casing movement, orchanges in standoff, as centralizers move across wellboreirregularities. This lateral movement alters the flow areaand encourages bypassed mud displacement.

Pressure velocity surges. Reciprocal movement alsoaffects flow rate and velocity of fluid in the annulus, Fig.43. During the upstroke, velocity in the annulus decreases,as part of the fluid pumped out of the shoe occupies thevolume previously occupied by the casing and fluid inside

36

CASING ROTATIONSTATIONARY 8TARTED

FLOWINGCEMENT

MUD ALMOSTREMOVED

Fig. 42-Rotational displacing drag force aids in removal ofby-passed mud in the narrow side of an eccentric annulus(after McLean et al).oo

-- --o 0C\I 0

""

00_....

oo

~2:..

EXAMPLE:

FOR Q = 20 BPM. 9%" CASING.

CYCLE TIME = 1.0 MIN.

ANNULAR FLOW(UPSTROKE) = 20 + 5 = 25 BPMANNULAR FLOW(DOWNSTROKE) = 20 - 5 = 15 BPM I:

10.5 1.0 1.5 2.0 2.5 3.0

CYCLE TIME FOR A 20 FT. STROKE. MINUTES--Fig. 43-Effect of reciprocal casing movementon annular flowrate. Maximum displacing rate assumes uniform acceleration,deceleration over 4 feet at each end of stroke.

the casing. On the downstroke, the casing acts like apiston, displacing fluid in the wellbore below the shoeup the annulus, along with the volume of fluid beingpumped through the shoe.

This motion creates substantial pressure and velocitysurges in the wellbore, Fig. 44,109 which improve theerosional effect of cement on bypassed mud by substan-tially increasing displacing drag forces. However, it isvery important to know the magnitude of pressure changesto avoid breaking down the formation and causing lostcirculation. This problem will be discussed later in thisarticle.

Pipe moving techniques. A power swivel should beused to rotate casing to avoid over-torquing the connec-tions; such forces should not exceed casing makeuptorque.

Thread compounds with Teflon and/or Silicone addi-tives should be avoided where high torque ranges are

WORLD OIL 1977

required for rotation. The low friction character of thesecompounds may allow over-torquing and excessive make-up that exceeds pin or collar yield strength.

Equipment is available that reciprocates and rotatescasing simultaneously. A recently published review of thismethod, compared to reciprocation alone, showed definiteimprovement in success ratio of primary cementing jobsin conventional completions with small annular clearancesin Exxon Co. development wells drilled in the Texas GulfCoast.ll0

While reciprocating, pick-up loads clearly have to beless than pipe tensile strength. And it is important to notethat casing weight variation will occur during the com-pletion operations, Fig. 45.111

The difference in indicator readings on upstroke anddownstroke is very important. This difference indicateswhether casing is moving freely or is tending to stick.While circulating and conditioning mud prior to cement-ing-with casing on bottom-the difference between up-stroke and downstroke weight decreases, Fig. 45, withimproved mud conditions, i.e. lower gel strength andplastic viscosity. Then, the indicator will reflect weightincrease from pumping heavier cement into the casing.As cement displaces mud up the annulus, there is aweight reduction, but difference in upstroke and down-stroke weight should remain fairly constant if casing ismoving freely.

Stuck pipe is indicated by an increase in thedifference on up and down strokes and not byincrease alone.

weightweight

Standoff rings. Mechanical devices can be used tominimize frictional forces between casing and wellborethat resist movement during mud conditioning and ce-menting. Centralizers that rotate on the casing also reducerotational resistance. .

Other devices that aid pipe movement are positivestandoff rings. These tools ride freely on the casing be-tween collars, and they have ODs slightly larger thancollars. Normally located above zones of interest, theserings act as bearings, reducing contact area betweencasing and formation, to substantially reduce forces re-quired to move casing in either reciprocal or rotationalmotion.

This equipment is recommended for:ated wells, where differential sticking iswhere any conditions are expected thatcasing movement difficult.

Highly devi-expected, orwould make

Scratchers. Casing centralizing and movement was de-veloped as a "package" that included use of scratchers-mechanical devices designed to remove filter cake and,theoretically, improve the surface for cement bonding,directly to the formation.

This may be the case opposite non-permeable zones,where no filter cake has formed. However, scratcherslikely remove only the outer, softer portion of the filtercake that has built up opposite permeable zones.

This should positively affect cementing, but if totalcake removal were achieved it could create lost circula-

tion or other problems related to cement dehydration.Placing scratchers opposite washouts should improve

mud displacement. Also, scratchers mechanically disturbmud gel strength and induce added turbulence.

Well bore formation pressure limits. Every borehole

WORLD OIL 1977

has limits on bottomhole pressures. The lower limit mustbe high enough to prevent entry of formation fluid andto stop formation sloughing. The upper limit must belower than pressure that would induce formation frac-tures and cause los~ circulation. Clark presented a graphicview of typical bottomhole pressure variations duringnormal drilling and completion and a theoretical bottom-hole pressure chart where formation strength was ex-ceeded.112

Review of the drilling history should help identifypressures that existed in the wellbore during drilling. Ifkicks were encountered and formation fluids entered thewell bore, minimum pressure limits should be clear. If lostcirculation occurred, upper limits may be more definite.Many other conditions can be used to define a well's"pressure window."

Fracture gradient knowledge is important in deter-mining safe slurry density and/or pump rate, and whetherstage equipment is needed. A profile showing fracturegradient vs. depth is desirable. Such a profile, to be dis-cussed in a following article, enables systematic designapproach. However, accurate fracture gradient profilesare not always available.

Indications of fracture gradient are obtained for agiven area through: The presence of lost circulationduring drilling, and records of breakdown pressures en-countered during stimula~ion and squeeze operations.

Occasionally, operators invest an extra effort to makesystematic and intentional measurement of breakdownpressure. One company obtained breakdown gradientswith drilling mud in open hole as part of the normalplugback and abandonment procedure for offshore ex-ploratory wells,11a And attempts have been made todetermine fracture gradient through log measure-ments.lla.116

Effects of pipe movement on wellbore pressure havehave been defined in the literature. 111-120There is generalagreement that accurate determination of swab-surgepressures associated with pipe movement requires con-sideration of properties of the systems at work in thewellbore. This includes fluid properties and regime de-terminations and an accurate prediction of borehole IDvariation.

Hand calculations required ~o do this accurately arecomplicated and time consuming. Therefore, computerprograms and nomographs have been used to simplifyanalysis and predict swab-surge pressures for a given setof well conditions.

Many operators and mud companies have computerprograms available for de~ermining surge pressures dueto casing running. This information is essential, to de-termine what running speed to use to stay within limits(the pressure window) of a well.

Condition mud before cementing. Reducing gelstrength and plastic viscosi~y greatly improves displace-ment efficiency, and it reduces pressures required at thecement-mud interface to displace mud. It also reducesdisplacement drag forces required to erode and removebypassed mud by reducing casing-to-mud and wellbore-to-mud resistive drag force effects described earlier.

Under certain, well defined, pressure window limits,it may be desirable to lower mud density, along with gel

37

strength and plastic viscosity, nearly to the minimumwellbore pressure limit. This would permit a largerpressure increase for displacemen~ pressures.

If this is done, pipe should only be rotated, to preventa swabbing action that may reduce pressure below thelower limit. .

In most cases, mud circulation to clean up the holeand remove cuttings from the mud should be adequateif good mud properties were maintained while drillingthe final portion of the hole.

Casing running tips. The final steps of: Making up thelast casing joint (landing joint) and the cementing head,establishing circulation and starting to move the pipe re-quires careful planning and a well coordinated effort.

With good hole stability and an accurate casing tally,it is possible to pick up the landing joint prior to taggingbottom. If possible, the cementing head should be madeup on the landing joint, otherwise it should be on the rigfloor, checked and ready for makeup.

Casing should not be stopped within 15 feet of bottomor with less than 10 feet between elevator and spider asthis is the minimum space to permit adequate weightslack-off to overcome most differential sticking tenden-CIes.

With the casing "free" it can be picked up to verifyability to reciprocate. Maximum resistance to casingmovement is experienced at this time and maximumpick-up load should be accurately defined to avoid over-stressing the pipe.

With casing 10-15 feet off bottom, final mud circula-tion should be started-slowly-while moving the casing.As circulation progresses, pressures normally decline asmud gel strength and plastic viscosity (shear stress) de-crease with slowly increasing pump rates (shear rate).

The minimum amoun~ of mud circulated prior to mix-ing cement should be the casing's volume. This verifiesthat float equipment is clear of foreign objects. It maybe desirable to circulate even longer if circulating pres-sures are abnormally high.

Mud contamination effects. The possibility of mIxmgcement and mud always exists during pumping and dis-placement. Such contamination can result in: Accel-erated or retarded thickening times, reduced cementcompressive strength, reduced bond strength (see Fig. 3,Part 1), increased filtrate loss (higher than in either mudor cement); and with oil base mud, the mixture maybecome an unpumpable mass.121-126

An API study showed that inorganic chemicals have anerratic effect on oil well cements,123.124 but generally tendto accelerate-the effect depends on concentration. Or-ganic chemicals generally retard, and may completelyinhibit cement set in some instances.

Severe thickening with oil muds occurs with cementmixing because such muds are thickened by water wetsolids that are readily available in the high solids contentcement. The small average cement particle size and largeparticle surface area contribute to the thickening prob-lem, which is most serioU's when oil base mud and cementslurry densities are high. Also, oil emulsion muds oftencontain calcium chloride in the water phase, which canaccelerate setting.

Pre-job tests at various oil mud/cement slurry ratioscan indicate extent of potential thickening problems.

38

+500

+400

MAX. PIPEVELOCITY

+300

o

-100

PIPESTOPPED~

-200 PIPE1 LIFTED

oTIME

Fig. 44-Measured pressure surges associated with picking-upand running of a single casing joint. Casing was lowere<lsmoothly after lifting. Clearly shown are the swab and surgeeffects caused by viscous drag, inertia and mud gel charac-teristics (after Burkhardt).'.'

Fig. 45-Pipe weight on indicator on upstroke and downstrokeindicates whether casing is moving freely. Changing weightreflects mud gel strength changes and density differences ascement is pumped, but difference between up and down strokeshould remain fairly constant if pipe is free (after Barkis).'''

To prevent mud/slurry problems, it is best to mini-mize contact. The bottom wiper plug prevents contami-nation in the casing, and a spacer fluid reduces cement-

WORLD OIL 1977

'0Q. GEL

+200 BREAKSa: "::::>00wa:::::>0000

M:! +100a..

CjCjF

xZz _w

Z- CONDITIONING ::!:::!:a: ZOO w0 ::::>< HOLE ()I- a:()< UPSTROKE

-' -() ,/

-'15 --------- --"

Il- IJ: ICj I DOWNSTROKEijj3:

I ECjEQUALIZATION II

TIME

1.2(!J>«-~oa:a:«~ 0.6o~ 0.4a:>I-Uo

JW>

DENSITY = 10 PPGPLAST. VISC. = 10 CP6" CSG IN 9" BOREHOLE50% STANDOFF

1.0il

0.8'

Fig. 46-Effect of fluid yield strength on velocity required toinitiate flow in narrow side of eccentric annulus, for BinghamPlastic fluid with turbulent flow through annulus, see Fig. 40(after McLean et al).'6

MUD10109.55.5

80%, 1 In.

CEMENT305013.8

PLAST. VISC. =YIELD PT. =DENSITY, PPG =DIA. HOLE, IN. =STANDOFF =

TOP ON NARROWSIDE

I I3 5

I10

I15 PUMP RATE. BPM

10 -20 30 40

FRICTION PRESSURE LOSS FOR MUD, PSI/1,OOOFT.

Fig. 47- Type of curve that can be designed for individualconditions to determine additional cement, to assure coverageof the narrow side of eccentric annulus. Multiply volume factortimes volume of annulus from shoe to desired cement columnheight. Example: At 5 bpm: To get cement to 1,000 feet abovethe shoe on the narrow side, requires 1.6 times the 1,OOO-footannulus volume. Final cement top on wide side will be 2,200feet above shoe. Note how volume factor decreases withhigher pump rates (after Graham)."

mud contact in the annulus.

Two bottom plugs may be required-one ahead, andone behind the spacer fluid-to prevent mud-cement con-tamination if: Contamination would create serious prob-lems, and the spacer fluid does not by itself strip the mudfilm from the casing bore.

A single bottom plug, ahead of the cement, will removethe film and accumulate mud ahead of the plug andbehind the spacer fluid (see Fig. 7, Part 1). This accumu-lated mud then can contaminate the cement.

A variety of spacer or preflush fluids are available, in-cluding water, brine, solutions of acid phosphates, die'Sel-oil (weighted or unweighted), oil base fluids and emul-sions (oil in water, water in oil). Compatibility of bothspacer and mud, and spacer and cement should be veri-

WORLD OIL 1977

fied on every cement job. Selection of amount and typeof spacer depends on type of mud being used and inter-reaction problems between cement and mud.

A water flush, normally in turbulent flow, may aidmud displacement efficiency. Salt water has less ten-dency-than fresh water-to cause shales to swell orslough. However, fresh water, salt water or fluids con-taining dispersing sur f act ant should not immediatelyprecede a high density cement slurry as thinning andweight material settling may occur.

DISPLACEMENT RATE, RHEOLOGY DESIGNGenerally, high displacement rates improve displace-

ment efficiency if cement can be in turbulent flow upthe annulus. Conditions that may prevent such flow in-clude: Limited displacement rate capability (pumpingequipment), a pressure window that limits displacementpressure and improper flow (rheological) properties ofmud and/or slurry.

Providing extra pumping equipment is basically aneconomic decision, if wellbore conditions can toleratehigher displacement pressures. Formation conditions thatdetermine the pressure window are fixed, and attemptsto exceed those pressure limits may create serious prob-lems.

Use of dispersants. The value of properly conditionedmud has been discussed. Fluid properties of the cementslurry can also be altered, i.e. dispersants can be addedto lower gel strength to attain turbulent flow at lowerdisplacement rates. This can be desirable where highpump rates would otherwise be required. By adding dis-persant and lowering pump rate, an increase in effectivecontact time can be realized, along with the desired ve-locity profile.

However, if turbulence can be achieved at reasonablepump rates without dispersants, the resulting displace-ment should be better, i.e. turbulent flow is better thanlaminar flow, but additional turbulence may not be"better yet."

After turbulent flow is established, displacement effi-ciency increases with increased slurry flow resistance, asdisplacing drag forces increase with increasing contactpressure at the cement-mud interface. Thus, thinningthe slurry to get "more" turbulence is not recommended.

The buoyancy effect of higher density cement slurry onlower density mud is a controversy in the litera-ture...,,,,,t28 Such effects should provide a positive dis-placing force on bypassed mud as long as there is verticalcontinuity of the mud column to the top of the risingcement-mud interface.

Contact pressure at the base of the bypassed mud-cement interface increases with increasing height of ce-ment. This should increase both displacing pressure anderosional effects due to increased contact pressure nearthe bottom of the bypassed mud column.

However, if the cement bypasses a portion of mud andthen ree'Stablishes complete displacement of the movablemud in the annulus above the bypassed mud, displacingdrag forces may be the only effective force working toremove the mud. With these conditions, it is likely thata large portion of the bypassed mud will not be removedunless turbulent cement flow is maintained. Sufficient

contact time should be provided to allow the cement-mud

39

3.0,

2.8'

2.6

2.4'

a: 2.20l-t)

2.0«u..w::E 1.8::>....J0

1.6>I-a]::Ewt)

drag forces to erode away any bypassed mud; a minimumof 10 minutes is recommended.97

How to utilize plug flow. When wellbore conditionsare such that turbulence cannot be achieved, displacingwith cement in a plug flow regime can maintain a flattervelocity profile in the annulus.127

While drag forces are not as effective as with turbu-lence, they can be maximized by increasing cement gelstrength as high as possible, particularly in the lead partof the slurry.

Also, cement density can improve plug flow displace-ment when it is maintained at least two pounds pergallon heavier than the mud.127

Centralized pipe and rotational movement may im-prove displacement efficiency. But reciprocal movementshould be avoided, as intermittently increasing cementvelocity could bypass mud.

Pumping rates should produce annular rising velocitynot greater than 90 feet per minute. Under some con-ditions this cannot be accomplished by controlling pumprate, i.e. with U-tube effect of higher density cement,and/or presence of lost circulation.

How to improve laminar flow displacement. Well-bore and/or surface conditions that prohibit turbulentflow may al'So prohibit plug flow. When these not-un-common circumstances exist, an alternative is to altercement rheological properties to increase apparent slurryviscosity.

Displacement, even in laminar flow can be effectiveif the slurry is thicker (has higher yield 'Strength andplastic viscosity) than the mud, and if sufficient volumesare used to obtain desired cement height on the narrowside of an eccentric annulus. 96,98

One guide for cement rheological design i'S to havecement yield strength exceed mud yield strength by afactor equal to maximum annulus clearance divided byminimum annulus clearance.

Even though turbulence will not be achieved, thehighest practical pump rate is recommended, as thedifference between mud and cement velocities on thewide side vs. the narrow side is reduced as rate in-

creases, Fig. 46.The cement volume used under these displacement

conditions should be such that the final height of cementon the narrow side i'S above any zones to be protected.This volume can be determined from design curves basedon specific mud and cement properties and casing-well-bore configurations (eccentricity), Fig. 47.

This data should be derived from well site measure-

ment'S of mud and cement slurry rheological propertiesand calipered hole size information. The detailed designcurve determination is available in the literature.98

Coming next month: Primary cementing techniques,proper use of downhole and surface equipment.

LITERATURE CITED... McLean, R. H., Manry, C. W. and Whitake~ W. K., "Displacement

Mechanics in Primary Cementing," JPT Vol. 1~, February 1'967.07Clark, C. R. and Carter, L. G., "Mud Displacement with Cement

Slurries," JPT, Julr. 1973... Graham, H. L., 'Rheology-Balanced Cementing Improves Primary Suc-

cess," O&GJ, December 18, 1972.

40

How to improve mud displacement duringprimary cementing

I. Center pipe in the borehole2. Move casing during mud conditioning and cementing

. Rotation is best for removing mud channels from narrowside of non-centered casing

. Reciprocation aids in achieving turbulence. Do not usewhen displacing in plug flow

. Combined rotation-reciprocation is most effective when dis-placing with turbulent flow3. Know formation pressure limits in the wellbore

. Lower limit is that required to maintain positive formationcontrol

. Upper limit is a function of the formation's strength, its re-sistance to hydraulic fracturing4. Condition mud prior to cementing5. Avoid adverse mud-cement reactions

. Use proper spacer fluids or flushes and wiper plugs6. Control displacement rates and slurry rheology

. Use high rates where turb~lence can be maintained in thewidest annular area, across interest zones

. With turbulent flow, provide adequate contact time formud removal

. When turbulence cannot be developed and maintained,consider lower rates to achieve plug flow in narrowest annularareas, across interest zones

. If neither condition can be attained, adjust cement prop-erties to achieve high yield strength and plastic viscosity, dis-place at the highest practical rate and use sufficient volume toget desired height on narrow side of eccentric annulus

00Brown, R. W., et al, "Cement Rheology-A Tool for Better Completions,"Petroleum Engineer Februa

'J1963.

.00Howard, G. c. and Clark, . B. "Factors to be Considered in Obtai'!inJ!Proper Cementing of Casing," API Drilling and Production Practice, 1948,I'p. 257-272.

... Dodge, D. W. and Metzner, A. B., "Turbulent Flow of Non-NewtonianSystems," AIChE Journal, Vol. 5, No.2, June 1959.

,., Robertson, R. E. and Stiffs, H. S., Jr. "An Imeroved MathematicalModel for Relating Shear Stress to Shear Rate in Drdling Fluids and Ce-ment Slurries," SPEJ, February 1.976.

'.3 "Standard Procedure for Testing Drilling Fluids," API RPI3B, SixthEdition, April 1976.

JOt"TestinJ! Oil Well Cements and Cement Additives," API RPI0B, Nine-teenth Edition January 1-974.

'00Ror;ers, W. F., Composition and Properties of Oil Well Drilling Fluids,Third Edition 1963 Gulf Publishing Co., Houston.

.06Ormsby, G. S., "Calculation and Control of Mud Pressures in Drillingand Completion Operations," API Drilling and Production Prac4ices, 1954,pp. 44-55.

107Brice, J. W., Jr., and Holmes, B. C., "Engineered Casi!,B. CementingPrograms Using Turbulent Flow ,Techniques," JPT, May 1964.

... Teplitz A. J. and Hassebrook, W. E., "An InvesJIgation of Oil-Well Ce-menting," API Drillinc_ and Production Practice, '\94ti, pp. 76-103.

.00Burkhardt, J. A., "WeIlbore Pressure Surges Produced by Pipe Movement,"JPT June 1961.

11.Holt "] , J. A., "Field Proven Techniques Improve Cementing Success,"Worl 0./, August 1.976.

m Barkis, B., "Primary Cementing, The Critical Period," B&W, Inc., Tech-nical Literature.

no Clarki E. H., Jr., "A Graphic View of Pressure Surges and Lost Circula-tion,' API Drilling and Production Practice 1956, pp. 424-438.m MacPherson, L. A. and Berry, L. N. "Prediction of Fracture Gradients

from Log Derived Elastic Moduli," The Log Analyst, September 1972, pp.12-19.

u'Matthews, W. R. and Kelly J., "How to Predict Formation Pressureand Fracture Gradient from Eiectnc and Sonic Logs," Oil and Gas Journal,February 20, 1967 pp. 92-106.

us EatonA B. A., "Fracture Gradient Prediction and Its Application in Oil-field uperations," j PT, October 11969pp. 1,353-1,360.

U6Taylor, D. B. an Smith, T. K., "improved Fracture Gradient Estimatesin Offshore Drilling Operations," API Drilling and Production Practice1970 pp. 41-50.

m C~well, W. T., Jr., "Pressure Changes in Drilling Wells Caused byPipe Movement," API Drilling and Production Praclices~ 1953, pp. 97:1112.

U8Schuh]

F. J., "Computer Makes Surge Pressure Calculations Useful,"O&G , August 3, 1964.

.1>Bazert D. A. and Owen, H. B., Jr.!.. "Field Application and Results ofPipe ripping Nomographs," Paper SP~ 2656, 1969.

". Fontinot, J. E. and Clark R. K., "An Improved Method for CalculatingPressures in a Drilling Weh," Paper SPE 4521', presented at Fall Meeting,Las Vegas, Nev., September 3D-October 3, 1973.

m Carney, L. L., "Cement Spacier Fluid," Paper SPE 4784, presented atFormauon Damage Symposium, New Orleans, La., February 7, 8, 1'974.

I22Morris, E. F. and Modey, H. R., "Oil Base Spacer System for Use inCementing Wells ContaimnJ! Oil Base Drilling Muds," Paper SPE 4610,presented at Fall Meeting, Las VeBas, Ne!'J September 30-0ctober 3, 1973.

.23Beirute, R. M., "All Purpose Cement-Mud Spacer," Paper SPE 5691,presented at Formation Damage Control Symposium, Houston, January29-30, 1976.

... "The Effects of Drilling-Mud Additives on Oil-Well Cements," APIBulletin D-4, Corrected Edition March 1963.

.23Anderson, F. M., "Effect of Mud-Treating Chemicals on Oil-Well Ce-ments, "O&GJ September 29, 1952.

'28,Tschirley, N. k., "Cementing in Oil Muds," Petroleum Engineer, May1975.Parker, P. N., eI al, "An Evaluation of a Primary Cementing ,TechniqueUsing Low Displacement Rates," Paper SPE 1'234, presented at Fall Meet-ing, Denver, Colo., October 3-6, 1965.

I28Garvin, T. and Slagle, K. A., "Scale Model Displacement Studies to Pre-dict Flow Behavior DurinJlt Cementing," IPT, September 1911'. .

WORLD Oil 1977

Cementing oil and gas.wells

Part 5-Guidelines for downhole

equipment use, stage cementing methods,

new concepts for cementing largediameter casing

George o. Suman, Jr., President,Ellis, Project Engineer, CompletionHouston

and Richard C.

Technology Co.,

1O-second summary

Concepts and applications of cementing equipmentused on casing strings during primary cementing areexplained along with a discussion of stage cementing,mixing and density measuring devices, and how to cementlarge diameter casing by the stab-in method.

PREVIOUSARTICLES in this series have presented thebasic principles of hole preparation, casing handling,cement slurry chemistry and additive selection-and howmud is displaced by the cement slurry.

This article will discuss downhole and surface equip-ment used in conventional primary cementing, with em-phasis on the common problem of lost circulation. Specialconsiderations for each of the casing strings-conductor,surface, intermediate and production-are reviewed andnew ideas are presented for cementing large diametercasmg.

Realizing that this subject covers a broad range ofcommercially available products and that design featuresof the equipment mentioned may vary widely amongmanufacturers, it is the intent of the authors to stress

basic concepts and applications, and general precautions.Equipment used in conventional primary cementing

normally includes a casing guide shoe, float collar, bottomand top wiper plugs, cementing head, centralizers, mixingequipment and pumps, Fig. 48.129,130,131Rotating or re-ciprocating type scratchers, multiple staging equipment,external casing packers, metal petal baskets and / or other

specialized cementing equipment are frequently required.And, resin-sand coated casing, external casing seal ringsand devices for increasing the annular velocity and/orswirling cement are sometimes applied.

TYPES OF SHOES, COLLARSIn most cases, except in certain shallow wells, a round-

nosed shoe is run on the bottom joint to guide the casing

WORLD OIL 1977

past borehole irregularities encountered while running thestring. Three types of shoes are commonly used: Guideshoes (without valves of any kind), float shoes and differ-ential or automatic fill-up types, Fig. 49.

Collars have basically the same features as shoes. Theyare commonly known as baffle collars (without valves),float collars, and differential or automatic fill-up collars,Fig. 49. Located one or more joints above the shoe, thecollar, in addition to float and fill-up functions, acts asa seat for pump-down wiper plugs. It thus indicates whencement placement is complete, and controls the amountof cement left in the casing. Since cement immediatelybelow the wiper plug may be contaminated, the collarshould be positioned to minimize the amount of con-taminated cement pumped out around the shoe.

The guide shoe or baffle collar has an open bore some-what smaller than pipe inside diameter. The float typecontains a check valve which prevents backflow of cementinto the casing after the cement job has been completed.This feature also prevents flow into the bottom of thecasing during running.

When float equipment is used, the casing rides or floatsdown to the desired depth because it is partially emptyand somewhat buoyant. When using float shoes or collars,bouyancy is controlled by the amount of fluid placedinside the casing from a surface fill-up line. The casingis normally filled at regular intervals (say every five to20 joints). Partial filling is also required to prevent col-lapse of large diameter casing.

Differential/automatic fill-up shoes and collars pro-vide partial fill-up of the casing during running, usingeither differential pressure, Fig. 49, or-for the automatictype-a predetermined-size orifice. Most single, differen-tial fill-up units (shoe or collar) keep the casing about90% full, unless the well's fluid level is low due to lostcirculation. An additional differential fill-up unit resultsin about 81 % fill-up. Of course, neither type of "auto-matic" fill-up equipment should be run in combinationwith float equipment.

Pumping fluid through some types of "automatic"fill-up units converts them to conventional float valves.In other types, a ball is pumped through the tool forconversion, Fig. 50. This type preserves the "automatic"fill-up feature if attempts are made to break circulationduring running.

Differential fill-up equipment is frequently used on long

41

strings to: Reduce surge pressures by permitting part ofthe displaced mud to enter the casing, rather than allbeing forced up the annulus; to provide continuous

PLUG CONTAINER

FLOAT COLLAR

CENTRAUZER

GUIDE SHOE PUMPING CEMENT

Fig. 48-Main equipment components of a typical primarycement job in a moderate depth well where additional acces-sories such as scratchers, stage collars, etc. are not required.

42

partial fill, thereby reducing running time, and to avoidthe hazard of casing collapse.

Some reasons for selecting float equipment withoutfill-up features are:

· The casing can be filled with well-conditioned mud,and entry of extraneous materials from the borehole isavoided, i.e. shale cavings, cuttings and LCM.

. This equipment .is somewhat simpler in operationand, possibly, more reliable.

· It gives more positive indications of wellbore fluidgains or losses; and it offers positive downhole casingshut-off if the well tries to kick.

. There is a more or less continuous and progressive"breaking" of gelled mud in the borehole.

Pressure surges causing formation fracturing and lostcirculation can be prevented by limiting casing runningspeed. Running casing at speeds which provide annularflow rates acceptable during drilling is normally safe(see Fig. 43, Part 4). Surge pressure should be calculatedto determine safe running speed where clearance betweenhole and casing is small (Part 4). Other considerations inestablishing running speed include: Presence of bridgesor key seats or doglegs; proximity of the shoe to totaldepth, and, occasionally, the number of scratchers andcentralizers.

If there is lost circulation material in the mud system,"automatic" fill-up equipment should not be used. Andif use of lost circulation material in the slurry is planned,bottom wiper plugs and float equipment-perhaps withthe exception of flapper valve types with straight-throughopenings-may have to be avoided.

As an extra precaution to supplement visual tool in-spection, fluid can be pumped through float and fill-upequipment after make-up to verify operation beforerunning to bottom.

Following cement placement-and after bumping thetop plug-the pressure normally is released. This releaseshould be rapid, to activate the check valve. If backflowis observed, pressure must be maintained until the cementsets up. However, excessive internal pressure expands thecasing and it can contract and form a micro-annuluswhen the pressure is released-after the cement sets (seePart 1).

Float, baffle and fill-up collars are normally made withequal or greater burst and collapse strength than thecasing on which they are run. For shoes, however, thesedesign criteria are not generally considered critical, ashigh burst and collapse strength is not required at thislocation in the string after drill-out.

WIPER PLUGS, CEMENTING HEADSWiper plugs are used to separate the cement from

preceding or following fluids, Fig. 51. The bottom plugalso removes mud from the wall of the casing, and pre-vents this mud from accummulating beneath the top plugand being deposited around the lower casing joints (Part1) .

After reaching bottom, the diaphragm in the bottomplug ruptures and cement is displaced out the bottom ofthe pipe and around the casing. The top plug seats on

WORLD OIL 1977

the bottom plug or float collar, after being displaced tobottom, and shuts off flow.

Cementing heads are available which hold one or moreplugs. When the two-plug system is used, the operatorshould verify that the bottom plug is, in fact, placed inthe bottom position in the cementing head. A mechanicaldevice should be used to give visual proof when the topplug leaves the head. The cementing manifold shouldbe connected so that the plug can be pumped out of thecementing head with the displacing fluid.

If the cementing head is located far out of reach,delays may be encountered in releasing the top plug andpumping may be interrupted for a period of time to thedetriment of the operation. Pup joints may have to beused to keep the cementing head within reach so thatsuch delays can be minimized.

At this time the cement is usually falling down thecasing on a vacuum. And displacing fluid can be siphonedinto the casing below the top plug (before it is released)if the valve to the supply source is not kept closed. Sincethe fluid can be siphoned through the cementing pump,the valve should not be opened until the top plug hasbeen released.

Another precaution taken by some service companiesis to pump a small volume of cement on top of the topplug before switching to displacing fluid.

A bottom plug is not recommended with large amountsof lost circulation material in the slurry or with badlyrusted or scaled casing, as such material may collect onthe ruptured diaphragm.

Displacement of the top plug should be carefully moni-tored. The volume of fluid behind the plug should bedetermined from calibrations on the cementing unit tanksor by measuring out of a mud storage tank. Anothermethod is to count pump strokes and convert to volumeby applying a known pump efficiency. If available, aflowmeter can be used to verify volumes pumped.

Pumps should be slowed as the pre-calculated displace-ment volume is reached, to avoid sudden bumping of thetop plug and excessive pressure. A mud line pop-off valveis a desirable safety precaution.

If the top plug does not bump at the calculated volume(allowing for displacement fluid compressibility), dis-placement should be stopped.

Accurate volume measurements can be important IIItrouble-shooting a problem cement job, as well as inkeeping track of the location of the top plug.

CENTRALIZERS

Casing centralizers are used to: Improve displace-ment efficiency (Part 4) ; to prevent differential pressuresticking (Part 1), and to keep casing out of key seats.

Two general types of centralizers are spring-bow andrigid. The spring-bow type has greater ability to providestand-off where the borehole is enlarged. The rigid typeprovides more positive stand-off where borehole is to-gauge. Special close-tolerance centralizers may be used onliners. Important design considerations are: Positioning,method of installation and spacing.

Centralizers should be positioned on casing: Throughintervals requiring effective cementing; on casing ad-jacent to (and sometimes passing through) intervalswhere differential sticking is a hazard, and occasionally

WORLD OIL 1977

GUIDE SHOE ORBAFFLE COLLAR

FLOAT SHOE(COLLAR)

DIFFERENTIAL FILL-UP.CIRCULATING TYPE

FLAPPER TYPEFLOAT

AUTOMATIC FILL-UPNON-CIRCULATING

INSERT FLOAT

Fig. 49-Examples of commonly used shoes and collars.Two fill-up devices are shown, the differential shoe or collarallows circulation while running pipe. With orifice type auto-matic fill-up device, high circulation rate shears the orificeretainer, converting tool to flapper type float. Insert float fitsin casing collar recess between joints. (Courtesy Bakerline andDowell)

on casmg passmg through dog-legs where key seats mayexist.

Effective cementing is important through productionintervals and around the lower six joints of surface andintermediate casing strings-to minimize likelihood ofjoint loss. Particularly susceptible to differential pressuresticking are permeable zones where pressure is depletedand/or high mud overbalance pressure exists. Smallclearance between casing and borehole, high deviationof the borehole and poor quality mud all increase differ-ential sticking hazard (Part 1); proper centralizationreduces the harmful effects of these conditions.

Although centralizers may appear to be unnecessaryobstructions on the pipe, they are effective and shouldbe used where applicable. Correct positioning requires acaliper log of the wellbore so that locations correspondwith to-gauge sections of the borehole.

Installation method depends on type, i.e. solid body,split body or hinged. The hinged type is most commonlyinstalled.

Centralizers are held in their relative position on thecasing either by the casing collars or mechanical stopcollars, Fig. 52. The restraining device (collar or stopcollar) should always be located within the bow-springtype centralizer so the centralizer will be pulled-notpushed-into the hole. Therefore, the bow-spring typecentralizer should not be allowed to ride free on a

casing joint.

API has established specifications for casing central-

43

FLAPPERVALVE

SHEARSLEEVE

SHEARSCREW

VALVESLEEVE

SHEARSCREWSHEARED

FLAPPERVALVE KIRKSITE

BALL~

BACK-PRESSURE VALVERELEASED FOR CEMENTING

RUNNING IN,VALVE OPEN (FILLING) CIRCULATING

Fig. 50-Principle of differential fill-up operation. Pressurearea differential on valve sleeve favoring the inside makes itengage lower flapper when casing is 90% full. Circulationhas no effect on tool, center, until dropped ball shears thesecond sleeve, permanently releasing the upper flapper, right.

DIAPHRAGM

CASTALUMINUMINSERT

BOTTOM PLUG TOP PLUG

Fig. 51-Top and bottom wiper plugs. Diaphragm in bottomplug ruptures with pressure increase to allow slurry passage.Solid plug, right, follows slurry. All plug material is drillable.

CENTR. SIZE, 7"HOLE SIZE, 9'12"

1'h:i- 1'14u:u..ocz %.<I:~ 'h

HINGEDCENTRALIZER

400 800 1,200 1,600 2pOO2~00

RESTORING FORCE, LBS.

. -- -Fig.52-Example of spring-bow centralizer contained by stopcollar so that device is pulled into hole. Load-deflection curvefor a centralizer gives lateral force on casing at various de-flections. For the example curve shown''', it takes over 1,700pounds to move the casing V4 inch off center.

izers, covering specific hole sizes and casing sizes andweight.132 Starting force, permanent set and restoringforce are defined and specified for individual sets of con-ditions.

Starting force is the force required to start the cen-tralizer into previously run casing, as determined by APItest. The maximum starting force permitted is less thanthe weight of 40 feet of medium weight casing on whichthe centralizer is run.

Permanent set is the constant bow height of the bow-springs after each bow-spring has been flattened 12 times.Maximum starting force is determined before permanentset-restoring force after.

44

Restoring force is the force exerted by a centralizeragainst the borehole to keep the pipe away from the wall.Centralizer restoring force capacity is determined throughAPI test procedures and can be presented as a load-deflection curve, Fig. 52.133 The minimum API restoringforce must equal 2 (w) sin 30 degrees-where (w) equalsweight of 40 feet of medium 'Weight casing and 30 de-grees represents an average hole angle-at a casing toborehole stand-off 0.67 times average casing to boreholeclearance. The factor (2) compensates for doglegs and isnot applied for casing sizes from 10%-20-inch.

Centralizer spacing. Load-deflection curves may beused for determining spacing required to achieve desiredstand-off. And it should be noted that stand-off requiredto prevent differential pressure sticking will normally beless than that to properly centralize casing for good dis-placement efficiency. The lateral load imposed on acasing centralizer is the combined effect of centralizerspacing, casing weight, hole angle, weight of casing belowthe centralizer and dogleg (even though minor). Theequation is:

Lateral load = Casing weight component + tension

component = m.W.L. sine + 2 (T) sin 8

Where:m = Steel in mud buoyancy factorW = Weight per foot of casing, poundsL = Distance from centralizer to next lower

centralizer, feete = Borehole angle, degrees

T = Tension (pulling force) due to casing belowcentralizer

8 = One-half the change in angle betweencentralizer and next lower centralizer

When a dogleg exists between centralizers, expressed indegrees per 100 feet, then

Dogleg (degrees/IOO ft.) x Spacing (ft.)200

8=

T = ~ m' W . L. cos e for casing sections below thecentralizer (the weight of the casing in mud isa close approximation for hole angles below thecentralizer of 25 degrees or less)

The sign (+) for the second term depends on thedirection of the dogleg (usually the sign is negative fora build-up in angle and positive for a drop-off in angle).The positive sign provides a more conservative (higher)calculated load and may be acceptable because of otherunknowns in a deviated hole.

Example calculation: For: m = 0.847 (10 ppg mud);W = 40.0 lb/ft, 9% inch casing; L = 45 feet (centralizerspacing); e = 25 degrees; 916 feet of casing below cen-tralizer, and a 2 degree/lOO foot dogleg:

Lateral load (additive dogleg) = (0.847) (40.0) (45)(0.4226) + 2 [(0.847) (40.0) (916)] 0.00785 = 644 +487 = 1,131lb.

Lateral load (Subtractive dogleg) = 644 - 487 = 157lb.

Some iteration (trail and error calculation) is requiredin calculating centralizer spacing in this manner becausea centralizer spacing must be assumed and then thelateral load on the centralizer calculated. The load then

WORLDOIL 1977

must be compared to the centralizer load deflection curve,Fig. 52, to determine whether the desired stand-off willbe achieved. If not, then a closer spa c i n g must beassumed.

Rules of thumb .for centralizerspacing in vertical holes

Surfacecasing-One centralizer should be placed im-mediately above the shoe and one at the top of each ofthe bottom six joints, to insure centralization and uniformplacement of cement in this critical section for reasonsgiven in previous articles. Centralizers may also be in-stalled to improve cement placement around any criticalwater sands.

Intermediatecasing-One centralizer should be placedimmediately above the shoe and one at the top of eachof the bottom six joints. Centralizers may also be placedwithin the cement interval to ensure uniform cementdistribution opposite critical zones.

Productioncasing-Place one centralizer immediatelyabove the shoe and one at the top of each of the bottomsix joints. They should be placed on every joint throughthe producing zones and extending 100 feet above (andbelow, if applicable). Other potential problem zones, keyseats, sticking areas, etc. should also be protected withcentralizers.

Liners-Use centralizers if clearance and hole condi-tions permit.

Stage cementing-Centralizers should be spaced overthe cemented interval above the stage collar and onejoint below, since there is no casing movement in suchjobs. When used the external packer would act as thelower centralizer.

Some manufacturers provide centralizers for installationon a given casing size, with several bow-spring sizesto accommodate starting and restoring force require-ments for different previously run casing sizes. Therefore,size of both casing to be installed and the previouslyinstalled casing (or hole) should be specified when equip-ment is ordered.

WIPERS, SCRATCHERSWipers and scratchers are used primarily to remove

borehole mud cake. They also aid in breaking-up gelledmud. Both rotating and reciprocating styles are available,Fig. 53 (also see Part 4). These devices are rarely usedon liners because of close clearances.

Rotating type wipers or scratchers are run across thezone of interest plus an additional 20 feet above andbelow the zone. Reciprocating type scratchers are gen-erally spaced at 5 to I5-foot intervals throughout thezone plus the additional 20 feet above and below. Whenreciprocating, the vertical casing movement should alwaysexceed the distance between wipers or scratchers. If re-ciprocal movement equals the spacing, removed mudcake and cuttings can accummulate at the end of eachstroke.

When wipers or scratchers are used, mud circulationshould always be started before pipe is moved. And pipeshould be moved slowly at first. If no pipe movement isplanned, these devices should not be run.

MULTIPLE STAGE EQUIPMENT

Multiple stage cementing consists of conventionalplacement of cement slurry around the lower portion ofa casing string followed by placement of successive upperstages through ports in a stage or port collar, Figs. 54,55.134 Although most stage cementin~ is done in two

WORLD OIL 1977

"..

I,

I,

A

B

r

,I

cL

'(

.1

D

Fig. 53-Examples of commonly used rotating and recipro-cating type wipers and scratchers. Rotating type (A, B, C)are spot welded or clamped. Reciprocating types (0, E, F)move between stop collars or are secured in-place with drive-set nails.

stages, additional stages are possible.Stage cementing can be used: When a long column

of cement is required and weak formations are presentwhich will not support the hydrostatic head; when twoor more widely separated intervals are present which mustbe cemented (for instance, an upper high pressure gasor water sand), or when special situations exist such asin the Arctic where casing suspension is desired belowthe base of the permafrost.

In deep, hot wells, stage cementing may also be re-

quired to. place slurry with proper temperature char-acteristics at the desired level, i.e. retarded cement withadequate thickening time for hot formations may notset-up if it is circulated to low temperature, shallow zones.

Stage or port collars may also be used for placingspecial fluids in upper portions of the casing string for

45

CLOSINGPLUG

LOWER

VSLEEVE

l'I

)f'ri, PORTS1

t,J1~:/I 0

'o {.. ,i. ~bENING, %,11 MB~..~ '

UPPERSLEEVE

CLOSED CLOSEDOPEN

Fig. 54-Stage collar operation. Tool is run in closed position,left. When lower stage is complete, bomb is dropped to movelower sleeve down exposing ports, center. Wiper plug follow-ing second stage slurry, right, moves upper sleeve downclosing all ports with cement outside casing. (CourtesyDowell)

protection against freezing, corrosion or fault movement.Advantages of port collars are that they can be openedand closed repeatedly, Fig. 55.

When wellbore fracture gradient profile is known, thestage cementing operation can be tailored more specif-ically to existing conditions.135 For example, high densitycement can be utilized and the cement column broughtabove the weak zone during the first, conventional stage.After that stage has set and the weak zone is sealed-off,a column of cement which would otherwise have frac-tured the weak zone and caused lost circulation can be

introduced at the stage collar.Other combinations of formation fracture gradients

and cement densities and column height can be handledutilizing two and three stages.134 Fracture gradients inthe above example were determined primarily duringstimulation treatments. Squeeze cementing fracturegradient information was also utilized.

Stage collars are most commonly used for this purpose,Fig. 54. The stage collar contains ports which are initiallyisolated by a sliding sleeve (s). The sleeve (s) can be moveddownward to open the ports-and later close them-with a special bomb or tripping plug. The stage collaris used in combination with: Special plug catching bafHes,bypassing bottom and shut-off wiper plugs, port openingbomb or tripping plugs and closing wiper plugs.

Typical application. The stage type tool is installed inthe desired place in the casing string as it is being run.136In the first stage, cement is circulated around the shoeand part way up the annulus-sometimes up to thelocation of the stage collar. After cement has been placedaround the bottom of the casing, the multiple stage toolis opened hydraulically by plugs. The well then can becirculated with mud, if desired.

The upper cementing operation(s) may proceed im-mediately, or the lower stage may be permitted to set-up.The final plug, following the upper stage cement slurry,closes the ports in the stage collar.

When a port collar is used, casing is run with one or

46

more port collars in-place, in the closed position. Thefirst stage primary cement job is conducted in the con-ventional manner. The casing then is landed. Drill pipeis run with a special tool for opening, closing andpacking-off the collars. One port collar can be opened,and cement placed. That collar then is closed, the nextcollar is opened, cement is placed, and so on. With allcollars closed, excess cement is reverse circulated.

When these devices are used, an external casing packeror metal petal basket is commonly installed below thecoUar to prevent cement from falling through mud in theannulus. This precaution is particularly appropriate whenweak zones exist below the collar.

One disadvantage to stage cementing is that the casingcannot be moved (rotated or reciprocated) after thefirst stage has set. This increases the possibility of chan-neling and incomplete mud removal.

Although stage cementing equipment has proven tobe quite reliable, it is always possible that the collar willnot close and seal completely. If this happens, satisfactoryremedial cementing at shallow depths, particularly whenthe well is completed in deeper high pressure zones, maynot be possible. However, the only alternative to use of

tzWD-o

weno-'o

!

ROTATING SLEEVE VERTICAL ACTIONSLEEVE

Fig. 55-Operating principle of two types of port collars thatcan be repeatedly opened or closed by rotation of tubing ordrill pipe, left, or by vertical movement, right. Use of cuptype packers and additional ported sleeves on the inner string(see Fig. 59) allow cement to be placed through one or morecasing port collars.

WORLD OIL 1977

collars-if stage cementing is absolutely necessary-isperforating, cementing and squeezing the perforations.Use of stage cementing collars is certainly preferable tothis alternative.

External casing packers, available in both solid rubberand inflatable styles, are becoming more widely appliedin primary cementing to reduce the cost of remedialwork. The external casing packer is frequently appliedin lieu of the metal petal basket where positive controlis required. Packers also help centralize the casing.

The use of the external casing packer and a stagecollar as a pack-off shoe or collar is illustrated in Fig.56. This combination has been effective in preventingloss of cement to rathole and contamination of the

primary cement job cement with mud. Inflatable ex-ternal packers and port collars have also been appliedfor cementing between zones to be open hole gravelpacked as discussed in a previous series (see WORLDOIL'SSand Control Handbook, page 44).

MIXING EQUIPMENT, DENSITY CONTROLDry cement must be mixed with the proper amount of

water to ensure that slurry and set cement propertiesare as designed. Effects of inadequate or excessive waterare discussed in Part 3 of this series.

For most slurries, the jet mixer will provide a uni-form mixture.135 Special mixing e qui p men t is some-times required for high density cement, high viscositycement and jobs in which precise composition and blend-ing of all additives is particularly critical (such as linerand squeeze cementing operations). Density measure-ments are used to verify proper cement/water mix ratios

during the job.

The jet mixer induces a partial vacuum at the venturithroat which draws in the dry cement. High streamturbulence then provides thorough mixing. This type ofmixer is simple, reliable and rugged. Some cementingcompositions require the use of specially designed andsized nozzle units. Jet mixers are capable of handling 50sacks per minute.

One disadvantage of high pressure jet mixers is thattwo pumps are tied-up during the mixing operation-onemixing, the other pumping fluid downhole.

Special mixing equipment available through servicecompanies utilize a variety of mixing principles. Twobasic types are "continuous" and "batch". Mixing and/orblending is achieved with continuous methods through:Cyclone or whirlpool action; recirculation; jet turbulence,or a combination of these actions. Larger "tub" storageof mixed slurry tends to improve uniformity.

Mixing and/or blending is achieved with batchmethods through use of: Propeller or imp e 11er typemixers; paddle mixers; ribbon blenders; pneumatic mix-ing, and rotation of the cement tank (similar in ap-pearance to those used in construction).

The amount of cement that can be mixed in a batch

unit is limited. However, several batch type units canbe combined to provide continuous operation on largejobs. Batch mixing provides the most accurate andthorough mixing of all slurry components.

WORLD OIL 1977

CEMENT

STAGE COLLAR

FLEXIBLEPLUG

Fig. 56-Schematic of inflatable external packer used with astage collar to pack off above a weak zone or open holesection. Flexible plug is first pumped to the shoe and pressureis applied to inflate the packer element. The tripping plugopens the sleeve for cementing and the shut-off plug closesthe sleeve permanently. Other variations are possible usinghydraulically operated cementing collars.

Continuous and batch units can also be combined in

series. The various types of equipment have differentlimits in mixing rate, storage or "holding" volume andpump rate. The service company should be consulted re-garding specifications, availability and suitability of unitsfor particular applications.

Density measurements are used to control the mixingoperation. Variations in density during a job can resultfrom: Non-uniform blending of dry components; changesin the water-to-cement ratio; air entrainment in the

sample, or a combination of these possibilities.

Density is measured as samples with balances (twotypes), or continuously with radioactive devices or aforce-balanced U -tube.137-139

Density is usually obtained with a standard API mudbalance. The device is simple, easy to use and givesreasonably correct values when precautions are taken toavoid air entrainment. Avoid sampling the upper, aeratedportion of the slurry in tub, blender or mixer.

Accuracy can be improved by using the API pressurizedfluid density balance in which the slurry is pressured toahout 400 psi with a hand pump before weighing. In thisdevice the air occupies a negligible volume.137

LOST CIRCULATION,VOLUME CALCULATIONSLost circulation is normally handled in primary ce-

menting by either: Using a low density slurry to preventformation breakdown and/or using stage equipment if

47

the breakdown pressure would be exceeded by bringingthe cement up in one stage.

Low density slurries may be desirable for minimizingdownhole pressure and avoiding lost circulation, butthe high strength of neat cement may be preferredthrough completion intervals and around lower casingjoints. Bridging material is added in only small con-centrations, if at all, to avoid problems with plugs andfloat equipment, and bridging in the casing-well boreannulus, see table.

Although high filtrate loss may be favorable for block-ing fractures in permeable zones, some filtrate loss con-trol may be desirable to prevent slurry dehydration andbridging in the wellbore annulus. In such cases, a goodcompromise is to use a cement with about a 200 to 500ml filtrate loss at 1,000 psi.

Bridging material should be used in primary cementingonly as a last resort. If it is used and stage tools arenecessary, only granular type materials should be con-sidered. In addition, the following precautions shouldbe taken:

Precautions to avoid plugging

. Preferably, the first and last portions of the primarycement job will not contain lost circulation material,particularly large solids. Bridging hazards are de-creased when slurry free of bridging material initiatesflow through restrictions. Slurry free of bridging ma-terial at the end of the job will tend to wash awaysolids left in collars and baffles to improve operationof floats and stage tools. And plugs wipe better withless chance of accumulatingbridging material beneaththe plug and stopping it prematurely.

. Avoid reducing slurry bridging material carrying ca-pacity with excess water or dispersants. Also, dilu-tion and thinning of slurry from water in pumps, linesor spacers should be avoided.

. The job should be continuous with no shut-downs.

Cement volume required in primary cementing canbe calculated using a caliper log and tables provided bythe cementing company. An excess of 15-35% is used asa safety factor when a caliper log is used. When such logsare not available, volume is based on experience in thearea and is some factor applied to the volume removedby the bit assuming no washouts.

Rig crews commonly calculate hole volume by timingthe circulation of marker material (oats, dye, etc.) and

Properties of bridging material

applying mud pump rate and drill pipe displacementdata. This can aid in determining cement volume.

METHODS FOR VARIOUS CASING STRINGS

Conductor pipe, and surface, intermediate and pro-duction casing strings have different requirements foraccessory casing equipment and cement composition (seeParts 1 and 3). For instance, design considerations mayinclude: The need for zone isolation; protection againstbottom joint loss; whether or not the interval will beperforated; and so on.

High compressive strength cement should be used atthe shoe of all strings and opposite the producing zones,particularly if high pressure treating or fracturing isplanned. Compressive strength should be at least 500psi before drilling out and 2,000 psi before perforating.

Conductor pipe is used to raise the circulating fluidhigh enough to return to the mud pits.129 It also preventswashing out around the rig base and sometimes it pro-vides a base for blowout preventers where gas sands maybe encountered at shallow depth. And it may be used tosupport some of the wellhead load. This pipe is cementedto the surface. Depth can be a few feet to 200 feet.

Normally, an accelerated neat cement is used to pro-vide maximum compressive strength and rotational/axialshear resistance. Minimal accessory downhole casingequipment is used. For instance, a guide shoe and topplug may be used when water is the drilling fluid andmud is not adhering to the inside surface of the casing.Precautions should be taken to avoid pumping this string(or any large diameter casing) out of the hole, as will bediscussed below.

Surface casing is run: To protect the shallow freshwater sands from contamination by brines; to seal offproblem sections of the hole (such as caving) ; to providesupport for the wellhead, and to provide blowout protec-tion in combination with blowout preventers. Depth canrange from a couple of hundred to several thousand feetand is frequently specified by government regulations.Surface pipe is usually cemented to the surface.

Normally, an accelerated neat cement is used to pro-tect a short surface casing string or the lower section of along string. "Filler" cement is placed across the uppersection because such a cement usually: Provides adequate

*Absolutedensity83Ib./cu.ft.atzeropsi,143Ib./cu.ft.at 3,000psi.**Concentrationsof 2-5Ib.jsackmaybe addedto cementslurrywith minimumdangerof bridging.

48 WORLD OIL 1977

Specific Size Temp. Cone.Type gravity (Mesh) limit Ib./sk. Comments

Cellophaneflakes.. .. .. .. ... - -% in. '" \Is-Yz Donot usebottomplugs,stagetool or ball typefloat equip.at overIb./sk.

Gilsonite.. . . ........ 1.07 (8/100) About Normally Donotusemorethan25Ib./sk. with stagetools,smallannularclearance300°F 5-25** or smallpipe.

Crushedcoal.. . . . . ....... 1.30 (8/200) l,OOO°F Normally Donotusemorethan25Ib./sk.with stagetools,smallannularclearance5-25** or smallpipe.

PerliteExpanded. . .. .. . . . . . . . . . . 2.40* (10/50) .. 15-20 ExpandedPerlitetakesonwateraspressureincreasesdownhole.PerliteSemi-expanded.. . . . . . 2.40* 50%(50/200) 15-20 tendsto float in thin slurries due to entrappedair. Lowgel strength

50%( <200) slurrieswill notcarry Perlite.Somewhatfragileandwill notperformas

Walnutshellscoarse... . . .well asothergranularmaterialsunderhighdifferentialpressure.

1.28 % in.-(100) .. ... 1-5 Donotusein smallannularclearancesor smallpipe.Walnutshellsmedium....... 1.28 (10/100) .... 1-5 Usuallymosteffective.Not likely to bridgebottomplugor annulus.Walnutshellsfine. . . . . . . . . . . 1.28 (30/100) ...... 1-5 Onlysizeto usewith stagetoolsor ball typefloats.

axial shear bond strength and zonal isolation; it is lesslikely to "break-down" any weak zones, and it is lessexpensive than neat cement. Other aspects of slurry de-sign may have to be considered, as discussed in Part 3,if salt zones, sloughing shales or other problems exist.

Precautions may have to be taken to prevent bottomjoint loss as described in Part 1, including: Strengtheningthe lower joints by welding or use of thread locking com-pound; using two plugs; using both a guide shoe andfloat collar, and centralizing the pipe.

Hanger devices are available that may be placed in thesurface casing a few hundred feet above the shoe to sus-pend part of the weight of an inner string from thatpoint.

Intermediate casing-protective casing-is most oftenused to seal off weak zones that might be fractured byheavy muds used to drill deeper, geopressured zones.Conversely, this string is sometimes used to isolate highpressure zones so lighter drilling fluid can be used for drill-ing deeper zones with more normal, hydrostatic pressure.Intermediate casing is also used to isolate corrosive water.

If only small annular fill-up is required, neat cementis used. When high slurry volumes are needed, inexpen-sive and low-density filler cement is followed by neatcement at the shoe. Stage cementing is sometimes re-quired. When cementing off bottom an external casingpacker and stage collar might be required as a pack-offshoe.

Production casing, in addition to its borehole supportfunction, is run to prevent interzonal flow while produc-ing from or injecting into (such as stimulating) the pro-duction interval. High compressive strength cement ispreferred in this application.

Neat cement with retarder, if required, is normallyused. Cement density and strength retrogression were dis-cussed in Part 3 (two ppg more than mud weight is de-sirable) .

Downhole equipment will normally include two plugs,using both a guide shoe and float collar. Some operatorsuse a flQat shoe and a float collar as added insurance forpositive shut-off. And "automatic" fill-up equipment isoften used on production casing.

Cementing large diameter casing requires some spe-cial considerations. Such casing is subject to beingpumped out of the hole. This will occur when the pumpor hydrostatic pressure acting on the cementing headarea, equal to the casing inside cross sectional area, pro-vides an upward force exceeding the buoyed weight ofthe casing. Pressure increase on bumping a plug is, ofcourse, offset and does not contribute to the problem.

Large casing can also be floated out of the hole if theweight of casing and mud in the pipe does not exceedthe buoyancy provided by the annular column of cement.The possibility of casing collapse must also be consid-ered. Heavy mud may be required to prevent these oc-currences.

Inner string or stab-in cementing is now a fairly com-mon practice for large diameter casing. The string iscemented through drill pipe stung into a special sealingsleeve in the shoe. With this method there is less likelihood

WORLD OIL 1977

CASING11

COLLARCEMENTINFLATETOOL

PORTCOLLAR

,

j"

,I'

:1!

IECP

INNERSTRING

I;'.

LATCHSEAL

FIRST STAGE INFLATE PACKER SECOND STAGE

Fig. 57-Stab-in stage cementing for large diameter casing.(1) With seal nipple latched into casing shoe, first stage ce-ment is pumped, and displaced with the flexible latch-downplug. (2) A ball is dropped into the cementing tool, the innerstring is raised, and cups are located over ECP port to inflatepacker element. (3) Tool is raised and rotated to open portcollar, and second stage is pumped. Then ports are closed,and the inner string is reverse circulated for clean-up.

of pumping the casing from the well. There is less mudcontamination, less wasted cement, and there is less ce-ment to drill out. One method of stage cementing largediameter, shallow casing using an inflatable external cas-ing packer and port collar is shown in Fig. 57.

Coming next month: Liner cementing-design and appli-cation, running and cementing techniques.

ACKNOWLEDGMENTThe authors wish to acknowledge the contribution of Mr. Kerr Godfrey of

Atlantic Richficld Co. who provided valuable information and data includedin this article.

LITERATURE CITED

". Willard, R., Personal communication, 1977.13. Gage, O. G., Jr., "Subsurface Cementing Equipment," Oil-Well Ce-

menllng Practices in The United StaJes, API (1959). pp. 109-117.131Moscrip, R. P.) Coordinator, "Preparation of Hole, Running and Cement-

ing Casing," Oil-Well Cementing Practices in The United States, API(I 959). pp. 101'-107.

132"API Specification for Casing Centralizers," API Spec 10D, Second Edi-tion, February 1973 and Supplement 1', March 1976.

133Anon. "Cementing Program,' Weatherford.134Pela, E. C,) Coordinator, "Multistage Cementing and Alternations,"

Oil-Well Cementing Practices in The United States, API (1959), pp.141-147.

186Gibbs, M. A., "Delaware Basin Cementing:-Problems and Solutions,"Journal of Petroleum Technology, October 1966, pp. 1281-1285.

13. Owsley, Wm. D., "Surface Cementing Equipment and Supplies," Oil-Well Cementing Practices in the United States, API (1959), pp. 87-89.

111Nickles, S. K., "An Instrument for Measuring the DensIty of Air En-trained Fluids," SPE Paper <W92Presented at 47th Annual Fall Meeting,San Antonio, Texas, Oct. 8-11, 1972.

133 Moran, J. P. and Hartweg, D. G., "How to Control Slurry Density,"The 011 and Gas Journal, April 28, 1958.

139Guest, R. J. and Zimmerman, C. W., "Compensated Gamma RayDensimeter Measures Slurry Densities in Flow,U Petroleum Engineer,September 1973.

49

Cementing oil and gas wells

Part 6-Liner applications and equipmentused for installation. Common problemsto avoid while pumping, displacing cement

George O. Suman, Jr., President,and Richard C. Ellis,Project Engineer, Completion TechnologyCo., Houston

10-second summaryLiner running and cementing methods are illustrated

and applications of various types of liners are discussed.Solutions to common problems encountered in conven-tional and special liner cementing, and basic job designcriteria, are suggested.

LINER CEMENTINGis one of the most difficult operationsassociated with drilling and completion. If a liner is noteffectively cemented, the well's capability to produce willlikely be reduced and the advantages of the liner installa-tion will not be realized. This article describes liner equip-ment, cementing applications, some associated problemsand solutions.

In one generally accepted definition, a liner is: A string

TYPES OF LlNlRS

Drilling liners are used to permit deeper drilling operations byisolating lost circulation or highly pressured intervals and con-trolling sloughing or plastic formations. And in lieu of a fulllength casing string, the drilling liner improves drilling hydrau-lics, i.e. greater cross section above liner top enables use of largerdrill pipe and/or reduces annular pressure drop.

Production liners are required to provide isolation and supportfunctions when casing was landed above the producing interval.

A tie-back stub liner extends from the top of a liner to a pointuphole, inside another string of casing or liner. The stub liner isused to: Repair damaged or worn casing above an existing liner,and to provide an added measure of protection against corrosionand/or pressure.

Tie-back casing is used to extend a liner to the wellhead. I t isused primarily for the same reasons as the tie-back liner.'" Run-ning such a string at the end of a drilling operation assures theprotection of fresh, unworn casing.

50

SURFAC~

2,000-

4,000-

6,000-

8,000-

10,000-

12,000-

14,000-

16,000-

18,000-

20,000-

I SURFACEL CASING

INTERMEDIATECASING

TIE-BACKSTUB LINER

PRODUCTION LINER

1/

PORE PRESSURE

/

(NORMAL)

FRAC PRESSURE

,/,,,,,,,,,,,,,,I,......,...'

I I I I I I I

8 10 12 14 16 18 20

EQUIVALENT MUD WT., PPG

Fig. 58-Example of casing and liner program to seal off highpressure zones in a deep well (after Mahoney and Barrios),'''

of casing that is used to case-off the open hole below anexisting casing string, and which does not extend up tothe wellhead.140

Included in this definition are slotted, pre-perforatedand wire wrapped screens that are placed in an open holeprimarily for sand exclusion during producing operations.Such liners are not included in this article as they are notordinarily cemented in-place. Liners that are discussedare described in the accompanying table. Wells drilled in

WORLDOIL 1977

CEMENTINGMANIFOLD

LINER TIE-BACK SLEEVESETTING

TOOL

PACKOFF BUSHING

(RETRIEVABLE-OPTIONAL)

HANGER

WIPER PLUG(SHEAR TYPE)

STANDOFFDEVICES

LANDING COLLAR

FLOATCOLLAR

FLOAT SHOE

Fig. 59-Typical equipment used to install and cement a drill-ing liner.

the deep basins of the United States frequently reqUireall of the liner types described, see Fig. 58.142

LINER EQUIPMENT

A liner is normally run on drill pipe that extends fromthe liner setting tool to surface. Special tools are availableto perform various running, setting and cementing opera-tions.

The following equipment is discussed from float shoe(bottom) to cementing manifold (top). Equipment loca-tions are shown schematically in Fig. 59.

A float shoe is placed at the bottom of the liner. Itcontains a check valve designed to prevent back-flow ofthe cement. A float collar can be run above the shoe to

provide a back-up check valve to assure that cement can-not re-enter the liner after displacement.143 Automatic fill-up type float equipment may be selected (Part 5).

A landing collar is usually run one joint above the floatcollar or two or more joints above the float shoe to pro-vide space for mud contaminated cement inside the liner.The landing collar's function is to latch and seal the linerwiper plug. It prevents the liner wiper plug from movinguphole if a check valve fails and also prevents it fromrotating, which aids the drilling-out operation.

Liner length is selected to extend across the open hole

WORLD OIL 1977

..INTERMEDIATE CASING

TIE-BACK PACKER

GAS MIGRATION

HIGH PRESSURE GAS ZONE

Fig. 60-Schematic of a liner tie-back packer used to repaira leaking liner top where high pressure gas has penetratedthe cement. Packer is run after liner is cemented and cleanedout (after Lindsey).1<3

DISPLACINGCEMENT

..

WIPER PLUGS

FLOAT SHOE

INFLATEPACKERS

Fig. 61-External casing packers used to provide positive sealbetween open hole intervals behind drilling liner (after Cov-lin).'"

and overlap the existing casing or drilling liner. Thelength of the overlap varies with operators and applica-tions. Fifty to five hundred feet of overlap have been usedin various applications. The overlap should place thehanger above any weakened or suspect lower joints in thepreceding casing string.

Longer overlaps are used when high pressures are

51

being isolated behind the liners, to provide more cementvolume in the liner-casing annulus. Longer overlaps alsoreduce cement volume displaced around the drill pipeabove the liner running assembly.

Short liner assemblie~ have been run and set on bottom.

Although the small annular clearance limits the degree ofliner buckling, any buckling will result in liner-boreholecontact-the worst possible position for the liner from acement placement standpoint. Except in unusual caseswhere buckling is not expected or where it can be pre-vented through centralization, liners to be cemented shouldbe suspended from slips set in existing casing, or thedrilling liner.

Equipment is available for the special application inwhich liners are cemented and set on bottom. A specialfloat shoe can be run on the bottom of the liner with anextra internal left-hand thread. The liner is first run into

the well. The cementing string then is run and engagedinto the thread at the shoe. The liner is run to bottom on

the cementing string and the cement job is completed.The cementing string is disconnected from the shoe byrotating to the right.

The liner hanger is installed at the top of the liner.Hangers are usually classified by the method used towedge slips against the casing wall. Two classifications forhangers are: Mechanical and hydraulic.141 Mechanicalset hangers require manipulation of the drill pipe (rota-tion and/or reciprocation) to engage the slips. Hydraulichangers are either hydraulic release or hydraulic set. Theslips of hydraulic release types require slight downwardmovement of the hanger for setting. Slips of hydraulicset types are driven into place by differential pressure.

The presence of slips between liner and casing reducesthe bypass area for circulating. This reduced fluid bypassarea can create a high pressure loss during circulation andcementing. Hangers are available with multiple split slipswhich increase the fluid bypass area and provide increasedslip contact area. These should be used on long liners foradded bypass area where formation strength is low, re-quiring careful control of cement displacing pressures.143

The liner setting tool, a rental item furnished by theliner hanger service company, provides the connection be-tween drill pipe and liner. Swab cups attached to tailpipe144 or a pack-off bushing and slick joint are insertedinto the liner to provide a seal between the setting tooland the liner, after the liner has been suspended from thehanger and the setting tool released. The tail pipe or slickjoint is usually 10-15 feet long. The slick joint methodreduces piston force effects of pressure on the formation.

Once the liner is hung, the setting tool can be releasedand picked up a short distance to confirm, by indicatorweight loss, that the setting tool has separated.

A relatively new innovation is the retrievable pack-offbushing that eliminates bushing drill-out.

A liner wiper plug can be attached to the end of thetail pipe or slick joint with a shear pin arrangement. Theselection of the proper shear rating is very important toprevent premature shearing and release of the liner wiperplug. This is especially important when a high densityslurry is to be used or where a large pressure drop is ex-pected across the liner wiper plug ID. The liner wiperplug can also be latched to the tail pipe to prevent pre-

52

mature shearing. Release of this type can only be affectedby engagement of the drill pipe wiper plug.

Liner packers can be installed at the top of liners to sealbetween liner and casing, after cement placement. Sealelements may be rubber or lead or a combination of both.Liner top packers may be run as an integral part of theliner hanger and set by manipulation of the liner runningtool. However, this type of packer should be consideredonly if clearance between casing and the packer elementis such that the hole can be circulated at desired rates

without increasing back pressure excessively on the openhole.

Inadequate circulation clearance, combined with thepossibility that the main sealing element could be damagedby mud and cuttings circulating past the packer, couldresult in seal failure.

A minimum-restriction liner hanger without a packermay permit more effective cementing and desired sealingof the overlap. A liner packer does enable reversing-outof excess cement without imposing high pressure on theformation. This type packer is not recommended for highpressure gas control.. Special packers can be set in conjunction with a tie-back sleeve (to be discussed later) after cementing andclean out operations have been completed. These "liner-tie back packers" seal both in the tie-back sleeve andagainst the suspending casing.143 The tie-back packers arenot exposed to potentially damaging circulation and havebeen successful in controlling gas leakage around the linertop, Fig. 60.

External casing packers have been used on liners toisolate between zones in open hole. They are inflated fol-lowing cement displacement-before the cement sets up-to provide more effective zone isolation, Fig. 61.145 Ex-ternal casing packers have also been used to seal the linertop. Liner stage cementing is possible with the inflatableexternal casing packer and hydraulically operated cement-ing collars.

Tie-back liner or casing. It may be desirable to extenda liner uphole, with a tie-back "stub" liner, or to thesurface with a tie-back casing string. This can be accom-plished by installing a tie-back sleeve or receptacle on topof the liner hanger. The tie-back sleeve is usually polished3-6 feet on the ID surface and is beveled on the top toguide entry of seal nipple, tools, drill bits, etc. Fig. 62.

A liner tie-back sealing nipple run on the bottom of thetie-back string should be designed to fill the full length ofthe tie-back sleeve with multiple sealing (packing) ele-ments to assure an effective seal even with localized dam-

age to the receptacle ID. Cement float equipment shouldnot be used, to avoid a pressure block which would pre-vent full insertion of the seal nipple into the receptacle.

As mentioned, the drill pipe extends from the linersetting tool to the surface. The cementing manifold andpump-down plug dropping head are connected to the topof the drill pipe. The manifold provides a means of pump-ing mud and cement down the drill pipe and retainingthe pump-down plug until it is to be released, behind thecement.

COMMON RUNNING CEMENTING PROBLEMS

Small annular clearance is the primary problem in lineroperations. It is not uncommon to have a 5-inch OD liner

WORLD OIL 1977

extend below 7-inch casing, inside a 6y/!-inch drilledhole. With the liner perfectly centered, the annular clear-ance is only %6 inch. It is likely that even less clearancewould exist, as a thin non-movable layer of mud cake maybe present opposite permeable zones. This is less than halfthe clearance norma,lly achieved in casing cementing prac-tices where, for example, it is common to run 5 1/2-inchcasing into a 7 7/8-inch drilled hole.

Small clearance causes high pressure losses during cir-culation and cement placement which increase the pos-sibility of lost circulation.

The small clearance also makes it difficult to' run liners.

Swab/surge pressures can be extremely severe and run-ning speeds should be slow to avoid pressures that couldbreak down formations and cause lost circulation. It is

frequently necessary to restrict running speeds to one standof drill pipe every two to three minutes.146 Detailed eval-uation of swab/surge pressures should be part of a linerrunning program.

Drilling mud properties for different wells may resultin substantially different swab/surge effects. Detailed com-puterized analytical procedures as well as simplified nomo-graphs are available in the literature to aid in determiningmaximum running speeds (see refs. 118-120, Part 4).

Cement contamination by mud is increased by the smallclearance between liner and open hole. And restrictedclearance may inhibit use of centralizers, resulting in severeeccentricity or actual borehole contact. Cement channel-ing or mud bypassing is most likely under these circum-stances.

Cement volumes are necessarily small and bypassedmud, particularly near the top of the liner, will be mostdifficult to remove. Even with cement in turbulent flow,and with good rheological properties of both the mud andcement, bypassed mud may not be removed due to in-sufficient "contact time" ,with the cement slurry.lo7

Lack of pipe movement while cementing. Althoughpipe movement is considered one of the most importantfactors in achieving a successful cement job, moving aliner while cementing is seldom' done because of the desireto be "free" from the liner prior to pumping cement.Fluid rising velocity decreases appreciably above the linerrunning assembly and debris and cuttings can accumulatearound the drill pipe making release difficult, particularlyif the mud system was not properly conditioned, prior tothe job.

Obtaining competent cement at the liner top with asingle-stage liner cementing technique, requires that excesscement be circulated over the top of the liner through thecasing-liner annulus. This operation concerns most drillingand operating personnel because premature set could leadto an expensive fishing operation or even well loss. Thus,the desire to be "free" from the liner usually precludesthe opportunity for pipe movement.

A recent innovation is a pressure relief sub. After bump-ing the plug, if release from the liner is not achieved,additional pressure (4,000-5,000 psi) opens ports andenables excess cement to be reversed out of the hole.

Temperature differential. Long-liner installations mayencounter problems due to a substantial temperature dif-ferential between liner top and bottom. Cement formu-lated to accommodate the higher, deeper temperatures

WORLD OIL 1977

may require prolonged WOC time at the liner top toachieve adequate set. Where high pressure gas is to beisolated behind the liner, this problem is severe, as gas"honeycombing" of the unset cement may occur and pre-vent setting and desired top seal.

Contamination. Mud-cement reactions may develop ex-cessive viscosity at the interface which could increasepressure drop in the annulus. High pumping pressurescould fracture weak zones or cause the fluid to be forced

from the slurry and the cement to bridge in the annulus.(See Fig. 26, Part 3.)

CEMENTING TECHNIQUES, DESIGN CRITERIAAn effective cement seal is usually required at both ends

of a liner. A good cement job on a drilling liner is onethat allows drilling to the next casing (or liner) settingdepth without: Having to squeeze either at the liner topor at the shoe joint, and without experiencing bucklingor other liner damage.

An effective production liner cement job provides aseal between liner and borehole such that remedial cement

squeeze jobs are not required-basically the same as fora production casing string.

Developing the seal at the top and bottom of a linerand between the liner and open hole requires effectivemud displacement by the cement slurry, and cement prop-erties that permit strength development without excessivewaiting on cement time.

Clearance and centralizing. A way to increase clear-ance would be to redesign the casing program and drilllarger holes for a given liner size or, conversely, runsmaller liners.

Another solution is to underream the open hole. Wherethis is not practical over long intervals, selective under-reaming opposite critical zones has been applied. How-ever, selectively underreamed sections can be similar toborehole washouts. And effective cementing can be mademore difficult, rather than simplified, under such condi-tions. Careful design is important.

Centralizing the liner in the hole is very critical to effec-tive cement placement. This is particularly true in deviatedholes. Centralizers or positive standoff devices on the linercould be essential for success of cementing operations.However, the small annular clearance between liner andopen hole often prohibits use of centralizers. Fluted posi-tive standoff collars will improve standoff conditions. Theycan be run with as little as ?'4-inch clearance.

Centralizers or positive standoff devices also reduce thelikelihood of differential pressure sticking between linerand open hole. This makes it easier to move the liner,once it is in-place. Another innovation, intended to reducedifferential sticking and improve cement placement, arehelical grooves in the OD surface of the pipe; collapseresistance of such pipe should meet requirements.

Moving the liner while cementing. The design of someliner setting tools and hangers makes it possible to movethe liner during cementing. And moving the pipe is onefactor that greatly affects cement placement efficiency(Part 4). However, as discussed, liner movement duringcementing is rarely attempted.

Special equipment is available that permits liner rota-

S3

tion after detaching the setting tool from the liner. But,the small bearing surface area on rotation collars limitsthe amount of weight that can be suspended below thedevice. The maximum liner length to be suspended belowa rotation collar should be confirmed with the manufac-turer.

Temperature compensation. The problem of achievinga cement seal at both ends of a liner increases with linerlength, as was mentioned.147 Wide temperature variationsusually require special cement formulations. It may benecessary to retard the cement to compensate for highertemperatures at the bottom. But, at the same time, it isnecessary that the cement set at the lower temperaturesnear the liner top in a reasonable time.

To compensate for the temperature variations it is essen-tial to have accurate downhole circulating and static tem-perature information. Tests have shown that a cementslurry that had a thickening time of 4 hours and 54 min-utes at 125°F had its thickening time reduced to only 2hours and 57 minutes at 144°F.

Temperature also affects set time and com pressi vestrength. For example, at 230°F a cement may have an8-hour compressive strength of 1,575 psi but at 200°Fthat same cement may not even set in 8 hours. (Part 3) .148

Special downhole temperature recording devices havebeen used to measure actual temperatures to make effec-tive cement formulation decisions.

Cement design criteria. Slurry formulation for linercementing is not simple. Each liner installation has to beexamined to define hole conditions and develop the spe-cific combination of properties that are best suited forthe job.

Pumping time (or thickening time) is usually designedto allow "reversing out" the cement in case of a problem.However, in wells where high pressure gas is being iso-lated behind the liner relatively short thickening and set-ting time are required to reduce chances of gas penetratingthe unset cement (honeycombing).

Slurry density has to be adequate to prevent formationfluid from entering the wellbore, but the combined den-sity and displacement pressures must remain below frac-ture pressures of the weakest zones open in the wellbore.Normally, slurry density slightly exceeds mud density.

Fluid loss additives are usually required to prevent for-mation damage and to reduce any tendency for buildinga cement filter cake that could cause bridging in the an-nulus. No lost circulation material should be used in liner

cementing, to avoid plugging float equipment or the nar-row annulus. If this material is absolutely essential forlost circulation control it should not be included in the

lead or tail portion of the slurry (Part 5) .

Cement volume used on liner jobs has varied from lessthan 100% to over 300% of the required volume. Excessvolume increases the likelihood for good cement placementbut it also increases the possibility of operating problems.Generally, 125-150% of the required volume based oncaliper surveys is used in liner cementing efforts.

One technique that has been used primarily to assurea cement seal at both the liner top and bottom is a"planned squeeze" job. The cement volume placed aroundthe shoe is only 70-80% of the annular volume behind the

54

COARSE THREAD FOR RIGHTHAND TOOL RELEASE

FOR HANGER ASSEMBLY

RECEPTACLE

Fig. 62- Tie-back sleeve and seal nipple used to connect tie-back liner or casing to an installed liner (after Lindsey).'''

liner; then a secondary cement squeeze is conducted atthe liner top. This technique has not had wide acceptance.The primary disadvantage is that a long gap will be leftbetween upper and lower cemented intervals. And theuncemented, unsupported section of liner may buckleunder sever stresses due to temperature and pressurechanges.149

Cement testing. There are special testing schedules forliners.61 Such tests should be conducted using cement sam-ples and additives from material to be used on the job.And the mix water should be from the field water sourceto "bring to light" any incompatibility between the fieldwater and some admix and/or the cement.

Spacer fluids. The plug arrangement for liner cement-ing eliminates the opportunity to run a bottom plug aheadof the cement. As a result, there can be a contaminatedlayer in the lead part of the cement slurry which maybecome very viscous.

Normally, a spacer fluid is pumped between mud andcement to provide a buffer to avoid serious contamination.Different types of spacers have been used depending onthe type of mud used for drilling and the cement slurryselected. In some instances multiple stage spacer systemshave been employed to improve mud displacement andreduce chances for adverse mud-cement reactions. Spacerfluids were discussed in Part 4 of this series and additionaldetails are available in the literature.121-12i!, 150,151

PUMPING, DISPLACING, JOB EVALUATION

A conventional liner cementing sequence is shown inFig. 63.152 The following precautions should be observedwhile pumping and displacing:

When the liner is in position, mud is usually circulated,to be sure that liner and float equipment are free of anyforeign material, and to condition the mud. Of course,debris and cuttings should have been circulated from thewell before the liner was run to clean up the system. Aclean mud system is important so that such materials willnot fall out on top of the liner running assembly duringthe cement job.

Important information can also be obtained while cir-culating the ,well after the liner is run. At a minimum,

WORLD OIL 1977

bottoms should be circulated to the surface-a full circu-

lation is preferred. Pump rate and pressure should bemonitored and checked against the plan for the job. If aserious deviation exists, an adjustment may be required,for instance in pump rate. Fluid should be weighed andexamined for gas or formation material. Returns shouldbe gaged and pit level observed for indications of lostreturns.

The cement can be batch mixed, circulated through aholding tank or ribbon blender and/or double pumped inorder to obtain and control desired cement slurry prop-erties.

Cement displacement rate selection should follow guide-lines suggested in Part 4- for casing cementing operations.Turbulent or plug flow rates are encouraged. Such flowminimizes excess cement volume requirements. Most op-erators prefer to limit the excess cement volume which, ofcourse, is pumped into the drill pipe-casing annulus. And,as mentioned, it is usually desirable to pump some typeof spacer fluid (buffer) ahead of the cement.

Plugs. When the cement has been pumped, the pumpdown plug is released and displaced between cement andmud. At the bottom of the liner setting tool and tail pipe,the pump down plug latches into the liner wiper plug,shearing or unlatching it from the tail pipe. The twoplugs then move as a single plug down the liner and latchin and seal at the landing collar.

Since there is no bottom plug, pump down and linerplugs wipe mud film off the ID of the drill pipe andliner. This mud collects below the plugs and can con-taminate cement in the bottom of the liner. Spacing be-tween landing collar and float shoe should be adequate tokeep contaminated cement out of the liner-open holeannulus. Mud accumulations beneath a wiper plug canbe substantial (Part 1).

Excess cement. With cement in-placeit is standard pro-cedure to pull the liner setting assembly out of the linerhanger. With the tail pipe above the liner top, excesscement can be reversed out. However, reverse circulationplaces an extra pressure on the annulus, and this addi-tional pressure should be precalculated and controlled,where necessary, to avoid formation breakdown. A linerpacker keeps reverse circulation pressures off the forma-tion.

One practice is to simply pull the drill pipe and leavecement inside the casing to be drilled out. Waiting oncement time depends on cement composition and holeconditions.

Tie-back casing is usually cemented by conventionallycirculating the cement. The cement job is conducted be-fore landing the seal nipple in the tie-back receptacle. Orit can be cemented in-place, after landing and testing thetie-back connection, by circulating cement through a stagecollar located above the tie-back nipple.

A tie-back casing string may also be cemented by re-verse cementing (cementing down the annulus).153 Thistechnique has been used in some deep wells-above highpressure gas zones and leaking drilling liners-so thatleaking gas would be conveyed up the inside of the tie-back string with mud and cement returns.

When reverse circulating cement into place, the cementcomposition can be correctly tailored to the job-for ex-

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About the authorsGEORGEO. SUMAN, JR., attended theCalifornia Institute of Technology andthe University of California (Berkeley),graduating with a B.S.M.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 Completion.Technology Co. which is actively work-ing with a number of client companies

in 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.

ample, retarded cement can be used on bottom, accel-erated cement on top and neat cement in-between. Pump-ing against the hydrostatic pressure of the cement columnis not required. However, volume to displace cement tobottom cannot be as accurately determined.

A tie-back stub liner is usually cemented after the sealnipple is landed in the tie-back sleeve and the tie-backliner hanger has been set. Cement is pumped and dis-placed down the drill pipe and liner with the liner wiperplug used to close a stage cementing collar located justabove the seal nipple. With cement in-place the liner run-ning tool is raised until the slick joint or tail pipe is clearof the tie-back liner top and excess cement is reversed out.

Job testing, evaluation. With cement in the casing, abit and casing scraper are used to drill out to the liner.Then a bit change is made to clean out cement inside theliner.

I t is usually desirable to pressure test the overlap tocheck the seal at the top of the liner prior to cleaning outthe float collar and/or float shoe. If the liner is notsealed, a cement squeeze is most easily applied at thistime. The overlap pressure tests may use applied internalpressure to create a differential toward the formation. Or,where high formation pressures exist, low density fluidinside the liner may provide sufficient differential towardthe borehole to indicate leakage. High differential couldbe assured by using a DST tool for the test.

Such differential pressure should be equal to or greaterthan the maximum differential expected during the re-maining drilling operation or during future productionoperations.

It may also be desirable to test the seal at the bottomof a drilling liner after the float shoe has been drilled out.The test of the seal at the shoe should be conducted at

55

Checklist for equipment, cementingmethod selection*

. Type of linerDrilIing, production or stub liner

. Float shoeFill-up or straight float typeWeight, grade and joint size

. Float collarFill-up or straight float typeSpacing above float shoeCombination landing collarWeight, grade and joint size

. LandingcollarRegular or combination with floatIs ball and seat test sub to be used to set hydraulic hangerSpacing above float collarWeight, grade and joint size

. Primary cementingaidsCentralizers or standoff devices should be compatible with

hanger setting equipmentExternally grooved pipe to reduce differential pressuresticking

. Liner selectionSizes, weight and gradeLengthJoint selection

. Size, weight, grade of suspending casing stringCasing wearSlip load distribution

. Type liner hanger to useMechanical or hydraulic setSingle or multiple slips (bypass area)Will rotation, reciprocation be performed during cementingHole geometryDoes hanger have to pass through top of another liner

. Provisions for future tie-back stringUse of setting collar only or tie-back receptacleLength of receptacle bore, 3 feet or 6 feetIf tie-back is completed, will liner hanger and receptacle

withstand maximum internal and external pressures ex-pected

Should the setting collar or tie-back receptacle be modifiedfor retrievable pack-off bushing

. Plug dropping head and cementing manifoldConnectionLatch-under type or handling sub pick-up typeIs ball dropping manifold required (for hydraulic-set hangers

and ball and seat test subs)Tell-tale for plug

. PlugsSize, weight of drill pipe operating stringShear pin rating of liner wiper plugDisplacement to shear wiper plugDisplacement volume to shear liner wiper plug and bump

plugs

. Cement recommendationsWeight, viscosity, thickening time, compressive strength,

fluid loss and loss circulation materialUse of bottom-hole temperature subs for information neces-

sary to slurry design

. ProcedurePre-cementing conditioningPump rateBottom-hole treating or break-down pressureSpacers, flushesDisplacement efficiency

. Post-cementing proceduresClean-out with mill or roller bitPreparations for completion

*After Lindseyl"

56

LINER WIPERPLUG

PLUGS lATCHEDTO COllAR

DRill PIPEWIPER PLUG

DRill PIPEREADY TO PUll

FLOATCOllAR(OPEN)

CEMENTING JOB COMPLETE

Fig. 63-Schematic representation of the typical liner cement-ing process. Liner hanging equipment is not shown (afterSmith).'"

a pressure equal to or greater than the highest mud weightexpected to be used prior to setting another liner or cas-ing. (See note about tests with low density fluids, DSTs).

In locations where well completion is conducted afterthe drilling rig is moved off, feed-back on success or fail-ure of production liner primary cementing is essential.Improved primary cementing will be realized when ac-curate information on the liner cementing technique andresults is communicated back to drilling personnel re-sponsible for design and implementation.

Coming in October: Remedial cementing, squeezing, otherspecialized applications.

LITERATURE CITED

". Davis, S. H. "Cementing Liners," Chapter 17, Oil Well Cementing Prac-tices in the United States, API, 1959.

141West, E. R., and Lindsey, H. Eo, "How to Run and Cement Liners inUltra-deep Wells," World Oil, June 1'966.

"2 Mahoney, B. J., and Barrios, J. R., "Cementing Liners .Through DeepHigh Pressure Zones," Petroleum Engineer, March 1974.

143Lindsey, H. E., "Running and Cementing Deep Well Liners," Three-partseries, World Oil, November, December 1974 and January 1975.

1« Lindsey, H. E., "Setting Liners in Shallow to Medium Depth Wells,"World Oil, May 1977. Also paper to Southwestern Petroleum Short Course,Lubbock, Texas, April 11377.

"s Covlin, R. .T., "Cementing Practices-Elk Basin Field," API Drilling andProduction Practices, 1968.

"6 API Bulletin D-II')', Running and Cementing Liners in the Delaware Basin,Texas, First Edition, December 1974.

141Tragesser, A., and Parker, F. W., "Using Improved Technology to ObtainBetter Cement Jobs on Deep Hot Liners," Preprint SPE 3891, April 1972.

"0 Shell, F., and Tra~esser, A., "API Is Seeking More Accurate Bottom Hole.Temperatures," 001 & Gas Journal, July 10, 1972.

..9 Lindsey, H. E., and Bateman, S. J., "Improve Cementing o( DrillingLiners 1U Deep Wells," World Oil, October 1973.

to. Carneu L. C., "Single Stage Spacer (or Deep Liner Cementing," Petro-leum l!.ngineer, June 1975.

'" Crowe, W. L., Griffin, T. J.J and Puntney, A. W., "Cement-Mud SpacerSystem Improves minois Welts," Drilline DCW, March 1977, pp. 33-34.

'.2 Moore, P. L., Drilling Practices Manual, The Petroleum Publtshing Co.,Tulsa, Okla., 1974, Chapter 16, "Cements and Cementing" by D. K.Smith.

153Lindsey, H. E., "Techniques for Liner Tie-back Cementing," PetroleumEngineer, July 1973.

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Cementing oil and gas wells

Part 7-A review of cementplug placement,

tubingless completion techniques and the

art and science of cement squeezing

George O. Suman, Jr., President, and Richard C. Ellis,Project Engineer, Completion Technology Co., Houston.

10 second summaryProblems and solutions associated with cement plug

placement, special methods for cementing small di-ameter, tubingless completions are discussed. Commonmisconceptions about squeeze cementing are correctedand recommended procedures are presented.

THIS ARTICLEdiscusses specialized cementing operationsand remedial cement squeezing. Special cement opera-tions covered are:

~ Placing of cement plugs in open hole or casing-bailer methods, balanced placement, use of wiper plugs,special slurry design

~ Cementing single or multiple tubingless comple-tions-displacement problems due to small diameters,how to avoid buckling, and

~ Use of a selective completion tool that isolates andprotects the pay zone.

The extensive analysis of squeeze cementing: Correctscommon misconceptions; applies the important principleof proper filter cake formation versus undesirable ver-tical fracturing; and describes methods and equipmentfor both high and low pressure squeeze cementing.

CEMENT PLUGS, PLACEMENT METHODS

A cement plug is a volume of cement designed to filla length of casing or open hole and provide a seal againstvertical fluid movement.154-156

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Cased hole cement plugs are usually placed to: Aban-don lower depleted zones; to plug and abandon an entirewell; or to provide a "kick off point" for sidetrackdrilling operations. Thru-tubing tools and techniquesare available that permit plug placement without pullingtubing and killing the well.157

Open hole plug back operations can be utilized to:Abandon the lower part of the hole; isolate a zone forformation testing; seal-off lost circulation zones; and/or

WIRELlNE

DUMP BAILER

CEMENT

ELECTRICAL/MECHANICALDUMP RELEASE

BRIDGE PLUG

CASING

Fig. 64-Dump bailer method of cement placement.Bailer of variable length is lowered on wireline. De-vice in bottom releases plate or opens ports todump cement on bridge plug or sand/gravel fill.

57

initiate directional drilling. (Lost circulation cementsare discussed in Part 3.)

Regardless of application, the primary problem withcement plugs is contamination of the cement with drillingmud or well fluids.158.159Placement control and cement

composition are critical due to the small volume ofcement normally used.

The dump bailer method is normally used in low pres-sure, cased holes at shallow depths, but it can be usedin deeper, higher pressure wells with thru-tubing tech-niques. Applications of this method are normally limitedto conditions where gravity displacement of well fluidby cement will readily occur.

In shallow low pressure wells, drilling mud is not re-quired as the well can be controlled with producedbrines or field water. Sand or gravel may be placed belowthe desired plug interval, or a permanent type bridge

SPACER

CEMENT

SPACERAND

PREFLUSH

~~,~ iilCONDITION MUD DISPLACECEMENT SPOT BALANCED PULL PIPE

ROTATEPIPE ANb FLUIDS PLUG SLOWLY

Fig. 55-Schematic of balanced plug method. All fluid volumesare carefully calculated so that hydrostatic pressure on plugin final location is identical in drill pipe and annulus.

DRILLPIPE

SEATSHEARED

TOP PLUGSEATED

CEMENTPLUG

BOTTOMPLUG

DISPLACINGCEMENT CEMENT RAISEPIPE,AND FLUID IN PLACE CIRCULATE

Fig. 56-Twoplug method for deeper wells or where displace-ment is difficult to calculate. Seat stops top plug to indicatewhen slurry is spotted. Pipe then is raised and additionalpressure shears seat to open pipe for circulation, or reversecirculation.

58

plug can be placed at the base of the plug-unless thewell is to be plugged from TD.

Cement is lowered in a dump bailer on a wireline anddumped on the plug, Fig. 64. Only limited volume canbe placed at one time and this must take an initial setbefore another batch can be dumped. In such appli-cations there is little problem with contamination; place-ment depth is easily controlled and cost is low.

The dump bailer has been used in open holes withlightweight drilling. mud present. Open hole inflatablebridge plugs can be used to bottom the plug above TD.

The balance method is most commonly used for plugplacement. Preflush, cement slurry and spacer fluid aredisplaced down the drill pipe with mud until cementlevel is about equal in annulus and drill pipe. The pipethen is pulled leaving the plug "balanced" in place, Fig.65. This procedure appears to be quite simple 'but failuresare not uncommon-and they are usually related tocontaminated cement. This method is used for both

cased and open hole plugs.

The two plug method is used for: Placing plugs at sub-stantial depths; where displacement volumes are difficultto calculate; and/or where cement volumes are small.The method uses a wiper-plug catcher in the bottomof the drill pipe which permits passage of bottom wiper-plugs but stops and seals the top wiper plug, Fig. 66.

Displacement volumes are measured, but when thetop plug reaches the catcher, the event is confirmed bya sharp pressure increase, and displacement is stopped.Drill pipe then is pulled slowly above the cement plug,additional pressure shears a pin in the plug seat andcirculation or reverse circulation can be established.

This method reduces problems that over or under-dis-placement can create with the balance method.

Recommendations that should reduce probability ofmud contamination and increase chances for successful

plug placement by balance or two plug methods arelisted in the accompanying table.

Sand filler. Some operators use sand to "improve" the"hardness" or "toughness" of a cement plug. Otheroperators specify that sand should not be used.

Unless well temperature exceeds 2300 F, fine sanddoes not react with cement (see Part 3-Strength Re-trogression). And compressive strength of cement atlower temperatures will decrease as sand concentrationsincrease. Neat cements that are densified with a disper-sant have the highest compressive strength. Thus, labtesting does not support use of sand to make slurries"harder." Yet operators who specify sand use in direc-tional plugs claim improved "hardness" and higher suc-cess ratios.

Sand may improve mud removal by some type ofscouring action and this could reduce mud contamina-tion. Thus, sand may affect hardness in a manner notrelated to a sand-cement reaction.

Cement slurries should be densified with dispersants,and sand (if used) should be angular rather thanrounded. Some operators prefer mixed sand sizes gradingfrom fine to coarse. Sand concentrations should notexceed 10-20% by weight of cement.160

Evaluate plug location, quality. In simple plug backs,

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How to minimize mud contaminationof cement plugs

. Select an in-gauge section of the hole to position the plug.A caliper log gives the most accurate evaluation, but drillingexperience in the area and mud loggin~ data can be valuableaids

. Condition mud prior to mixing cement. Circulate bottomsup, as a minimum, and move the drill pipe. Drill pipe shouldbe equipped with centralizers and scratchers to help removemud cake and/or reduce cement channeling

. Use preflush fluid ahead of cement-in some operationsthis can be water. Where chemical flushes are to be used, typewill depend on mud composition and density. Oil base mudspacer should be used where oil based muds are present. Withwater based muds the flush can be water with a mud thinningchemical; or if density is critical, a weighted water base mudflush can be used. Preflush volume should provide at least 150-200 feet of fluid in the annulus

*. Drill pipe wiper plugs can be used ahead of and behindboth preflush and cement. Wiper plugs ahead of the cement willbe pumped out of the drill pipe and the wiper plug behind thecement will remain in the cement near the top of the plug.

*. Use carefully calculated volumes of preflush and spacerbetween mud and cement to obtain equal height in annulusand drill pipe when displacement is complete.

. Use a dispersant additive to densify the cement slurry;17-18 ppg slurries can be prepared by adding 0.75-1.5% dis-persant to class A, G or H cements when mixed with lessthan normal water. These cements develop high early strengthand will tolerate a greater degree of mud contamination andstill develop adequate strength after necessary woe time. Athickening time of about 30 minutes in addition to a realisticplacement time is recommended

. Use adequate cement volume. Minimum vertical fill fordirectional or sidetrack operations should be 300 feet. Anticipatethat at least the top 50 feet of the plug will be contaminatedwith mud. It may be desirable to use excess slurry then pulltubing or drill pipe to desired location of plug top and reverseout the excess

. Batch mix cement or mix thoroughly through a ribbonblender, double pump-or simply mix slow enough-to assureuniform high density slurry

. After 2-3 barrels of cement clears bottom of drill pipe,pick up 10-15 feet to reduce exposure of cement to mud belowthe plug

. Continue to rotate drill pipe until cement displacement iscomplete to reduce chance of cement channelin~ through mudin the annulus. Once cement is spotted, avoid rotation untilpipe is pulled above the plug.

* For use only with balance method

4-6 hours may be adequate before setting down on theplug to check its position. In directional work, 8-16 hoursor more may be required. Provide adequate WOC time.

When drilling a directional plug, check cuttings forpremature drillout. If the cuttings are sharp edged andangular, cement has set properly. Subrounded or ballshaped cuttings indicate drilling is premature and ad-ditional WOC is recommended.

Usually after 24 hours, inadequate set is an indicationof serious contamination and the plug should be drilledout and replaced.16l Where conditions permit, an alter-native is to place another plug above the first.

TUBINGLESS COMPLETIONS

In so-called tubingless completions, one or more tubingstrings are run and cemented in the borehole to serveas both casing and tubing. Almost all equipment usedin cementing conventional casing strings is available forcementing these small diameter tubulars-including:

WORLD OIL 1977

SMALL DIAMETERCASING

Fig. 57-Possible irregular geometric arrangements ofsingle or multiple strings in tubing less completionscauses inefficient displacement of mud by cement.

Guiding equipment, float shoes and collars, multiplestage cementing collars, centralizers, scratchers (rotatingand reciprocating), cement baskets and packers orbasket-type shoeS.162-164

Several cementing problems that are particularly signif-icant in the case of tubingless completions are:

1. Due to close tolerances of downhole completion/productionequipment in the small "casing," buckling of the strings cancreate serious problems

2. Mud displacement is more difficult due to irregular geom-etry and lack of turbulent flow,' '.. and

3. Drill-out can be more difficult. This is. commonly avoidedby placing baffles or float collars below zones to be perforated.In addition, special precautions are taken to avoid pumpingexcess cement on top of the upper plug.

Casing buckling is a great concern to operators utiliz-ing tubingless completions. Special precautions used toprevent buckling include leaving pressure on the stringswhile cement sets to impart additional tensile loadingwithin the cemented interval, or pulling additionaltension on the string after the initial cement set to addtensile loading above the cemented interval,166

Efficient mud displacement is difficult due to the ir-regular geometry, Fig. 67, and lack of turbulent flow.However, successful cementing operations have beenachieved165-161 by emphasizing: Casing centralization;pipe movement; increased displacement rate (by pumpingthrough more than one casing string); relative rheolog-ical properties between mud and cement (yield pointand density); and use of cement slurries having dilatantrheology, i.e. viscosity increases with shear rate. Effectiveuse of preflushes is also important.

Types of pipe movement critically analyzed in theabove noted references were rotation or reciprocation(or simultaneous rotation and reciprocation) of singlestrings, and reciprocation only of multiples strings (ro-tation of multiple strings may wind the strings togetherand cause restrictions). "Prudent" use of wire loop typescratchers served to break up gelled mud and createflowstream disturbances to aid displacement-not toremove mud filter cake.

The conclusion was that pipe movement by either

59

1

SHEAR RATE (FLOW)

Fig. 68-Four time-Independent rheological fluid characteristicsin isothermal, laminar flow.

reciprocation or rotation is effective. However, simul-taenous rotation and reciprocation desirable for conven-tional completions was not economic for 2%-inch tubing-less completions in 7'Vs-inch hole.167

Multiple casing strings have been cemented by pump-ing down only the longest string. A variation of thismethod is to spot cement through the longest stringthen lower other bullplugged strings through the unsetcement. Such a "delayed setting technique" requirescareful planning.

Pumping through more than one string can improveresults by increasing displacement rate. When two stringsto be cemented are located at the same depth, they maybe pumped into simultaneously. When the strings areat different depths, initiation of mixing and pumpingcement into each string must be staggered. Occasionally,a string which could be landed at a shallower depthis run to bottom to increase flow velocity by decreasingannular cross sectional area.

Rheology design. Efforts have been made to improverelative rheologic properties between mud and cement,i.e. yield point and density. Before cementing, if cir-cumstances require and permit, mud returns can bewatered back during the entire circulation period tolower mud weight, yield point and plastic viscosity.This increases the difference between flow properties ofmud and cement. An extensive study utilizing a specialcomputer program indicated that for 2%-inch tubing in7%-inch hole, most desirable mud properties for maxi-mum displacement efficiency was a plastic viscosity equalor less than 12 centipoise, and yield point equal or lessthan 5 pounds per 100 square feet.166

Use of cement slurries having dilatant rheology wasshown to be more favorable for mud displacement ef-ficiency.166 Due to the large annular space and limitedconduit size, fluids in the annulus are almost always inlaminar flow.

Four possible time-independent isothermal rheologiesof fluid exhibiting stable properties in laminar flow are:

60

Bingham plastic fluids; pseudoplastic fluids; dilatantfluids; and Newtonian fluids, Fig. 68. Bingham plasticand Newtonian fluids are discussed in Part 4. Water isa Newtonian fluid, and water suspensions of finely dividedsolids, gelled drilling muds and gelled Class H cements(Fig. 69) are Bingham plastic fluids. In the case of Bing-ham plastic fluids, a finite shear stress and shear rate areproportional in the laminar flow region.

Shear stress and shear rate of pseudoplastic fluids arenot proportional, i.e. viscosity decreases with shear rate(shear thinning). An example would be hydroxyethylcellulose (HEC) based completion fluids. Such fluidscan be non-thixotropic and should be readily displacedby cement.

For dilatant fluids, Fig. 68, shear stress and shearrate are also not proportional, and viscosity increases withshear rate. This feature increases displacement forces act-ing on the narrow side of an annulus and on gelled mud.These fluids, therefore, increase mud displacement ef-ficiency in the laminar flow region.

The extreme differences between rheological typesnoted above apply only to laminar flow. Turbulent flowwould tend to reduce the magnitude of these compar-isons. However, turbulent flow in single and multiplestring tubingless completions is unlikely.

SELECTIVECOMPLETION TOOL

One special equipment item which eliminates severalpossible restrictions to flow or production from the for-mation and provides unusual production or stimulationflexibility is the Selective Completion Tool developedby Gearhart-Owen Industries (see article "New com-pletion technique keeps formation faces clean," WORLDOIL, November 1973).

This tool consists of inflatable packers, a cement by-pass arrangement and sliding sleeve port-type collars runas an integral part of the casing string, Fig. 70. Afterrunning casing to bottom, the equipment is properlypositioned downhole with respect to the productive for-mation using a gamma ray log for correlation. The inflat-able packers are expanded by increased mud pressureafter the bottom plug seats on the baffle or collar.

The bottom packer then diverts flow of primary cementfrom the casing-wellbore annulus into the tool's by-passarea, from which the slurry re-enters the annulus above

t(f)

13a:I-(f)a:iIiJ:(f)

_ CLASS H PLUS GEL0--0 DENSIFIED CLASS H0-0 1-1 LlGHlWEIGHT-CLASS H

2-1 LlGHlWEIGHT-CLASS H

1200F~ "i£

/.~

SHEAR RATE-

Fig. 69-Rheology of four types of cement slurries. ClassH plus gel (straight line) is a "Bingham plastic" fluid, allothers exhibit "dilatant" properties (after Clark andJenkins).'..

WORLD OIL 1977

the upper packer. Tool length can be extended to 100feet or more by adding modules. And more than one unitand sliding sleeve may be run at one time.

Cement does not contact the weIlbore through theproductive formation. And flow restrictions associatedwith perforations are avoided, i.e. perforating debris andconvergence of flow within the formation towards per-foration tunnels.

Production or stimulation treatment flow is established

through one or more of the sliding sleeve port-type collarswhich can be repeatedly opened or closed by a me-chanical shifting tool run on pipe or wireline. By placingsuch a collar just above the lower packer and anotherjust below the upper packer, stimulation fluids may becirculated in the annulus across the productive zone toremove mud-caused impairment.

Ports may be opened or closed by wireline for testpurposes, or to shut-in a zone. Equipment is availablefor use in sand control.

In some cases, greater than normal casing to boreholeclearance is required. And certain components may haveto be custom made for specific applications.

'REMmIAL SQUEEZE CEMENTING

Squeeze cementing is the process of forcing a cementslurry through holes in the casing. The primary objec-tive of squeeze cementing is to develop a seal in the cas-ing-wellbore annulus between formation intervals pene-trated by the casing. The most common purposes forsqueeze cementing are to:16B

. Repair a primary cement job that failed due to cementby-passing mud (channeling) or insufficient cement height (fill-up) in the annulus

. Eliminate water intrusion from above, below, or within thehydrocarbon producing zone

. Reduce the producing gas-oil-ratio by isolating gas zonesfrom adjacent oil intervals

. Repair casing leaks due to corrosion or split pipe

. Plug all, or part, of one or more zones in a multizone in-jection well to direct injection into desired intervals, and

. Plug and abandon a depleted or watered-out producingzone.

Squeeze cementing can 'be classified as high pressureand low pressure. And two techniques used are: Braden-head squeeze and packer squeeze. These classificationsand techniques will be discussed later in the article.

Misconceptions. Techniques and technology of squeezecementing have been developed over a period of morethan 40 years,169 and later operations have proven thatsome early concepts were incorrect. Yet many applicationsare still based on these misconceptions. For example, somepeople erroneously assume that:

I. Cement squeezed through holes (perforations) in casingunder high pressure generally forms a horizontal cement "pan-cake" opposite the holes, thereby developing a barrier to verticalfluid movement

2. Injecting drilling mud into perforations at high pressureopens all perforations

3. High final squeeze is a positive indication of a successfuljob, and

4. In zones with good permeability, cement penetrates theformation without fracturing.

The fundamental concept of squeeze cementing isthat cement filter cake forms the initial seal.

A cement slurry consists of finely divided solid par-ticles dispersed in liquid. Such particles in the slurry

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INFLATION VALVE

_INFLATABLE PACKER

ANNULAR BYPASS

SLIDING SLEEVE

I-INFLATABLE PACKER

-INFLATION VALVE

Fig. 7o-Selective completion tool features two inflat-able packers that straddle and isolate the pay zone.Cement circulates through the tool's internal bypassand re-enters annulus above the upper packer. Slidingsleeves then can be opened to expose inside of cas-ing to the isolated formation. Tool length can be varied(courtesy Gearhart-Owen Industries, Inc.)

cannot be displaced into normal formation permeabilityas it would require permeability in excess of 100 Darciesto allow a normal slurry to penetrate a sand formationwithout fracturing.16B Therefore, when slurry is forcedagainst a permeable formation, the solid particles willfilter-out on the formation face as filtrate is forced into

the formation permeability.The filter cake has much lower permeability than most

sand formations. And as cake forms on part of theformation, slurry can be diverted to other exposedformation permeability. A properly designed squeeze jobwill cause dehydrated cement filter cake to fill the open-ing(s) between the formation and the casing. And, ifallowed to cure, the dehydrated cement filter cake willform a nearly impermeable solid.

In cases where slurry is to be placed in a fracturedinterval (either natural or induced) the cement solidswill have to develop a cake on the fracture faces and/orbridge the fracture.

Most successful squeezes in fractured formations haveused a staging technique in which a highly acceleratedslurry, or a slurry with bridging agents such as gilsoniteor sand, is followed by a second stage of moderate fluid

61

loss slurry. This system encourages bridging and filtercake development and helps divert movable slurry tounsealed fractures.

Fluid loss control. As noted above, the successfulsqueeze must deposit cement filter cake in openings be-tween casing and formation.110 To achieve this it maybe necessary to control cement fluid (filtrate) loss. If fluidloss is uncontrolled, cement may dehydrate and bridgeoff the upper portion of a perforated interval beforeslurry is displaced to the lower perforations, Fig. 26,Part 3. Conversely, very low fluid loss can result invery slow filter cake development and unacceptably longplacement operations.

Key factors that affect rate of filter cake growth are:Slurry properties (fluid filtrate loss and water-to-solidsratio) ; formation characteristics (permeability, pore pres-sure and fracture pressure); and squeeze pressure (dif-ferential between downhole slurry pressure and forma-tion pore pressure).

And, of course, fluid loss and filter cake growth ratevary directly, i.e. a slurry with a high fluid loss willhave a fast filter cake build-up.

The composition of a squeeze slurry should be basedon characteristics of the formation opposite the inter-val(s) to be squeezed, and techniques to be used. Informations with unimpaired natural permeability, slurrywith a water-to-solids ratio of 0.4 (by weight) and a lowfluid loss of 50-150 cc in 30 minutes under 1,000 psidifferential should provide satisfactory caking for most"low-pressure" squeeze jobs.l11

Slurry fluid (filtrate) loss can be varied and controlledas required, over the wide range of temperature andpressure conditions normally encountered in oil and gaswells, with various cement additives112 (Part 3). The

WELLBORE, FRAC. PRESS., P F

VERTlCALSTRESS, "y

HORIZONTAL

STRESS, "HI

I II I

I J~___~_ -... ,

INDUCED HORIZONTALFRACTURE

INDUCED VERTICAL

FRACTURE

PF~"HI or "H2

"HI or "H2<"y

Fig. 71-Effect of well depth and vertical-horizontalformation stresses on type of hydraulic fracture in-duced by injected fluid. Horizontal fractures will notbe created if fracture pressure is less than overburdenpressure, this is usually the case at depths greater than3,000 feet.

62

important factors are rate of deposition and amount offilter cake deposited. Slurry solids content affects timerequired to develop cement cake and time required foradequate dehydration at a given fluid (filtrate) loss.

When squeezing against shales, dense limestones, dolo-mites-or permeable formations where natural permea-bility is plugged with mud-a low fluid loss cement maynot be desirable. In these situations a "high-pressure"squeeze job is usually performed and low fluid loss slurrycould be undesirable' because its restricted filtrate loss

could inhibit filter cake development.16DThus, squeeze pressure, time and slurry composition

are the primary controllable variables. However, thesefactors also are functions of formation character and

type of fluid in the well, i.e. drilling mud or "clean"workover fluid.

HIGH PRESSURE SQUEEZING

High pressure squeeze cementing is defined as a jobin which fluid pressure in the wellbore exceeds formationfracture pressure prior to or during the time that cementslurry is in contact with the formation. High-pressuremethods are recommended only when squeezing relativelyimpermeable zones or where the squeeze is to be con-ducted with drilling mud in the hole.

Fracturing of the formation permits displacement ofmud or work over fluid through holes in the casing. Theslurry then displaces this fluid into the fractures, permit-ting development of cement filter cake on the fracturesurfaces.

Where the previously-cemented annulus contains fluidor mud filled channels, fracture initiation may occuranywhere along the length of the channels-above orbelow the perforations. After fracturing, cement dis-places and follows fluid from the channels into the frac-ture and cement is deposited in the channels betweenperforations and the fracture initiation point.

Since it is likely that perforations will be at an inter-mediate part of any channels, only that part of the chan-nels between the perforations and the fracture initiationpoint is filled with cement. Use of the hesitation tech-nique under these circumstances may develop additionalfractures and a more effective cement seal. More details

on hesitation squeezing are presented later in this article.

Potential Problems. With high-pressure squeezes thereis no contrQl of either location or orientation of the

generated fracture. The fracture will be oriented per-pendicular to the least principal stress as shown in Fig.71. Note that horizontal fractures will not be created if

fracture pressure is less than overburden pressure.Formation fracturing during high-pressure squeezing

may be counter-productive, as fractures induced in for-mations deeper than 3,000 feet are nearly always vertical.Thus, even if the casing-wellbore annulus is sealed, verti-cal communication between zones may be established inthe fracture. Horizontal fractures containing cement"pancakes" cannot be generated by high pressure squeezecementing in deep wells.l11

Once a fracture is created it must be sealed-off with

cement, particularly if it is vertical and extends into azone being isolated. However, sealing-off the fracture maybe difficult because fracturing is usually initiated withmud, and attempts to purge the fracFures may only extend

WORLD OIL 1977

them. Thus, the necessary volume of cement can be large.It is not unusual to use 100-500 sacks on a high-pressuresqueeze job. Such problems with mud-filled fractureshave been minimized by using a high-fluid-loss fluid(water) for breakdown. Where mud is needed for control,such fluid is spotted before setting the packer. Afterbreakdown, cement is circulated into place for squeezing.

Another problem in a perforated interval is that mud-filled perforations can withstand large pressure differen-tials, especially toward the formation. And, all perfora-tions may not be forced open when the formation is frac-tured by the high pressure. In fact, the most commoncause of squeeze cementing failures is .attributed to theunplugging of mud-plugged perforations after the squeezejob.

Generally, it is recommended that solids-free workoverfluids be used whenever fluid has to be displaced into theformation ahead of cement. Acid or chemical washes can

also be used ahead of the slurry. Several clean-up tech-niques and chemical wash formulas are presented in theliterature.173-177

LOW PRESSURE SQUEEZING

Low pressure squeeze cementing is defined as a job inwhich fluid pressure in the wellbore is maintained belowfracture pressure of exposed formations prior to, andduring, the time slurry is in contact with the formations.In practice, "safe" squeeze pressure is usually specified assome value below established fracture pressure (300 psihas been used in some areas).

Low pressure squeeze cementing175 utilizes a small vol-ume of low fluid loss sl urry placed against exposedpermeable formations with a moderate squeeze pressure.Filtrate from the slurry is forced into formation perme-ability allowing build-up of cement filter cake. Low fluidloss reduces dehydration rate and discourages bridgingas the slurry is forced along openings or channels.

In low pressure squeezes, perforations and channelsmust be clear of mud or other solids. If the well has been

on production, such openings may have been purged. Ifthe job is to be performed through new perforations, re-sults may be enhanced by perforating in a solids-free,non-damaging fluid-such as filtered brine to prevent clayswelling-with pressure underbalance to permit purgingof perforation cavities. In existing perforations pressure/suction washing with or without acid may be considered.

Procedure. In practice, the low pressure squeeze job isgenerally conducted as follows:

1. Initiate injection. Determine downhole injection pressure

2. Circulate slurry to desired location in the casing

3. Apply moderate squeeze (downhole) pressure. Considerincreased hydrostatic effect of cement column

4. Restore squeeze pressure by engaging the pump as bleedoffoccurs. (Note: During steps 2 and 3, cement filter cake isdeposited in perforations or holes)

5. Gradually increase downhole pressure to 500--1,000 psiabove pressure required to initiate flow. When bleed-off ceasesfor about 30 minutes, stop displacing cement slurry and hold thepressure. Do not exceed "safe" squeeze pressure. Successfulsqueeze jobs are routinely obtained with only one or two cubicfeet of cement displaced through the perforations.

6. Reverse circulate excess cement from casing, or pull workstring leaving cement to be drilled out later, if necessary.

A properly designed slurry will leave only a small

cement filter-cake bump (node) inside the casing aftercirculating out excess slurry. Improperly designed slurries

WORLD OIL 1977

FLUID LOSS

(ML/30 MIN. AT 1,000 PSIIlP)

CEMENT NODES

15

800

150

6" CASING- 50

PERFORATIONS

Fig. 72-Schematic of cement filter cake node building after45 minute squeeze with various fluid (filtrate) loss properties,(after Rike).173

can result in excessive caking with enlarged nodes, orinadequate caking and inability to hold pressure, Fig. 72.

The casing can be left with cement nodes small enoughthat drilling-out is not required. And the ability to reverseout excess cement in many applications makes low pres-sure squeezing compatible with "thru-tubing" tech-niquesY6

SQUEEZE TECHNIQUES

Squeeze cementing in permanent and tubingless com-pletions requires some special precautions but basic tech-niques are similar to those used in conventional wells. And,for the most part, only low pressure squeeze jobs are at-tempted.

A permanent completion is one in which tubing andwellhead remain in place during life of the well. Squeezecementing in these wells can be performed with concentricsmall diameter tubing. Thru-tubing tools such as inflatablebridge plugs and packers have been developed to be runon wireline or small diameter tubing strings to permitconventional, small scale squeeze cementing operations.

Squeezing through small concentric tubing uses verysmall slurry volumes which are susceptible to contamina-tion by fluids in the casing and in the tubing-tubing an-nulus. Therefore it is particularly important to maintainaccurate volume control of all fluids pumped into thewell to assure proper slurry placement.

The hesitation squeeze is a subclassification of squeezecementing that can be used in either high or low pressureapplications. The principal aspect of the technique isalternate pumping and hesitation (not pumping). Thehesitation is to encourage cement filter cake buildup.

Hesitation procedures are much more of an art thana science, as hesitation time and pressure change duringpumping and waiting are observed, and varied, based onexperience. The alternating of pumping and hesitation arecontinued until the desired final squeeze pressure is ob-tained, 171 Fig. 73.

The Bradenhead squeeze technique normally is usedon low pressure formations. Usually the interval to besqueezed is at or near the bottom of the well.

The general procedure, as illustrated in Fig. 74, includes

63

BLED PRESSURETESTED

BACKFLOW

20 40 60

TIME, MINS.

Fig. 73-Example of hesitation squeeze technique shows al-ternate pumping and hesitation to allow cement filter cakeformation and gradual buildup to desired squeeze pressure(after Beach et al).'"

these steps: Circulate cement across zone to be squeezed;pull drill pipe (or tubing) above the perforations; closeblowout preventors (or shut off flow from the annulus)

and apply pressure to drill pipe or work string to forceslurry to dehydrate against the formation; reverse outexcess cement in the work string and casing, or let cementset, and drill out as required.

Squeeze pressure is limited by casing string and well-head burst strength, so the Bradenhead technique is nor-mally used with a low pressure squeeze. It is not a precisecement placement technique and is not generally recom-mended when there are several open intervals and onl}one is to be squeezed, or where casing is not pressure tightabove the zone to be squeezed.

Packer squeeze techniques permit precise slurry place-ment and isolate high pressure from casing and wellheadwhile high squeeze pressures are applied downhole. Apacker squeeze can be conducted with either drillable orretrievable squeeze packers. Wellbore fluid below thepacker is usually displaced through perforations ahead ofthe cement when this method is used. Dirty fluid mayblock flow of cement to a portion of any exposed perme-ability.

In the past, main advantages of a drillable packer orretainer, over a retrievable packer, were that it preventedbackflow and disruption of the filter cake and providedthe ability to isolate perforations from circulation pressuresabove the packer. With new technology, these capabilitiesare available with some retrievable cement retainers, andthey can be of particular -advantagewhen it is necessarytoremove the packer from the wellbore after squeezing.

Retrievable packers can be set and released repeatedlyon a single trip, as may be required to locate holes in thecasing. When retrievable packers are released, differentialpressure from the formation must be controlled to preventback-flow and cement filter cake disturbance. Generallythe retrievable packer is less expensive to run; and lessrig time is required if cement is to be drilled out.

Many accessories have been developed for use with theretrievable squeeze packer, such as retrievable bridge plugsthat can be run below the squeezepacker and set at anypoint below the packer. The retrievable bridge plug willhold pressure from either above or below.

64

Although this isolation technique is most always re-quired for high pressure squeeze jobs it can be effectivelyused on low pressure squeezes where accurate cementplacement is desired. And, with a low pressure squeeze,it is possible to run and retrieve the bridge plug on thesame trip with the retrievable squeeze packer. It is alsopossible to squeeze multiple zones on the same trip withthis equipment. However, as mentioned earlier, differen-tial pressure between casing and formation must be con-trolled to prevent displacement of unset cement filter cake.

Drillable packers can be obtained with either of twovalve systems. The "poppet" type back pressure valve willprevent back-flow only. The "two-way" valve will retainpressure from either direction and closes when drill pipeis pulled above the packer. The two-way valve systemmakes it possible to reverse circulate any excess cementfrom the drill pipe without exerting pressure below thepacker. Drillable packers can be set on tubing or drillpipe, and by electric (logging) line.

The choice between drillable or retrievable packers isprimarily dependent on well conditions and squeeze tech-nique. Details on specific capabilities of either type shouldbe obtained from the service company or manufacturer(supplier) .

Packer location should be carefully considered and mayvary depending on the type job. If set too far above

'I

REVERSECIRCULATE

APPLYSQUEEZE

PRESSURE

Fig. 74-Schematic of Bradenhead squeeze technique normallyused on low pressure formations. Cement is circulated intoplace down drill pipe (left), then wellhead, or BOP, is closed(center) and squeeze pressure is applied. Reverse circulatingthrough perforations (right) removes excess cement, or plugcan be drilled out.

SPOTCEMENT

WORLD OIL 1977

Ci5 2,0000-ur!5 1,600

fdg: 1,200w()

800II:::>rn

400

00

perforations or holes to be squeezed, excessive volumes offluid-either workover fluids or mud-must be displacedinto the formation ahead of the cement, or the slurry maychannel through the mud, Fig. 75. Conversely, a packerset too close to perforations or holes could become stuckif pressure on the outside of the casing is transmittedabove the packer and causes the casing to collapse.

It is desirable to test and then maintain some pressureon the casing annulus above the packer. Observation ofthis annulus pressure can be effectively used as a checkfor leaks in the squeeze string, packer or casing. Annuluspressure can also be used to prevent collapse pressuresfrom developing during high pressure jobs.

Usually, the packer should be set 30-60perforations. If corrosion holes or split pipesqueezed, more space is recommended.

feet fromare being

Final squeeze pressure. Thirty (or more) years agowhen squeeze cementing was more art than science, highfinal squeeze pressure was one primary indicator used tomeasure success. However, high final pressure may occurbecause dehydrated cement has bridged-off the casing orperforations. And mud cake filled perforations are alsocapable of withstanding high differential pressure, par-ticularly in the direction of the formation. Thus high finalsqueeze pressures can be achieved where the squeeze isunsuccessful.

Job evaluation. Proof of a successful squeeze is the with-standing of differential pressure between casing and for-mation after the well is returned to operation, either pro-duction or injection. However, it is usually desirable totest the squeeze job before removing the work over ordrilling rig.

Differential into the wellbore may be obtained by swab-bing or displacing workover fluid with field crude.

In some production wells it may be impractical tounload the wellbore without returning the well to pro-duction. In these cases a positive pressure test that doesnot exceed formation fracture pressure should be con-ducted after cement has set and, if required, after drill-out. Even though it is not conclusive, pressure testing canbe relatively quick and inexpensive to perform. It maydetect a job failure, and, in most cases, less effort andexpense are required to repeat the squeeze operation atthat time. Procedures for evaluating cement jobs will bediscussed more fully in the next article.

In squeeze jobs where cement is to be drilled out, anindication of success is the way the cement drills. If itdrills hard all the way, results may be good. However,soft spots or voids usually indicate an unsuccessful job.161

Remedial squeeze cementing techniques and technologyprovide a wide variety of "cures" for problems related tofluid movement behind the casing and/or in the wellbore.However, prevention-where possible-is a more effec-tive, less expensive solution than squeeze cementing.

Squeeze cementing is a remedial tool. It should not beused as a planned supplement to primary cementing. Forexample, careful design and execution of primary cement-ing is a much better way to get zone isolation than relyingon high-pressure "block squeezing" above and below thepay. As mentioned, high pressure block squeezing mayactually aggravate communication between zones.

Coming next month: Defining the problem to be "cured"

WORLD OIL 1977

CASING

PACKER

CEMENTCHANNELLED

THRUMUD

MUD

Fig. 75-Packer location is important. In this example,packer is set too high allowing cement slurry to becontaminated as it channels through mud to reachperforations or holes (after Shryock and Slagle).'68

by squeeze cementing is likely the most important ruleof preparation. Many diagnostic tools and evaluationprocedures that can be used to gain an understandingof downhole conditions before and after squeezing, orafter primary cementing, are discussed in the concludingarticle, along with some recent cementing innovations.

LITERATURE CITED'M Parsons, C. P., "Plug-back Ce1l1enting Methods." AIME Trans. Vol. 118

(1936). .,.. Goins, W. C., Jr., "Open hole plug-back Operations," Oil Well Cement,ng

Practices in tne U.S., API, 1'959.,.. Mont/5omery, P. C. and Smith, D. K., "Oil Well Cementing Practices and

Mater.als," Petro Engr., May_and June, 1'971.'" Fischer, J. S., Wadder, F. V. and McGuirel,. J. A., "hn.proving Production

with Electrical Workover System," Paper SrE 24114,1969.... Beach, H. J. and Goins, W. C., Jr., "A Method of Protecting Cements

Against the Harmful Effects of Mud Contamination." AIME Petro Trans.Vol. 210, 1957.

". Morgan, B. E. and Dumbauld, G. K., "Use of Activated Charcoal inCement to Combat Effect. of Contamination by DrilIing Muds."

160Banister J. A., "Methods and Materials for Placiny Cement Plugs inOpen Holes," Presented at the National Interstate Oi Compact Commis-sion's Convention, Yellowstone Wyo., June 11957.

'0' Murphyl,. W. C., "Squeeze Cemenunj! Requires Careful Execution forProper Kemedial Work," Oil & Gas Journal, February 1976.

'0' Buster, J. L., "Cementing Multiple Tubingless Completions," API Drillinlland Production Practice, 1965, pp. 15-23.

.03Willingham, J. E., "Experience with 2-%" Casing in the West Texas-New Mexico Area," API Drilling and Production Practices, 1963, PI'. 64-71.

164Scott, R. W., "Small Diameter Well Completions," Engineering PracticesManual No.4, Reprinted from World Oil, 1963.

,.. Childers, M. A., "Ptim"ry Cementing of Multiple Casing," Transactionsof AIME, Volume 243, 1968.

'00Clark, C. R. and Jenkins, R. G., "Cementing Practices for Tubin!!lessCompletions" SPE Paper 4609 Presented at the 48 Annual Fall MeeUng,Las Vegas, Sept. 30-0ct. 3, \973.

16'Holley, J. A., "Field Proven Techniques Improve Cementing Success,"World 0,1 August 1976, PJI. 31'-33.

,.. Shryock, S. H. & Slagle, K. A., "Problems Related to Squeeze Cementing,"/PT, August 1968.

169Torr~y, P. D., "Pr~Kress in Squeeze Cementing Application and Technique"Oil Weekly, July 29, 1940. ..

110Hook, F. E., and Ernst, E. A., "The Effect of Low-Water-Loss Additives,Squeeze Pressure and Formation Permeability on the Dehydration Rate ofa Squeeze Cementing Slurry," Paper SPE 2455. Presented at the SPERocliy Mountain Regional Meeting, Denver, May 25-27, 1969.

m Beach, H. J., O'Brien, T. B. & Goi~1 W. C'I J!;..o "Controlled FiltrationRate Improves Cement Squeezing," world Oi, May, 1961.

m Binkley, G. W., Dumbauld, G. K. & Collins, R. E., "Factors Affectingthe Rate of Deposition of Cement in Unfractured Perforations DuringS~ueeze Cementing Operations," Paper SPE 891'-G, 1957.

'" Rike, J. L:t "Obtaining Successful Squeeze-Cementing Results," PaperSPE 4608, 1~73

m Carter, L. G. et al., "Remedial Cementing of Plugged Perforations,"Paper SPE 759, 1963.

116Morgan, B. E. & Dumbauld, G. K.; "Bentonite Cements Proving Suc-cessful in Permanent-Type Squeeze O{)erations."

116Huber, T. A., Tausch, G. H. & DublIn, J. R. III~ "A Simplified Cement-ing Technique for Recompletion OperatIOns." AIME Transactions, Vol.WI, 1954.

'" Harris F. and Carter, G.~ "Effectiveness of Chemical Washes Ahead ofSqueeze Cementing," API raper 85'1-37-H, 1963. .

65

Cementing oil and gas wells

Part 8-Methods for evaluating primarycementing effectiveness plus a wrapupof several new tools to improvecompletion operations

George o. Suman, Jr., President, and Richard C.Ellis, Pro jec t Engineer, Completion Technology Co.,Houston

10-second summaryBasic principles of temperature logging. bond logging

and various tests for proving fluid shut-off by primarycementing are described, along with three new tools forcompletion, through-tubing work and whipstock installa-tion.

THIS CONCLUDINGarticle discusses several methods of

evaluating the effectiveness of a primary cement job, ora remedial squeeze. The techniques include logging meth-ods-to determine factors such as cement height, thick-ness, bonding or possible mud channeling-and variouspositive performance tests such as pressure tests, perfor-ating and bailing, and production and/or productionlogging tests, to prove whether the job accomplished itsintended purpose.

Also discussed are several recently introduced down-hole tools that are closely associated with cementing op-erations. These include:

~ The new Pack/Perf Completion system that pro-vides positive isolation and formation support throughthe perforated interval

~ A new through-tubing, inflatable bridge plug that

can simplify plug back operations in casing, below thetubing string, and

~ A permanent packer arrangement for positivelyanchoring a whipstock tool. The system can cut costsand eliminate cement plug placement problems, in this

application.

66

60u..o

40

20

2 3

CEMENT SHEATH THICK., IN.

Fig. 76-Lab tests of various cement thicknesses with Insulat-Ing and non-insulating material simulating surrounding forma-tion Indicate that temperature rise Inside casing from settingcement can vary significantly with rock thermal dlffusivityproperties (after Gretener).180

EVALUATION TECHNIQUES

Evaluation of primary cementing is usually based onone of the following basic failure definitions: Cementfailed to fill the casing-borehole annulus above the mini-mum acceptable cement height; it failed to provide aseal at the casing shoe (or at the top of a liner), or itfailed to provide effective isolation of the zones of in-terest.

When any of these failures are detected, squeeze ce-menting remedial operations are usually required. A num-ber of evaluation techniques are available, including:Temperature surveys; radioactive logs; pressure tests;acoustical cement bond logs, and production testing andproduction logging.

Temperature surveys are used to detect maximumheight of cement in the casing-wellbore annulus.178.119Reasonably accurate in this application, such surveyscannot determine cement quality, or effectiveness in pre-venting vertical fluid migration.

The method consists of running a recording thermom-eter in the casing following the cementing operation.Setting cement generates "heat of hydration" which in-

WORLDOIL 1977

ENLARGEDHOLE SECTION

)

C

-

Fig. 77-ldealized temperature log in homogeneous lithologyenvironment. Curve C compared to Curve B illustrates effectof enlarged borehole with corresponding increased cementthickness (after Folmar).179

240

200 ,--12,000 FT TEST

11.o 160

Ii~WI- 120

80~ f4,000 FT TEST

SLURRY TEMP.___ APPARATUS TEMP.

o 2 3 5 64

TIME, HOURS

Fig. 78-Cement temperaturedevelopmentwith time as afunction of well depth is indicated by lab results in a simulatedwellbore apparatus preheated to temperatures of various depthlevels. Tests show 800 F slurry first cools fluid inside casing,then maximum temperature develops several hours afterplacement. Temperature rise is greater in higher temperatureenvironment (after Farris).'"

creases the temperature of adjacent fluid in the casingby several degrees.

Maximum temperature anomalies may be expectedto range from 10-40° F, Fig. 76.180 The magnitude ofthe anomaly will depend on thickness (or mass) ofcemen t behind the casing, as well as the thermaldiffusivity of surrounding formation. Where lithology isfairly uniform, the temperature log will indicate relativethickness of cement behind casing,179 Fig. 77. Calipersurveys can be particularly helpful in analyzing the tem-perature survey. If a hot area is noted where there isno hole enlargement, cement has invaded the formationthrough fractures or a thief zone. If the indicated ce-ment top is higher than calculated, cement channelingshould be suspected.

To locate the cement top, the temperature surveyshould begin either at the surface or at least 1,000 feet

WORLD OIL 1977

above the expected top. It is desirable to run the surveyat 50 F per inch sensitivity under normal conditions.And well conditions must remain static from the time

the plug is bumped until the survey is completed. Cau-tion should be observed when mixed lithologies (sand,shale, limestone, dolomite, salt, etc.) are present becauseit is possible to misinterpret.a lithology change as a ce-ment top. In these areas it is advisable to run a base logprior to running casing, to avoid possible erroneous in-terpretations.

The rate at which temperature changes depends ontemperature to which the cement is exposed. This isusually a function of depth of the cement job, Fig. 78.181Peak temperatures often occur 4-12 hours after start ofmixing operations but remain elevated for more than24 hours, as shown in Fig. 79. Therefore, temperaturesurveys normally should be run between 8 and 24 hoursafter cement is mixed. Because these surveys are onlyapplicable for this short period after cementing, they,of course, have no application in old wells.

There are conditions in some areas where extremelyhigh well temperatures override the temperature increaseof the hydrating cement.182 If the cement top is be-tween casing strings, the temperature will be greaterthan, but parallel to, the geothermal gradient. In wellsin which particularly heavy or viscous drilling fluids areused, special cement displacing fluids may have to beused to permit running of the survey.

Radioactive surveys. Addition of radioactive tracermaterial to the lead portion of the cement slurry pro-vides a positive indicator of the cement top. Either longor short half-life material can be used. Carnolite has a

half-life of approximately 1,700 years, and permanentlyaffects natural gamma-ray emissions near its location inthe well. Several radioactive materials that can be used

as tracers have half-lives of 8-80 days.

Principal disadvantages of radioactive survey tech-niques for cement height determination are: Specialhealth precautions; interference with natural radioactivesurveys, and high costS.178

Pressure, inflow tests. Pressure tests are conducted

Fig. 79-Temperature and pressure effects within fluidfilled casing shut in immediately after cementing. Notemaximum temperature buildup 8-12 hours after mixing.Temperature remains elevated for several hours (afterFarris).'"

67

CEMENTTOP

.):I:

\....n.,w \0

I

\\\\\\\\

I I II I ,,,,

A B

TEMPERATURE

210 2,000

200 L VI 1,800PRESS.RELIEVED

190

b

1,600 Ci.i11.0 11.

a: 180 1,400 cri::?E (f)

wW II:....170 '" . 1,200 11.

PRESS.

160 1,000

150 8000 4 8 12 16 20 24

TIME, HOURSFROMSTARTINGTO MIX

REVERSECIRCULATING SUB.

DRILL STEM

REVERSECIRCULATING SUB. HYDRAULIC

MULTIPLE SHUT-INVALVE

n ]]

..~. j

;1]

ROTATINGSHUT-IN VALVE

INSIDE RECORDERCARRIER

JARS

SAFETY JOINT

HYDRAULIC VALVE PACKER INFLATIONPUMP

INSIDE RECORDERCARRIER

SCREEN SUB.

TOP PACKERHYDRAULIC JARS

SAFETY JOINTTEST PORTS

OUTSIDE RECORDERCARRIER

PACKER

SPACING

PERFORATEDANCHOR BOTTOM PACKER

OUTSIDERECORDERCARRIER

ANCHOR SHOE t BELLY SPRING

SINGLECOMPRESSION

PACKER

INFLATABLESTRADDLE PACKERS

Fig. SO-Two types of drill stem test tools used to check pos-sible fluid entry from a cement job test. Single packer type(left) must be set above single test point. Inflatable straddlepacker tool (right) can test more than one interval (courtesyLynes Inc.).

to verify integrity of the casing following primary ce-ment jobs. And specific procedures are specified by gov-ernment regulations in most locations. The casing pres-sure test is conducted after cement has set but prior todrilling out the cement shoe. These tests are not anindication of cement effectiveness.

In some locations, i.e., California, regulations requirethat the casing be perforated and tested by either bailingor inflow evaluation tests, called water shut-off (WSO)tests. In California the WSO tests provide assurancethat a cement seal of the annulus exists, to protectshallower freshwater reservoirs from brine and/or hydro-carbon contamination. This procedure of perforating andchecking rate and content of inflow, if any, has beenused to verify a cement seal above and/or below hydro-carbon producing zones in many areas. The advantageof this technique is that if a failure is indicated, a ce-ment squeeze of the WSO holes will be placed oppositea non-productive formation, rather than opposite thezone of interest. Also, inflow likely will purge mud fromthe perforations, a desired preparation for low pressuresqueeze jobs.

68

The WSO procedure can be as simple as bailingfluid from the casing and checking for fluid rise-aftercasing has been perforated or drilled out. However, per-forating and testing is more commonly conducted withcombination tools that can be run on tubing or wireline.

A WSO test can give positive indications of com-munication problems, or lack thereof, prior to final com-pletion. However, WSO perforations must enter the mudchannel, if one is present. And a small channel can bemissed with zero-degree gun phasing. The tighter thephasing, the lower the chances of missing a channel.

Combination of a mechanically fired perforating deviceand a testing tool makes it possible to perforate and teston a single trip with tubing or drill pipe.183 This testis conducted by perforating an impermeable zone aboveor below the zone of interest, setting the packer andopening the tester valve. A minimum cushion, fluidor gas, is placed inside the test string. In some locationsregulations specify the maximum amount of cushion.Inside and outside recording pressure instruments arealso included as an integral part of most testing tools,Fig. 80.

The tester is usually left open for a:bout an hour.If strong entry is indicated by a heavy "blow" at thesurface, the tester may be pulled sooner. The amountand type of fluid inside the test string can be checkedby reverse circulating the sample to surface or by re-tention in the string and later recovery. Pressure chartsare checked to confirm that the tester was open andexposed to cushion/formation pressure, to verify a goodtest.

Where there is a need for very accurate location ofWSO holes, a wireline perforator can be used with acollar locator and/or gamma ray log for correlation.After perforating, a conventional tester is run on tubingand the test is conducted, as with the combination tool.

Stra.ddle packers can be used to test more than oneset of WSO holes above and below zones of interest.

With a bottom packer added to the test assembly, eachset of WSO holes can be isolated and tested, Fig. 80.

Wireline perforating and testing tools are availablefor obtaining small fluid samples following selectiveperforating. These tools are primarily used to perforatethrough to the zone of interest and obtain a sealedreservoir fluid sample that could be suitable for PVTanalysis. The size of the sample chamber limits the ap-plication of this type equipment.

After drilling out. Where additional drilling is to beconducted and when the casing is cemented in an im-permeable formation, the casing shoe can be drilledout and the casing seat inflow tested. The amount ofopen hole to be drilled .below casing is specified by law,in some locations, but is usually 5-10 feet. Tests canbe made with a conventional tester set near bottom.

The testing procedures are the same as those used withthe perforating and testing program.

A pressure test can also be conducted after drillingout the casing shoe and 5-10 feet of open hole. Twoobjectives of this procedure are: To test effectivenessof the cement seal at the casing shoe; and to determineformation strength (fracture gradient) at the shoe.

One indication of cement seal failure at the casing

WORLD OIL 1977

shoe is loss of drilling fluid at pressure less than calcu-lated fracture pressure. When this occurs it usually in-dicates channeling during cement displacement, and stepsshould be taken to squeeze cement the shoe.

It is recommended that estimated surface test pres-

oa:wNW::Ei=

IC)I~I!;(IC)I

II

TIME_

A. FREE PIPE

B. GOOD BOND TO PIPEAND FORMATION

C. GOOD BOND TO PIPE,NO BOND TO FORMATION

D. DECENTRALIZED PIPE,ONE SIDE NOT BONDED

Fig. 81-Examples of acoustic signals actually received in testwells under various cementing conditions (after Walker).'''

GAMMAAPI GAMMA RAYUNITS10 110

o~o

oCo>oo

AMPLITUDE..

PIPE BOND MICRO-SEISMOGRAM

.!_0!l~~I!<2.N_~q,N'p_ 200 LOG 1,200

Fig. 82-Example of a cement bond log display of a sectionof well-bonded casing shows typical data included on fieldlog. Amplitude-time display (right) indicates weak pipe ampli-tude signal (grey tone left half) and strong formation signal(black line right half) comparable to signal B in Fig. 81 (cour-tesy Welex).

WORLD OIL 1977

sure (PST) required to fracture the formation be checkedprior to the test, using the equation:

PST=FG X D - 0.052p X DWhere: PST= Surface test pressure, psi

FG = Fracture gradient, psi/ft.D = Depth, ft.p = Mud density, ppg.

This surface test pressure must also be less than thepressure rating of equipment, i.e. wellhead, BOP, casing,etc.

H the drilling fluid has low mud weight and highfluid loss, rate of pressure bleed-off may be considerable.In some instances, it may be difficult to distinguishbetween fluid loss to permeability, poor cementationand/or formation yield (fracturing).

Acoustical cement bond logging in use since 1960,provides an evaluation of the cement column behindcasing. The cement bond log (CBL) combined withan acoustic signature log (MSG, VDL, XV, etc.) is alog in which both time of arrival and amplitude ofvibrations are used to evaluate bonding conditions.

Sonic signals are transmitted to a receiver that isacoustically isolated within a combination tool. In tra-versing through casing, signal amplitude is attem.\atedto a varying degree depending on material outside thecasing. Attenuation effect will be greater if that ma-terial is solid and bonded to the casing.

Signal amplitude is converted to electronic signals andvaries inversely with degree of attenuation. Thus ahigh amplitude casing signal is indicative of no bondbetween cement and casing, Fig. 81 (A).

When cement is firmly bonded to casing and forma-tion, there is a low casing signal and the signal receivedis characteristic of formation behind pipe, Fig. 81 (B).When cement is bonded to pipe bu t not formation, bothcasing and formation signals have low amplitude, Fig.81 (C).

When casing is resting against the borehole, chan-neling commonly occurs, preventing cement from sur-rounding the casing. Thus casing is free on part ofits circumference and formation-cement-casing couplingexists around the balance. Then both casing and for-mation signal are present as shown in Fig. 81(D).

It is important to receive more than just the casingsignal. Acoustic signals travel through fluid in the well-bore, casing, cement and/or annular fluids and forma-tion. The casing and formation signals are of primaryinterest. Additional details of CBL techniques, tech-nology and procedures are available in the literature.184-196

eBL presentations. Acoustic signals in a cased bore-hole consist of all arrivals along any coupled path be-tween transmitter and receiver. The time and ampli-tude of the combined signal from the various paths aresuch that all information cannot be presented adequatelyby a normal logging curve. Thus a CBL usually includesan amplitude curve that measures a specific time seg-ment of the acoustic signal and one or more of thefollowing:

. Transit time of the first acoustic signal that exceeds apredetermined amplitude

69

. Amplitude of the formation signal, and

. A variable intensity recording where dark and light streaksrepresent positive and negative half cycles of the acoustic signal,or

. An acoustic scope picture-XY presentation.

Additional measurements frequently included on CBLs

1.5

enI-I

o>uic::)I-::::;Q.::E<I:

I<I:Z(!jen

oo 2

CEMENT SHEATH THICKNESS, INCHES

Fig. 83-Effect of cement sheath thickness on pipe amplitudesignal (with pipe bonding only). With less than ~-inch, ampli-tude increase tends to indicate free pipe.

100

>::!: 10uiC:JI-::iQ.::!:<I:

51,h" CSG., 0.3" THICK.

1.0

0.2 _

o 20 40 60 80 100

% CIRCUMFERENCE BONDED

Fig. 84-Relation of cement bond log pipe amplitude to cementcompressive strength and percent circumference bonded. Ex-ample: 500-psi cement with 80% bonded shows same signalas 4,OOO-psicement with 40% bonded (after Schlumberger).

70

include a gamma ray curve and a casing collar log, Fig.82. Though not directly related to acoustic propertiesmeasured by CBL, this information has proven helpfulin CBL interpretation.

3

Interpretation. Validity of CBL interpretation is a con-troversial issue. There are no industry standards fortools or procedures. Inadequate information on CBLheadings, miscalibration of tools, lack of effective toolcentering in the casing and/or poor running procedureshave resulted in misleading interpretations.

Interpretation of a specific CBL depends on how andwhat portion of the acoustic signal is measured andrecorded. Factors that significantly affect tool responseinclude: Acoustic frequency of tool; electronic controlthat determines the acoustic signal segment measured(Gating systems and bias settings); spacing betweentransmitter and receiver; tool calibration; centralization,and logging speed.

Here are other factors that can introduce errors in

CBL interpretation:

. Extent of cement set (hardening) affects sonic signal veloc-ity and amplitude. During the setting process, gel which formsaround the cement particles is apparently an excellent absorberof acoustical energy. As cement hardens, acoustic transmissibilityincreases significantly and the casing signal is dampened out.Thus it is best to run CBLs at least 24-36 hours after the cementjob is completed or when compressive strength of cement reaches1,000 psi.

. Cement composition also affects acoustic transmission. If ahigh degree of sensitivity is applied where low-density cementingmaterials have been used, poor bond may be indicated althoughgood bonding actually exists. Tests in dril1ed holes with casingcemented with API Class A cement, indicated that small sectionsvoid of cement could be located only by using high sensitivity.Therefore, voids or channels may not always be indicated onCBLs unless proper sensitivity selection-with respect to cementcomposition-is used.1"

. Cement sheath thickness may vary, causing changes inattenuation rate. Lab tests indicate that a thickness of ~-inchor more is required to achieve full attenuation, Fig. 83. Thus,casing should be sized to provide a minimum of ~-inch clear-ance in the drilIed hole, with adequate centralization. Cementthickness can be critical in certain liner completions wherethickness is less than ~-inch.

. Cement compressive strength and percent of casing circum-ference bonded affects CBL amplitude, Fig. 84. It is not possibleto determine the difference between a job in which cementstrength is lower than anticipated, and a job in which cementstrength is as estimated but small mud channels exist.18OVerticalzone isolation does not exist in the latter case.

. A microannulus is a very small gap between casing andcement. This gap will affect a CBL. However, the presence of amicroannulus normally does not prevent isolation between zonesand it usually tends to "heal" with time.

A microannulus can be caused by: Shutting in thecasing and allowing pressure on the casing to increasedue to temperature rise; thermal expansion of the casingwhile cement sets and subsequent temperature reduction;contaminants on the external surface of the casing suchas mill varnish, grease, oil-wetting, etc.; and by dis-placing drilling mud with lighter-weight completionfluid prior to running the CBL.

Where a microannulus is indicated by logging, it isrecommended that a short overlap CBL be run underpressure, opposite zones of interest. The entire CBL

WORLDOIL 1977

RUNNINGPOSITION

COMPLETEDSYSTEM

Fig. 8S-Schematic of Pack/Perf Completion System illustratesinflatable external casing packer as primary cement is beingdisplaced (left) and after rubber element has been filled withcement and the pay zone has been perforated (right).'o.

should be run under pressure if there is a significantchange in amplitude with the casing pressured.

When mud channels are present, pressuring the casingwill have little, if any, effect on the CBL.195 With chan-neling, vertical isolation does not exist and remedialsqueeze cementing should be considered. Remember, achannel may only be on one side of the casing andchances of perforating into such a channel with a single-phase gun are minimal-use a 90-degree phased gunto perforate when channeling occurs.

The CBL can be an important aid in estimating ce-ment bond quality, when properly applied.195 CBL in-terpretation is not sinJple and straightforward as isoften assumed. And detailed information on cementingand logging operations are essential for accurate inter-preta:tion.

Production testing, production logging. The mostpositive evaluation of cement effectiveness has been ob-tained by production testing and production loggingmethods, following completion operations. These meth-ods include one or more of the techniques shown be-low: 197 -203

Production testing/logging techniques

1. Production tests-flow rate and content (water, oil, gasand solids, if any)

2. Inflow evaluation by determination of flow rates and con.ten t vs. surface flowing pressures

3. Comparison of 1 and/or 2 with fluid rate and contentexpected based on open hole logging data

4. Evaluation of historical production data and comparisonbetween wells with common completions (production surveil.lance)

5. Pressure build-up and fall off measurements with down.hole pressure reorders

6. Inflow vs. depth measurements with downhole flowmeters7. Flowing and/or static temperature vs. depth measurements

with high resolution surface recording thermometers8. Flowing fluid density vs. depth measurements9. Downhole fluid samples

WORLD OIL 1977

10. Radioactive fluid injection and surveys to identify injec-tion points and possible presence of migration channels behindcasing, and

11. Noise-logging to detect behind-casing fluid movement.

As mentioned in Part 7 of this series, the most im~.portant rule of preparation for remedial cementing op-erations is to accurately define the downhole problem-if any exists. Generally a combination of productiontests and production logging procedures are requiredto identify and locate channels or other problems as-sociated with lack of effective zone isolation. Verifica-

tion of remedial ,workover effectiveness requires thesame tests and/or other combinations of tests and log-ging procedures.

Primary cementing has been called "The Critical Pe-riod" of drilling and completion operations. And thereis universal agreement that effective primary cementingis a critical requirement for effective completions andminimal operating problems. Without zone isola:tion, sub-sequent stimulation, reconditioning and recompletion willbe less productive and more costly, at best. And secon-dary recovery efforts will be much more difficult tomonitor and control.

Perhaps the most important primary cementing pro-cedure is accurate and detailed documentation of the

casing running and cementing operations. This infor-mation is invaluable for evaluating cement jobs-it isabsolutely essential if improved procedures and equip-ment are to be developed.

Recommended job documentationCasing details

Size, weight, grade, equipment (centralizers, scratchers, floatshoes and collars, stage collars, petal baskets, etc.), inspectionprocedures, special handling, joint make-up tests and procedures,running speed, details of movement during cementing (if any),landing practices, etc.

Cement details

Volume, type and composition, density, rheology characteris-tics, displacement procedure (rate, use of top and bottom wiperplugs, preflush and spacer fluids including description andvolume, etc.)", service company, pressure and rate charts, surfacecirculating temperature, anticipated set time, etc.

Other details

Lost circulation, premature build-up of pressure, detail of anyoperating problems like pump break down or delays, poor mudconditions, etc.

CEMENTING EQUIPMENT INNOVATIONS

The Pack/Perf Completion system, developed by Com-pletion Technology Co. and manufactured by Lynes,Inc., provides one technique for assuring a positive bar-rier to vertical fluid movement in the casing-wellboreannulus. And, borehole wall support is established thatsubstantially exceeds such support obtained through con-ventional cementing methods.

The completion consists of locating one or more in-flatable external casing packers (ECPs) opposite zonesto be perforated. Following conventional cementing op-erations, and before cement sets, the ECPs are inflatedwith cement. This procedure: Purges by-passed movablemud; encourages casing centralization; and mechanicallydehydrates residual mud cake against the formation.Cement inside the casing is drilled out after necessary

71

SMALL. DIA. TUBING

ELEMENTS

__ DEFLATED INFLATED

, TOOLaD2 "/16"

Fig. 86-New through-tubing inflatable bridge plug can be runthrough 3V2-inch tubing, on macaroni string or coiled tubing,and set in casing as large as 7o/s-inch. Tool holds 700-psidifferential pressure (photo courtesy Lynes, Inc.).

wac time, and cement filled ECPs are perforated toestablish exclusive communication to zones of interest,Fig. 85.

The need for remedial squeeze cementing for zoneisolation should be eliminated. Casing will be centeredin the borehole at the ECP and a unifonn cement sheaththickness will exist.

Isolation packing, ball sealers, chemical diverters, etc.are frequently used to ensure that each perforation re-ceives treating fluids. However, after improper conven-tional cementing, such fluids may move vertically in theannulus even though they entered individual perfora-tions. The Pack/Perf system contacts the formation witha pressurized rubber seal, backed by non-contaminatedcement, that positively blocks vertical fluid movement inthe annulus. Acid, hydraulic frac fluid, chemical sandconsolidation fluid and other treatments will enter the

fonnations for which they are intended.Increased borehole wall support can be a significant

advantage where wells are completed in weak fonna-tions or where the reservoir is geopressured. Such for-mations are particularly subject to failure if mechanical

72

STARTING MILLWITH PilOT

CASING

DRILlPIPE

WHIPSTOCK

PERMANENT PACKERMODIFIED TORECEIVE AND lATCHWHIPSTOCK

Fig. 87-Schematic of new whipstock anchor offered by BakerPackers. System provides positive seat without danger of dis-turbing tool when bit is pulled back through casing window.Permanent packer is set first in oriented position (if desired)then whipstock anchor is run on the pilot mill and stabbedinto the packer. Additional set-down weight then shears millfree to begin sidetrack operation.

support is not provided. Mud channels or pockets leftfrom conventional cementing can be "drained" whenthe well is perforated and produced. This can removelateral support and cause failure of the formation rock.

In unconsolidated sands, lateral support can be a fac-tor preventing initial sand movement that leads to sandcontrol problems. This new support mechanism pro-vides the means to establish stabilized arch sand control-

a method that could increase productivity at minimumcost.204,205

Through-tubing bridge plug. Lynes Inc. has recentlyintroduced a new tool that can supplement, simplifyor even eliminate certain cement plug back operationsin casing (or possibly open hole) below an existingtubing string, Fig. 86.

The pennanent through-tubing inflatable bridge plugdevice has a 2 11/16-inch aD. It can be run, on amacaroni string or coiled tubing, through 3~-inch tubingand be expanded with fluid and set inside casing, up to7 5/8 inches. Once set, the plug is capable of with-standing up to 700 psi differential pressure.

The tool can be used to bottom a cement plug or,

WORLD OIL 1977

by itself, to shut-off bottom water from a perforatedinterval, etc.

Whipstock anchor. A new system is now offered forsetting an oriented, or non-oriented, whipstock on apermanent packer arrangement prior to cutting a win-dow in casing for sidetracking operations, Fig. 87. De-veloped by Baker Packers, a Division of Baker Inter-national Corp., the packer and anchor assembly positivelyanchors the whipstock in place, preventing both rota-tion and vertical movement. The packer also functionsas a permanent bridge plug to isolate the casing belowthe window. It can be run on electric line or pipe. How-ever, if directional orientation is required, the packer,will have to be run on pipe.

The system is an alternative to a cement plug placedfor sidetracking operations. Generally, less rig time andlower total cost will be realized for sidetrack operationswith this new innovation. And, it eliminates the potentialproblem of whipstock movement when the bit is pulledup through the window. Unless prevented, such move-ment can cause re-entry difficulties.

LITERATURE CITED

178Teplitz, A.J. and Hasselbrock, W.E., "An Investigation of Oil WenCementing," API 1946 Drillin~ & Production Practices.

119Folmar, L.W., "Methods of Detecting Top of Cement Behind Casing,"API-Oil Well Cementing Practices in the U.S., 1959 (Chapter 12).

18.Gretener, P.E., "Temperature Anomalies in Wells Due to Cementing ofCasing," ]PT, February 1968.

'8' Farris, R.F., "Method for Determining Minimum Waiting-on-CementTime," Petroleum Technology, January 1946.

'8. Kading, H.W. and Hutchins, J.S., "Temperature Surveys: The Art ofInterpretation," API Drilling & Production Practices, 1969.

'83Young, V.R., "Testi!'$ of Primary Cement Jobs, API-Oil Well Cement-ing Practices in the U.S., 1959, ChaRter 111'.18.Anderson, W.L. and Walker, T., 'Research Predicts Improved CementBond Evaluations with Acoustic Logs," ]PT. November 19611.

188Winn, R.H., Anderson, ,T.O., Carter, L.G., "A Preliminary Study ofFactors Influencing Cement Bond Logs," ]PT, April 1962.

'86Walker, T., "Case Histories of Bond Logging," O&G], May 7, 1962.181Riddlo;., G.A., "Acoustic Wave Propogation in Bonded and Unbonded Oil

Well t.<asing," SPE 454, October 1962.188Pardue, G.H., et ai, "Cement Bond Log-A Study of Cement and Casing

Variables," ]PT, May 11963.180Flournoy, R.M., and Feaster, J.H.. "Field Observations on the Use of

the Cement Bond LOR and Its Application to the Evaluation of Cement-ing Problems," SPE 632, 1963.

'90Harcourt G., Walker, T., and Anderson, T., "Use of the Micro-Seismo-gram and Acoustic Cement Bond Log to Evaluate Cementing 'Techniques,"SPE 798, '1964.

,., Anderson, T.O., Winn, R.H. and Walker, T., "A Qualitative Cement-bond Evaluation Method," API Trans. 1964.

19.Walker, T., "A Full-Wave Display of Acoustic Signal in Cased Holes,"]PT, August 1'968.

... Bade, I.F., "Cement Bond Logging ,Techniques-How They compare andSome Variables Affecting Interpretation," ]PT, January 1963.

19.Chaney, P.E., Zimmerman, C.W., Anderson, W.L., "Some Effects ofFrequency Upon the Character of Acoustic Logs," ]PT, April 1966.

'96Fertl, W.H., Pilkington, P.E., and Scott, J.B., "A Look at Cement BondLogs," SPE 4512, 1973.

'00Pilkington, P.E., and Scott, J.B.J. "Comparing Cement Bonds AfterTen-Plus Years," Pet. Eng., April 1:176.

,., Wilson, C.L., et ai, "How Good is That Wen Completion?" O&G],June 26, 1955.

108Wade, R.T., et ai, "Production Logging_The Key to Optimum WenPerformance," ]PT, February 1965.

,.. Kading, Horace W. and Hutchins, J.S., "Temperature Surveys,: The Artof Interpretation," API-Drilling and Production Practices 11969.

'00Meunier D., Tixier, M.P., and Bonnet, J.L., ",The Production Combi-nation Tool-A New System for Production Monitoring," SPE 2957, 1970.

20'Witterholt, E.J., Tixier, M.P., "Temperature Logging in InjectionWells," SPE 4022, 1972.

... McKinley, R.M., Bower, F.M., Rumble, R.C., "The Structure andInterpretation of Noise from Flow Behind Cemented Casing," ]PT,March, 1973.

... Odeh, A.S., Jones, L.G., "Two-Rate Flow Test, Variable-Rate Case-Application to Gas-Lift and Pumping Wells," ]PT, January 1974.

... Suman, G.O., Jr., "Unconsolidated Sand Stabilization Through WellboreStress State Control," SPE 5717, '1975.

"'" Snyder, Robert E., "What's New in Well Completion," World Oil, May1977.

End of series

WORLD OIL 1977 73