Typical cemented completion configuration, as applied on Cormorant A/North Cormorant well operations.
The potential downside of cemented monobore completions, such as remedial cementation, and the possibility of failing to get the string to total depth (TD) due to hole problems, has stopped companies from using this technology. But the need to deliver a low cost solution in today's high cost North Sea environment has driven KCA Drilling and Shell Expro to design and deliver the first cemented completion, challenging traditional concepts and standards.
The cemented completion concept is fundamentally a simple one. The reservoir open-hole section is drilled to the required depth, and following electric logging (if required), the completion tubing is run into the open-hole and cemented back inside the previous casing shoe or window. The christmas tree is then installed and the well perforated in the normal manner.
The advantage of cemented over conventional completions is commercial - it saves 5-7 days rig time during installation by eliminating such operations as running and cementing liner, wellbore clean up, and packer setting procedures. In addition, the amount of liner and completion accessories required, such as packers, liner hangers, PBRs (polished bore receptacles), nipples, and other elements, are greatly reduced. The savings per well due to time and hardware is £0.5-1.0 million.
Cemented completions already have been used in low cost operating areas around the world, but well CA-28S2 on Shell Expro's Cormorant Alpha platform marked the first cemented completion to be performed in the North Sea. At the time of this article's writing, two Cormorant Alpha and three North Cormorant wells have been successfully completed in this manner. All have demonstrated considerable cost savings as a result, with three of the five wells completed in 50% of the planned time.
CA-28S2 was selected as the ideal candidate for evaluating the method due to its short 6-in. open hole length of 708 ft and near vertical inclination. Since then, open hole lengths have been progressively increased, culminating in CN-28S1, which was successfully completed with 6,500 ft of 8 1/2 in. open-hole at 67° inclination.
The Cormorant A platform
Although the basic concept is simple, careful planning and attention to detail are essential if the operation is to be performed effectively. Prior to cementing, the tubing hanger is landed off, tied down, and pressure tested. The control and balance lines are attached back to the control system. The big bore safety valve dummy is then removed to avoid a restriction for the cementing plugs. Cementing takes place though the completion tubing, with returns back through the annulus valves. Both annulus outlets should be used to minimize back pressures.
Since cement acts effectively as the completion packer in this design, it is imperative that cement is returned back inside the previous casing window. Careful consideration to the cement volumes used must be given, and in these circumstances a LWD or electric line caliper log is invaluable. Extensive modeling is required to predict the likelihood of losses and channeling. Also, with the presence of control and balance lines, no rotation is possible during cementing. Optimal centralization therefore takes on added importance and again must be modeled.
Fallback options have been developed for most of the likely failure scenarios. If cement is not achieved back inside the window, for instance, one solution is to cut and recover the tubing above the top of the cement and then re-complete with an overshot and conventional packer.
Cementing is performed via a surface launch cement head. A single combination bottom plug is launched prior to cementation to confirm passage of the plug though the completion and calculate actual displacement volumes. Dual-combination top plugs are launched behind the slurry to minimize the risks of cement bypass and a cement sheath remaining inside the tubing. This is particularly important since the slurry is displaced with seawater with no planned clean-out prior to perforation.
Bumping the plug is important under these circumstances. Remedial cleanouts using coiled 2 7/8-in. pipe were performed, however, on the first two jobs, due to cement plug bypass and congealed mud residue respectively.
Learning points derived here included further simplifying string ID changes and using dual-top plugs behind the cement. Rigorous wellsite procedures have also been developed for clean out of surface lines prior to cement displacement.
Interestingly, early concerns surrounding the passage of cement and plugs through an unprotected safety valve nipple have proven to be unfounded. The nipple is greased internally prior to installation and hydraulic fluid is flushed through it continuously during the cementation. To date, no problems with the subsequent installation and testing of the safety valve have been experienced.
The tubing is pressure tested on bump, and both the tubing and annulus are inflow tested. Wireline runs are then performed to drift the tubing, clean the SSSV (subsurface safety valve) nipple profile and set a dummy or protection sleeve at this stage as required by the forward program.
Meanwhile, the cement slurry is designed to have achieved adequate compressive strength development at this time. A nominal annulus pressure test is then performed to in excess of the shoe fracture strength to ensure adequate well integrity prior top removing the blowout preventers (BOP) and installing the tree. Later, following the cement bond log, an annulus pressure test to full design pressure is performed.
The cemented monobore completion concept has been taken and refined as a proven method of delivering cost effective North Sea production wells. Much learning has already taken place along the way to ensure this.
Meticulous planning and attention to detail are critical to minimizing the risks. The results to date over the five production wells have been remarkable, with the revised economics now impacting on field development potential.