LIMITS Reference 1. In gas wells, liquid loading can also be predicted using simplified

In document Drilling and workover best practices (Page 152-156)

PL3. COMPLETION DESIGN

6. LIMITS Reference 1. In gas wells, liquid loading can also be predicted using simplified

methods presented with Turner et al which are independent of pressure drop calculations. These methods have been reviewed by Lea and Tighe. For wells producing high water or gas-condensate ratios, it is recommended that tubing size be assessed using these methods in addition to lift curve methods and that the most conservative approach be adopted.

P-1-M-7100 2.4.4

6.2. Erosion in completions occurs when there are high velocities and if there are solids particles in the flow stream. The most common points for erosion is where there are restrictions that cause increased velocities. The API have published a method in API RP 14E, to determine the threshold velocities for erosion to occur in piping systems but the validity of this for all conditions is questionable.

P-1-M-7100 2.4.4

6.3. The choice of the optimum tubing size should be taken into account the AGIP standardisation in terms of:

6.3.1. Well head diameter.

6.3.2. Subsurface safety valve diameter.

6.3.3. Production casing diameter.

6.4. The maximum tubing OD for a particular design shall consider the clearance CSG / TBG in order to be able to washover and fish a broken tubing by standard overshot.

7. OPTIMUM TBG SIZE THROUGH FIELD LIFE Reference

7.1. Optimum TBG size should change with changing reservoir condition and different configurations should be evaluated through time.

7.1.1. Compromise diameter.

7.1.2. Workover to substitute the tubing.

7.1.3. Concentric TBG installation.

Reference list:

‘Completion Design Manual’ STAP-P-1-M-7100

PL. 3.6. STRESS ANALYSIS

1. GENERAL Reference

1.1. All completion tubing strings will have tubing movement calculations conducted to ascertain the maximum load applied to the string and/or completion tubing movement to be catered for in the completion design.

All tubing strings should be designed for stress, preferably using an appropriate up to date computer programme. Currently Eni-Agip Division and Affiliates recommended programme is the Enertech WS-Tube programme to the latest version.

P-1-M-7100 7.1

1.2. The triaxial equivalent stress must be computed from the axial, radial, hoop, and torsional shear stresses.

1.3. The effective axial force shall be computed by summing the actual axial force and the force that causes the same outer fiber stress that is induced by the curvature due to buckling and hole doglegs.

1.4. Hoop and radial stresses shall be computed using Lame’s formulas at the OD and ID.

1.5. Shear stress shall be computed from the torque and polar moment of inertia.

1.6. Stresses shall be computed on the side with compressive bending stresses and on the side with tensile bending stresses, to insure the worst stress conditions have been identified.

2. PARAMETERS Reference

2.1. During completion tubing design process, it is necessary to calculate the variations in length for the stresses applied under load conditions.

When these have been determined it will confirm the suitability of the selected tubing.

Tubing movement occurs due to only two reasons:

• Temperature changes

• Change in pressure induced forces.

P-1-M-7100 7.2

2.2. The well data and parameters required (or already determined) to produce an accurate tubing movement/stress analysis and, hence, selection of a tubing are:

• Casing design profile

• Casing programme contingency profile

• Tubing size from optimisation analysis

• Pressure gradient

• Temperature gradient

• Reservoir fluids specific gravities

• Completion fluid specific gravities

• Production/injection or stimulation forecast.

P-1-M-7100 7.3

2.3. Movement can only occur if the tubing is free to move. If the tubing is not free to move and is anchored to a packer then stress will be subjected to the tubing string and packer.

Tubing movement upward (contraction) is assumed to be negative and downward (lengthening) is positive.

P-1-M-7100 7.2

2.4. The optimum tubing size, determined by nodal analysis conducted by the reservoir engineers, is required and is the basis of all the calculations.

The tubing movement/stress calculations will then determine the tubing weight or any change in grade required to meet with the applied SF for stress.

P-1-M-7100 7.3.2

2.5. Bottom-hole Pressure:

Accurate initial and prognosed future formation pressures both static and dynamic are fundamental to tubing movement/stress calculations. These pressures can be obtained from previous well exploration test data or appraisal well test reports.

P-1-M-7100 7.3.3

2.6. Temperatures (Static and Flowing):

Accurate well temperature data are vital in tubing movement/stress analysis as the temperature effect is usually the effect which causes the greatest tubing movement.

P-1-M-7100 7.3.4

2.7. Temperature changes cause expansion and contraction in metals, which is a significant factor in tubing strings. All metals have a particular expansion rate that is termed the ‘Co-efficient of thermal expansion’.

The co-efficient of liner expansion for tubular steels is usually 6.9 x 10-6 in/in/F°.

P-1-M-7100 7.2.2

2.8. When a well is completed, either with a tubing seal unit in a packer bore or a tubing movement device, it will have completion fluid in both the tubing and the annulus, this is referred to as the initial condition.

All subsequent conditions are calculated from this initial condition.

P-1-M-7100 7.4

2.9. The prediction of temperatures and pressures is of high concern to the tubing design and a lot of care shall be given in the choice of the operational parameters.

2.10. Production operations normally yield tubing elongation’s and injection operations normally yields tubing contractions.

2.11. Usually injection or cold operations are the most critical for the stress behaviour.

3. CALCULATION METHOD Reference

3.1. For each operation the tubing movement and the relevant stresses shall be calculated as per the method described in the AGIP procedure.

P-1-M-7100 7.10

3.2. Effects to consider:

3.2.1. Piston (Hooke). P-1-M-7100 7.4.1

3.2.2. Buckling. P-1-M-7100 7.4.2

3.2.3. Ballooning. P-1-M-7100 7.4.3

3.2.4. Temperature. P-1-M-7100 7.4.4

3.3. The completion shall be divided into as many sections as any changes in material, tubing OD, tubing ID, casing ID, internal fluid level, external fluid level.

3.4. The stress at bottom and top of every section shall be calculated.

3.5. All tubing strings should be designed for stress, preferably using an appropriate up to date computer programme. Currently Eni-Agip Division and Affiliates recommended programme is the Enertech WS-Tube programme to the latest version.

P-1-M-7100 7.1

4. SAFETY FACTOR Reference

In document Drilling and workover best practices (Page 152-156)

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