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Much of the input to CWEAR is straightforward. CWEAR does, however,contain a number of options to customise a wear analysis. The followingrecommendations should be followed unless local experiencesuggests otherwise.

Tortuosity applies a sinusoidal variation to both inclination and azimuth.Only the smooth, artificial surveys used during well planning should havetortuosity applied. The following recommendations are taken from theCWEAR users manual:

The period should be at least five times the average interval betweenadjacent survey stations

Due to the behavior of the sine function, and if the survey stations areequally spaced from the surface, a period equal to twice the surveyinterval will result in no tortuosity

The amplitude should be set to a value between 0.4 and 1.0 to modeltypical field conditions

Dogleg insertion shifts the survey on either side of the point of interestand then uses a new survey station to connect the shifted survey with itsoriginal path. Dogleg insertion is an important option for emulating thecasing curvature in a vertical well associated with helical buckling.

Several of the entries under Tool Joint Information on the Tubular Datainput window are directly applicable to the calculation of the number ofdrillpipe protectors necessary to avoid excessive casing wear.

Input Variable Use in CWEAR

Max Lateral This is the maximum normal force to be toleratedLoad per on a tool joint before protectors are considered.Tool Joint If the normal force on a tool joint is less than this

quantity, no drillpipe protectors are assumednecessary, regardless of the contact time andensuing wear.

Max Lateral The maximum normal force each drillpipeLoad per Drillpipe protector can support.Protector

Wear Limit on If the wear is less than this value, no drillpipeDrillpipe protectors are assumed necessary.Protector Usage

3.3.3.1Tortuosity (Survey Data)

3.3.3.2Dogleg Insertion

(Survey Data)

3.3.3.3Drillpipe Protector

Calculation (Tubular Data)

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Should drillpipe protectors be necessary, the number of protectors pertool joint is calculated from the formula:

Protectors per Joint = Normal Force per Tool Joint + 1Max Lateral Load per Drillpipe Protector

where the value calculated is rounded down to the nearest integer. Thenormal force per tool joint is determined by assuming all the normal forceon a drillpipe joint is supported at the tool joint. If the drillpipe joint lengthand tool joint lengths are not known, recommended values are 30ft and14in respectively.

Several options for displaying the effect of wear on collapse and burstresistance are available. Results from the option selected are displayedin the output windows following a wear calculation.

Ignore all CWEAR estimates of collapse of worn casing. The reductionin collapse resistance due to wear is directly proportional to the reductionin wall thickness. When viewing the output, wear percent can be used todetermine the reduction in collapse resistance.

Wear constitutes a direct threat to the integrity of affected casing whenthat casing is subjected to subsequent differential pressure and/or axialloads. Usually the pressure and axial loads associated with the drillingthat produces wear are insufficient to cause failure. It is later loads,associated with well control or completion and production operations,when coupled with the reduced wall thickness, that pose the greatestpotential for failure.

Wear is most common in extended reach and horizontal wells whereeither the length of rotation or the magnitude of the normal force at a pointin the wellbore becomes critical. Vertical wellbores, typical of onshoreand exploratory holes, are not, however, without the potential for wear.Here, the culprit is usually buckling which produces a curvature in thecasing corresponding to the helical trajectory of the unstable tubular.Common causes of buckling in vertical wellbores include the following(refer also to Section 9.1):

Setting a string on bottom or slacking off during WOC prior to allowingthe cement time to build sufficient gel strength to support the casing

Change in axial force and effective tension associated with increasesin drilling fluid density and circulating temperature during drill ahead.This source has become prominent in intermediate casing strings ascement tops are lowered (below the previous shoe) to (a) avoid atrapped annulus in high pressure, high temperature (HPHT) wellsand/or (b) permit annular cuttings injection

(E.3.1)

3.3.3.4Revised Burst and

Collapse Resistance(Parameter Data)

3.4Wear and CasingDesign Software

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Currently, no software contains integrated prediction of both wear and itseffect on exposed tubulars. Working this problem usually involvesco-ordinating two models; a wear model and a casing design model.Following a discussion of the effect of wear on casing integrity, thesections below offer guidance on co-ordinating the casing design/wearprediction procedure for both directional and vertical wellbores.

In a directional wellbore, the procedure for determining the effect of wearon the integrity of a casing string is iterative:

(1) Design a trial casing string assuming no wear. The string should besufficient to withstand all anticipated service loads.

(2) Use the trial casing string as input in CWEAR and determine thewear for anticipated drilling conditions.

(3) With a wear prediction in hand, check the integrity of the trialcasing string. If necessary, repeat the procedure with a revisedcasing string.

Typically, only one iteration will be necessary as wear is relativelyinsensitive to the wall thickness and grade of casing.

The procedure for determining the effect of wear on the integrity of acasing string in a vertical wellbore is identical to the procedure for adirectional wellbore with one exception. In a directional wellbore thenormal force immediately follows from the inclination and directionalchanges of the borehole trajectory. In a vertical wellbore, however,significant wear can occur in the presence of buckling, without bucklingthere is no normal force. It therefore becomes necessary to fabricate aborehole trajectory representing the helically buckled tube. The procedureto do this is as follows:

(1) Design a trial casing string assuming no wear. The string should besufficient to withstand all anticipated load cases. Include a drillahead load case, not to check for string integrity but rather to checkfor the possibility of helical buckling during drilling operations insidethe trial string.

(2) If buckling is predicted, compute the dogleg severity in the helicallybuckled tubular using the procedure described in Section 9.3.

3.4.1Wear in

Directional Wellbores

3.4.2Wear in

Vertical Wellbores

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(3) Use the trial casing string as input in CWEAR and determine thewear for anticipated drilling conditions, using a user-specified DLSin CWEAR.

(4) With a wear prediction in hand, check the integrity of the trialcasing string. If necessary, repeat the procedure with a revisedcasing string.

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