SURFACE, PROTECTIVE, AND PRODUCTION STRINGS

essentially the same functions as in wells drilled on land and with bottom founded offshore rigs. The design burst, collapse and tension loads assumed for design are the same as used on other wells except for the effect of water depth on casing back-up pressure used for burst and collapse design.

With floating rig operations, casing strings are landed in a subsea wellhead and a seal is installed to isolate the external casing annulus from the wellbore. After the seal is set, the pressure in the annulus is typically never monitored again. While it is possible to unset and/or remove a casing annulus seal assembly (prior to subsequent string being set) this is generally not done. After a subsequent casing string is hung in the SSWH, even this option is no longer available.

When a casing annulus is sealed creating a trapped volume, pressure testing the casing hanger seal assembly will be a critical operation. The pressure test volume must be carefully monitored to ensure the seal is set and test pressure is not being applied to the entire trapped annulus. On several occasions, test pressure has leaked past a leaking seal assembly and, since the test pressure exceeded the casing collapse rating, the casing string was inadvertently collapsed. Prior to the 1980s, casing hanger seal

assemblies used elastomeric seals, and leaks were common. Most of the casing hanger seal assemblies today use metal-to-metal seals, and leaks in these seal assemblies are less common.

When cold mud in a trapped annulus is heated by bottom hole temperature, the pressure in the annulus can reach several thousand psi due to thermal expansion of the fluid. This problem is thought to have led to at least one complete wellbore failure (20). Generally the worst design case occurs (highest increase in temperatures) after a well is placed on production.

To prevent annulus pressure build-up in wells drilled with floating rigs, mitigation options used include ensuring annuli are not sealed with cement (optimize casing setting depths, etc), installing pressure rupture disks, use of insulated tubing strings and use of

crushable foam in the annulus. The risk and operating considerations for providing a method to access casing annuli with an ROV have also been considered.

Trapped casing annuli can also cause problems with connections on the casing. Most casing strings have connections designed to contain internal pressure only. An external pressure higher than the internal pressure is not a design criteria for most casing strings. Special connections which seal both external and internal pressure are often used on critical wells drilled with floating drilling rigs.

There are two commonly encountered situations with casing annuli that will affect burst casing design for wells drilled with a floating rig. In most cases, the top of primary cement is left below the shoe of the last casing string set. This permits any pressure increase in the casing annuli to “bleed-off” to formations exposed below the last casing shoe. In some cases and for a variety of reasons, the top of primary cement will seal the casing annuli at the last casing shoe. This creates a fixed trapped volume in the casing annuli. These two cases are shown in Figure 2.16.

Annulus Cementing Options

Riser Riser Seal

Assembly 36-in. 36-in. Top of Cement 20-in. 20-in. Top of Cement Void Mud Cement 13 3/8-in. 13 3/8-in.

Annulus Not Sealed With Cement Annulus Sealed With Cement

Figure 2.16 - Casing Annulus Options, Wells Drilled With a Floating Rig

BURST LOADING

The following guidelines are recommended for calculating annulus pressures for burst design of casing strings when the strings are landed in a SSWH. The guidelines depend on whether the casing annuli is sealed with cement at the last casing shoe.

The typical case found with casing strings set in wells with floating rigs is not to seal the annulus with cement. This is also the preferred method of preventing excessive pressure buildup in casing annuli. Figure 2.17 illustrates this design condition. Typically it is possible to place casing strings so that primary cement will not seal the casing annulus at the previous casing shoe.

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With this case, fluids and pressures in the casing annulus change with time. Pressure at the casing annulus seal assembly is assumed to balance the local formation pore pressure below the last casing shoe. Depending on water depth, casing setting depth, mud weight and exposed formation pore pressure, the mud left in the casing annulus may or may not drop as shown in Figure 2.17.

Annulus Not Sealed W ith Cement

Riser Riser Seal

Assembly

36-in. 36-in.

Mud Drop

20-in. 20-in.

Top of Cement Top of Cement

Void Mud Cement

13 3/8-in. 13 3/8-in.

No annulus mud drop Annulus mud drop

Figure 2.17 - Casing Burst Design, Annulus Not Sealed With Cement

The recommended pressures to use in burst design when designing casing for floating operations when the annulus is not sealed with cement are:

1. Assume that the mud in the casing annulus will drop below the seal assembly to a depth that the setting mud weight will balance the local pore pressure at the shoe, then use zero backup from the seal assembly to the top of the mud column.

2. Next use setting mud weight gradient from the top of the mud to the previous casing shoe.

3. Then use the local pore pressure gradient from the last casing shoe to the design string setting depth.

Appendix 2 includes an example showing how this recommended method can be used when designing for burst conditions.

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EXXONMOBIL FLOATING DRILLING SCHOOL 2002 EDITION

The presence of shallow hydrocarbons can complicate the goal of leaving casing annuli non-sealed. It is common practice to cover all hydrocarbon intervals with primary

cement, and this is a regulatory requirement in many areas such as the GOM.

When a hydrocarbon zone is near a previous casing shoe, it can be difficult to cover the hydrocarbon interval with cement and still leave the shoe at the previous annulus open, not sealed with cement. It may be necessary to use less than optimum casing setting depths to leave casing annuli open after hydrocarbon zones are properly cemented. In a few cases, it may be necessary to seal a casing annulus with cement creating a trapped volume. When this condition exists, the hydrostatic pressure trapped below the seal assembly cannot bleed-off to the formation. For this case, the recommended pressures for use in burst design are:

1. Use zero psi burst backup pressure at the seal assembly.

2. Use setting mud weight from the seal assembly to the top of cement.

3. Use a 9.0 ppg gradient for the cement column (from top of cement to the outer casing shoe depth).

4. Use local formation pressure gradient from the outer casing shoe depth to the casing setting depth.

COLLAPSE DESIGN

For collapse design of strings landed in a subsea wellhead, it is recommended that the external pressure be assumed to be the casing setting mud weight. Credit is not taken for possible pressure reduction due to fluid loss to exposed formations below the outer casing string (even if the annulus is not sealed with cement). The worst case assumption is that permeable formations do not exist below the outer casing shoe.