1. Burst during drilling
Burst loads can occur during the drilling phase due to displacement of the borehole to hydrocarbons. There are, however, a number of special cases to be considered. The base case and the special cases will be addressed in this section.
1.1 Internal pressure profile
The worst-case internal pressure loading is that following a complete loss of primary control corresponding to full displacement of the casing to gas and the well closed-in at surface. The internal pressure profile is based on a gas gradient taken from the pore pressure at TD. If the gas-water contact (GWC) in the structure is known, the chosen gradient should be assumed to originate from this depth.
Where more information is available about the behaviour of the hydrocarbon phase, e.g. via PVT data from offset wells, a field-specific gas gradient should be used. When hydrocarbons with a very low gas/oil ratio are encountered, the relevant oil gradient may be used. Although hydrocarbons with a medium gas/oil ratio will separate out once the well is shut in, it is very difficult to quantify a realistic internal pressure profile for this case. Hence, the approach for the worst-case internal pressure loading described above should be used.
The resultant pressure at the casing shoe should be compared with the formation breakdown pressure (FBP) at that depth. If the pressure is in excess of the highest anticipated FBP the internal pressure profile should be reduced accordingly. The hydrocarbon gradient will then extend upwards from this highest anticipated FBP at the casing shoe.
1.2 External pressure profile
See article Collapse Loads section 1.2.
1.3 Special cases
1.3.1. Over-pressured aquifer in borehole below casing
When only an over-pressured aquifer is encountered, the internal pressure profile will be that due to full displacement of the wellbore to formation water, with the well closed in at surface. The pressure calculations are based on a pressure line with the formation-water gradient, drawn from pore pressure at the top of the aquifer.
The resultant pressure at the casing shoe should be compared with the formation breakdown pressure (FBP) at that depth. If the pressure is in excess of the highest anticipated FBP the internal pressure profile should be reduced accordingly. The pressure line with water gradient will then extend upwards from this highest anticipated FBP at the casing shoe.
1.3.2. Salt loading
Salt loading is a time-dependent phenomenon and since its onset cannot be accurately predicted, it should be assumed absent when calculating the external pressure profile for a burst scenario. This is just the opposite of the rule given in Section 3.2.2.2 for collapse scenarios.
The internal pressure profile is that resulting from displacement of the casing to hydrocarbons or to water as described for the case of the overpressured acquifer above.
2. Burst during production
Burst loading during the production phase will generally depend on whether the load is above or below the production packer. Burst loads above the production packer are usually a result of tubing failure. There are, however, a number of special cases to be considered. The base case and the special cases will be addressed in this section.
2.1 Internal pressure profile
2.1.1 Above the production packer
The maximum internal pressure profile experienced by the production casing will be that resulting from a leak in the production/injection tubing or test string at or near the surface. The appropriate surface pressure will then be imposed on the packer fluid. The gradient of the pressure line is determined by the density of the fluid between the tubing and the casing at the time.
For production wells, the maximum surface pressure will be the closed-in tubing-head pressure (CITHP), which should be based in the worst case on a column of gas extending from the pressure at TD. If the gas-water contact (GWC) in the structure is known, the pressure line with the chosen gradient should be assumed to originate from this depth.
Where more information is available about the behaviour of the hydrocarbon phase, e.g. via PVT data from offset wells, a reservoir-specific gas gradient should be used. When hydrocarbons with a very low gas/oil ratio are encountered, the relevant oil gradient may be used. Although hydrocarbons with a medium gas/oil ratio will separate out once the well is shut in, it isvery difficult to quantify a realistic internal pressure profile for this case. Hence, the maximum CITHP based on a gas column extending from the pressure at TD should be assumed. A suitable margin should be included in the CITHP if squeeze kill operations are to be considered.
For injection wells, or wells where stimulation treatment may be performed, the maximum surface pressure will be the injection-tubing-head pressure (ITHP) during the respective operations. The ITHP resulting from stimulation treatment need only be considered when annuli cannot be monitored.
2.1.2. Below the production packer
The internal pressure profile below the packer for a production well is that corresponding to full displacement of this section of the casing to hydrocarbons. Worst-case pressure calculations should be based on a pressure line with gas gradient extending from the pressure at TD. If the GWC in the structure is known, the chosen pressure line should be assumed to originate from this depth.
Where more information is available about the hydrocarbon phase behaviour, e.g. via PVT data from offset wells, a reservoir-specific gas gradient should be used. When hydrocarbons with a very low gas/oil ratio are encountered, the relevant oil gradient may be used. Although hydrocarbons with a medium gas/oil ratio will separate out once the well is shut in, it is very difficult to quantify a realistic internal pressure profile for this case. Hence, the maximum loading based on a gas column extending from the pressure at TD should be assumed. A suitable margin should be included if squeeze kill operations are to be considered.
For an injection well, or wells where stimulation treatment may be performed, the internal pressure profile below the packer should be that resulting from injection operations.
2.2 External pressure profile
See article Collapse Loads section 2.2
2.3 Special cases
2.3.1 Gas-lift wells
For gas lift completions, the most severe internal pressure loading above the packer is that generated during the kick-off process, when the kick-off pressure is applied to the top of the packer fluid.
2.3.2 Salt loading
Salt loading is a time-dependent phenomenon and since its onset cannot be accurately predicted, it should be assumed absent when calculating the external pressure profile for a burst scenario.
In gas-lift wells, a leak in the production casing may impose the lift-gas injection pressure on the annulus fluid column between the production casing and the intermediate casing. Special attention should be paid to the internal pressure profile for this latter casing in subsea well design where control of this pressure is not possible.