PARTC10C

8/12/2019 PARTC10C

http://slidepdf.com/reader/full/partc10c 1/5

September 1999 Issue 2 Section C10 Casing Wear 10-5

BP Amoco Casing Design Manual BPA-D-003

FIGURE 10.5EXPERIMENTALLY MEASURED

WEAR FACTOR

Casing wear cannot occur unless the drillstring touches the inside of thecasing. As Figure 10.1 shows, this occurs when the drillstring is pulledaround or through a ‘dogleg’. The typical method for measuring doglegsis in degrees per l00 feet. This gives an average value over the length.Unfortunately, casing wear often occurs around severe ‘local’ doglegs(<100 ft), and what appears to be a smooth survey profile may containhidden dangers. In particular, drilling through buckled casing can cause

severe wear.

When designing a well profile, it is important to understand the effect alocal dogleg would have on the life of the casing. Empirical data hasshown that build and drop rates of directional wells can be locallyexceeded by at least 1.75 times the planned rate. Well profiles shouldbe checked for sensitivity to these unplanned doglegs by using theCWEAR program.

There are no preferred well profiles to minimise casing wear but highsidewall forces can be minimised by using a deep kickoff section.

Because of this, most horizontal wells do not suffer from severe casingwear as the sideloading generated by the BHA in the horizontal sectionis generally low and more evenly distributed.

The following procedure provides a means of quickly determiningwhether casing wear will be a problem on a well. From this preliminaryinvestigation it should be possible to decide whether a more detailedstudy is required.

10.2.3Doglegs

24

20

16

12

8

4

0

0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16 0.18 0.20

Wear Depth (in.)

W e a r F a c t o r

5000 lb/ft

7000 lb/ft

10.2.4Estimation of Casing

Wear

8/12/2019 PARTC10C


September 1999 Issue 2 10-6 Casing Wear Section C10

BP Amoco BPA-D-003 Casing Design Manual

Information RequiredTo perform a preliminary estimation of casing wear, the followinginformation is required:

• Type of tooljoint hardbanding• Mud type (oil-based or water-based)• An estimate of drillstring sideload at the depth of interest, or alternatively

the drillstring tension (or compression) and the dogleg severity.Average values for a hole section are good enough

• An estimate of the total rotating hours expected inside a casing stringand the planned rotary speed

ProcedureThree of the charts in this section are needed to estimate casing wear; becareful to select the correct charts to work from.

1. Use Chart 1 to determine the casing WEAR FACTORUse the drillstring simulator (DSS) to estimate the drillpipe sideloadat the depth of interest. Alternatively estimate drillstring tension (orcompression) and dogleg severity to calculate side load from Chart 1.

FIGURE 10.6ESTIMATION OF CASING

WEAR

Estimation of Casing Wear

Select point forcsg wear analysis

Wear Factor

Determination

1. Drillstring sideload from DSS

or from chart of drillstring

tension and dogleg (Chart 1).

2. Wear coefficientTJ WBM OBM

t.c.Steel

Armacor

106

2

53

2

Equivalent rotating hoursE.g. rot hrs = rot hrs x RPM/60

Casing weight

Wear VolumeDetermination

Wear Depth

Determination

Sensitivity analysis

Repeat calcs with

different input values

Chart 1

Charts 2-4

Charts 5-12

Inputs

Inputs

Inputs

8/12/2019 PARTC10C




Determine the wear coefficient of the tooljoint hardbanding from thetable below:

Tooljoint WBM OBM

Smooth tc 10 5

Plain steel 6 3

Armacor M 2 2

Arnco 200 XT 2 2

To estimate SIDELOAD, read up from DRILLPIPE TENSION/ COMPRESSION to the intercept with DOGLEG then read across toSIDELOAD. Read across from SIDELOAD (y-axis) to the intercept withthe appropriate WEAR COEFFICIENT in the table. Read down to the

left-hand x-axis for the WEAR FACTOR.

2. According to tooljoint diameter, select from Charts 2-4 todetermine casing WEAR VOLUMEAs Charts 2-4 assume a rotary speed of 60rpm, determine the numberof equivalent rotating hours anticipated inside the casing string asfollows:

1 equivalent rotating hr = 1 hour’s rotation @ 60rpmHence: Total equivalent rotating hrs = Total rotating hrs x RPM

60

Read up from EQUIVALENT ROTATING HOURS (x-axis) to the interceptwith the appropriate WEAR FACTOR (from Chart 1). Read across to they-axis for WEAR VOLUME.

3. According to casing OD and tooljoint diameter select fromCharts 5-12 to determine percent casing WEAR DEPTHRead up from the calculated WEAR VOLUME (x-axis) to the interceptwith the appropriate CASING WEIGHT. Read across to the y-axis forpercent WEAR DEPTH.

% casing wear =reduction in thickness x 100

original thickness

This procedure should be repeated with small variations in inputparameters (especially dogleg wear coefficient, and rotating hours) toobtain levels of confidence in the predicted wear. This will also indicatesensitivity to changes in well design and drilling parameters.

This procedure is summarised in a decision tree Figure 10.6 (ESTIMATIONOF CASING WEAR).

8/12/2019 PARTC10C


September 1999 Issue 2 10-8 Casing Wear Section C10

BP Amoco BPA-D-003 Casing Design Manual

Interpretation of ResultsThe predicted wear should be compared with the allowable wear to staywithin the required design factors. The allowable wear can be obtainedfrom ‘Stresscheck’. A more detailed casing wear study should be

considered if:

• Sensitivity analysis gives wide variations in percent wear• A sidetrack is planned• Casing wear cannot be calculated with the charts• Casing burst or collapse design is critical – often the case for

HPHT if required drift is to be achieved

Full casing wear investigations can be performed by the Well IntegrityTeam, UTG.

ExampleA 121 / 4in hole is being drilled to 3500m at an average ROP of 10m/hr anda rotary speed of 120rpm. A string of 54.5 lb/ft 133 / 8in casing is set at1500m. At 500m there is a 3 deg/100 ft dogleg and the drillpipe tensionis about 160,000 lbf. The hole is being drilled with oil-based mud and thedrillstring has 61 / 2in OD tooljoints with tungsten carbide hardfacing. Howmuch casing wear is expected?

From Chart 1: Wear Factor = 400From Chart 3: Wear Volume = 1.25 cu in/ftFrom Chart 5: Wear Depth = 20 percent of casing wall

1,200 1,000 800 600 400 200 0

Wear Factor

10

8

6 5 4 3 2 1

200

150

100

50

0

Wear Coefficient

0 50 100 150 200 250 300

Drillpipe Tension / Compression (1000 lbf)

10 7.5 5 4

3

2

1

0

Dogleg (deg/100ft) Chart 1

S i d e l o a d ( l b l / f t )

Wear Factor Determination

FIGURE 10.7CASING WEAR

DETERMINATIONCHARTS (1-12)

8/12/2019 PARTC10C




0

2

4

6

8

101200

1100

1000

900

800

700

600

500

400

300

200

100

0 200 400 600 800 1,000 1,200 1,400

Wear

Factor Chart 2 (4.3/4" Tooljoints)

W e a r V o l u m e ( c u . l n

/ f t )

Equivalent Rotating Hours

4

6

8

10

12

14

1200

1100

1000

900

800

700

600

500

400

300

200

100

0 200 400 600 800 1,000 1,200 1,400

Wear Factor Chart 3 (6.1/2" Tooljoints)

W e a r V o l u m e ( c u . l n

/ f t )

Equivalent Rotating Hours

2

0

Wear Volume Determination

Wear Volume Determination

Documents

PARTC10C