【本周專題：完井】膨脹工具解決大量井下難題（中）

CASING ANNULUS PACKER

A casing annulus packer (CAP) is manufactured onto a joint of standard API casing. The components of a CAP include a valve sleeve (which is fixed to the OD of the casing), the inflation element, and a sliding end. During inflation, one end of the packer slides to allow the OD to increase. The most common CAP application is for secondary cementing or off-bottom cementing, where a stage tool or cementing port collar is placed above the CAP to allow the pumping of cement to the surface. The CAP is often used on intermediate casing strings, when it is not possible to get cement to the surface, due to low bottomhole pressure.

These wellbore sections are typically drilled fast and not calipered, and therefore large wash-outs are common. While every effort is made to place the packer in a gauged section, sometimes the packer is set in a washout, which may result in over-expansion, causing the inflation element to rupture. Furthermore, if the annulus is on losses, regaining casing integrity can be difficult, because there is more hydrostatic pressure at the CAP on the ID of the casing than on the annulus. The valve sleeve is designed to lock-out in the event of a rupture, but an overbalance scenario can prevent this. While experience shows that this is a low-frequency event, the possibility of an occurrence requires a solution.

To address the inability to shut the valve, in the described unbalanced scenario, a new valve design was required to protect against this scenario.

New shut-in valve. To solve the issue, new technology was incorporated into the valve sleeve to provide redundancy, to ensure casing integrity is maintained once the packer is set, no matter the fluid level in the annulus. The technology is patent-pending and available in any size of casing annulus packer. Field trials have been successful in the Permian basin, in wells with 9 5/8-in. intermediate casing. In the Permian basin, and in other applications, it is common to have a low fluid level in the annulus, or for the annulus to be on losses in the intermediate casing section.

The basic operation for a two-stage cement job is to pump the primary cement job through the float shoe. Then, the wiper dart lands on the float collar and pressure is increased to inflate the CAP. After the CAP is set, additional pressure is applied to open a stage tool. Following, an opening plug is dropped. The second stage job is then pumped and a closing plug lands on the stage tool to close it. In the event of a ruptured packer, the new valve sub is activated to ensure casing integrity. The contingency plan at this point is typically to wait a few hours for the cement to setup on the primary job before opening the stage tool to pump the secondary job.

The CAP has a 10 ft seal with a stage tool on top. The packer was inflated as designed and the secondary cement job was successfully pumped. The service provider’s new technology ensures that in the unlikely event of a ruptured packer, casing integrity can be immediately reestablished by activating the new valve system.

THRU-TUBING WIRELINE INTERVENTION

An inflatable bridge plug or packer can be set using wireline or slickline. A battery operated system is used to deploy and set the tool. Downhole electronics are used to control the inflation process through a motor/pump assembly.

Depending on how critical an exact setting depth is to operational success, the operator can use a wireline or a slickline. For applications where the setting depth is critical, wireline is used because it can run a gamma ray and casing collar locator for correlation prior to setting the tool.

A solution may require either a bridge plug configuration or a packer configuration. In the case of a packer, the application is typically to use a scab liner to isolate a section of the wellbore. A recent case history required such an approach. A well in deep water experienced pressure on the “A” annulus and regulators required the operator to locate and repair the leak. It was determined that an isolation packer was leaking. One option would have been to mobilize a rig and pull the upper completion to replace the isolation packer.

But this was an older well producing at low flowrates (1,500 bpd), so an expensive intervention with a rig was considered uneconomical. A rig-less operation therefore was considered using inflatable packers deployed on a wireline system.

Inflatable technology was chosen because a restriction in the completion would not allow conventional mechanical packers to pass. The leaking isolation packer was positioned above a ported sub. The proposed plan was to set a packer below the ported sub on one run, and then set an upper packer equipped with a blank interval of pipe beneath it, to “sting” into the top of the lower packer. This would isolate the ported sub while allowing flow through the scab assembly.

The upper packer assembly was designed to sting into a polished bore receptacle (PBR) that had been left looking up after the lower packer was set. The upper packer assembly was then latched into the PBR. Shear pins in the latching mechanism allowed this assembly to be retrievable. In this case, the packers were set successfully. Once the scab liner was in place, the well was put back on-line and slowly ramped up to the previous 1,500 bpd production rate. No pressure was seen on the “A” annulus meeting the regulator requirements. This intervention was done at approximately 5% of the estimated cost of a rig-based solution. The expandable remedy is ideal for offshore developments that are in the later stages of production, where flow rates and pressures have been reduced.