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3.1.1. Casing design is actually a stress analysis procedure. The objective is to produce a pressure vessel which can withstand a variety of external, internal, thermal, and self weight loading, while at the same time being subjected to wear and corrosion.

P-1-M-6110 7

3.2. Max acting burst pressure 3.2.1. Refer to Table PL 2.5

3.2.2. If it is foreseen that future stimulation or hydraulic fracturing operations may be necessary, the fracture pressure at perforation depth and at the wellhead pressure minus the hydrostatic head in the casing plus a safety margin of 70kg/cm2 (1,000psi), will be assumed.

P-1-M-6110 8.1.2

3.3. Max acting collapse pressure 3.3.1. Refer to Table PL 2.6

3.3.2. Biaxial stress:

Total tension load affects burst and collapse resistance of the casing, (effects of axial stress on burst resistance are considered negligible).

P-1-M-6110 8.4.1 Reduced collapse resistance in biaxial stress must be considered. P-1-M-6110 8.4.1 3.3.3. Prevention of casing collapse in salt sections must be considered. P-1-M-6110 8.7 Eni-Agip design procedures assume uniform external pressure

exerted by salt on the casing equal to overburden pressure.

P-1-M-6110 8.7.3

3.4. Total TENSION load

3.4.1. Total tension load is given by adding to the weight of casing in air:

(Refer to Table PL 2.7)

3.4.2. Buoyancy force (negative) while running casing. P-1-M-6110 8.3.2 3.4.3. Bending forces in deviated wells (curved section of hole). P-1-M-6110 8.5.1 Determination of bending effect5. P-1-M-6110 8.5.2 3.4.4. Tension load due to bump plug after displacing cement does not

affect biaxial stress evaluation.

Take in to account eventual pressurisation about both opening /closing DV operations and setting ECP.

P-1-M-6110 8.3.3-3

3.4.5. Others parameters affecting total tension load: Drag forces in deviated wells. P-1-N-6001E 6.3.10 Shock loads (dynamic stresses), due to arresting casing in slips. P-1-M-6110 11 Internal pressure tests6.

The worst situation assumes the casing totally free to move.

P-1-M-6110 11.3 Changes in the magnitude of the buoyancy forces. P-1-M-6110 8.3.2 3.4.6. Evaluate ‘safe allowable pull’.

It is normal to consider an overpull contingency of 100000lbs.

P-1-M-6110 11.1

5 B = 15,52 α OD Af ; TB : additional tension [kg] OD : outside diameter [in]

α : build-up/drop-off rate [deg/30m] Af : cross section area [cm2]

TB = 218 α OD Af ; TB : [lb] OD : [in]

α : [deg/100ft] Af : [in2 ]

6 The test pressure shall not exceed 70% of the API minimum internal yield pressure of the weakest casing in the string. The test pressure shall remain stable for 15 minutes.

3.5. Required & actual design factors

3.5.1. Burst required design factor. Refer to Table PL 2.5 P-1-M-6110 8.1.2 3.5.2. Collapse required design factor. Refer to Table PL 2.6 P-1-M-6110 8.2.1 3.5.3. Tension required design factor. Refer to Table PL 2.7 P-1-M-6110 8.3.3 4. DECREASING IN THE CASING PERFORMANCE PROPERTIES Reference 4.1. Casing wear

4.1.1. Reduction in collapse resistance due to wear will be critical at shallow depths, the reduction in burst resistance will be critical at the lower end of the casing string.

P-1-M-6110 8.6

4.1.2. Eni-Agip design procedure.

• In vertical well, casing wear is usually in the first few joints below the wellhead or intervals with a high dogleg severity.

Considerations should be given to increase the grade or wall thickness of the first few joints below the wellhead.

• In deviated wells, wear will be over the build-up and drop-off sections. The casing over these depths can be of a higher grade or greater wall thickness.

P-1-M-6110 8.6.8

4.1.3. The percentage casing wear at each point along the casing is then calculated from the volumetric wear. Eni-Agip acceptable casing wear limit is </= 7%.

P-1-M-6110 8.6.1

4.1.4. The volume of casing worn away by the rotating tool joint equals:

P F= Wear factor (ins2/lbs)

L= Lateral load on drill pipe per foot (lbs/ft) D= Tool joint diameter (ins)

N= Rotary speed (RPM) S= Drilling distance (ft) P= Penetration rate (ft/hr)

P-1-M-6110 8.6.2

4.1.5. Prediction of casing wear Wear factor evaluation:

It is depending on drilling fluid characteristic and tool joint type.

P-1-M-6110 8.6.4

4.1.6. Detection of casing wear:

• Use of magnets in mud flow return system.

• Run a calliper survey tool.

P-1-M-6110 8.6.5

4.1.7. Practices to reduce casing wear:

• Use drill pipe without hard facing.

• Keep sand content low.

• Use of rubber drill pipe casing protectors.

• Use DHM, turbines.

• Keep doglegs at a minimum.

• Use oil based mud.

P-1-M-6110 8.6.6

4.1.8. Recommended approach to casing wear problems at well planning stage:

1. Design the casing.

2. At the wear points, calculate the allowable reduction in wall-thickness so that the burst (or collapse) resistance of the casing just equals to burst (or collapse) load, including the appropriate Design Factor.

3. Estimate the wear rate in terms of loss of wall-thickness per operating day.

P-1-M-6110 8.6.7

4.2. Corrosive environment 4.2.1. Carbon dioxide (CO2):

• Partial pressure > 30psi - usually indicates corrosion.

• Partial pressure 3 – 30psi - may indicate corrosion.

• Partial pressure < 3psi - no corrosion.

P-1-M-6110 9.1.3

4.2.2. Hydrogen sulphide (H2S):

The combination of H2S with CO2 is more aggressive than H2S and is frequently found in oilfield environments. Attack due to presence of dissolved hydrogen sulphide is referred to as ‘sour’ corrosion.

P-1-M-6110 9.1.3

4.2.3. Factors affecting corrosion rates:

• Temperature

• Pressure

• pH

• Fluids velocity.

P-1-M-6110 9.1.3

4.2.4. Acceptable casing for ‘sour’ service Vs operating temperature. P-1-M-6110 Table 9.B 4.2.5. Eni-Agip design procedure. CO2 corrosion:

• Exploration wells - no influence on material selection.

• Producing wells - selection of high alloy chromium steels resistant to corrosion, inhibitor injection.

P-1-M-6110 9.8.1 H2S environment:

• Exploration wells:

with high probability of encountering H2S, it should be considered to limit casing yield strength according to API-5CT and NACE standard MR-01-75.

• Producing wells:

casing and tubing material will be selected according to the amount of H2S and other corrosive media present.

P-1-M-6110 9.8.2

4.3. Temperature effects 4.3.1. High temperature service Reduction in yield strength. P-1-M-6110 10.1 Graph ‘modulus of elasticity of casing Vs temperature’. P-1-M-6110 10.1 4.3.2. Low temperature service:

Use high ductility steel to prevent brittle failures during transport and handling.

P-1-M-6110 10.2

4.4. Buckling & compression 4.4.1. Buckling Buckling effect may occur in the uncemented portion of a casing string, if (after the cement has set):

• Internal pressure increases.

• Annular fluid density reduction.

• Casing is landed with less than full hanging weight.

• Temperature increases.

P-1-M-6110 11.4.1 Buckling of long uncemented portions of the casing string (in vertical wells), can be prevented by:

• Cementing the casing up to the neutral point.

• Pre-tensioning the casing on landing.

• Rigidly centralising the casing below the neutral point.

P-1-M-6110 11.4.1

4.4.2. Compression Wells with the wellhead at ground level or sea bed.

The surface casing must be cemented to surface / seabed.

P-1-M-6110 11.4.2 Wells with the wellhead above sea level (no mudline suspension).

The surface casing must be designed for compression loads.

Every joint of the surface casing must be centralised.

P-1-M-6110 11.4.2 Wells with mudline suspension.

The weight of the casing is taken at the seabed, but the wellhead is above seabed.

The C.P. must be cemented to seabed.

The tieback strings may be subject to buckling, a full structural analysis should be carried out (commissioned).

P-1-M-6110 11.4.1 P-1-M-6140 15.5