Full-bore isolation valves (FBIVs) and multicycle tools (MCTs) eliminate the need for installing a drilling rig with a completion riser during subsea tree installation, thus reducing the time and cost for completing these wells.
Shell International E&P Inc. used this Baker Oil Tools' disappearing plug technology for completing wells in its Crosby, Manatee, and East Anstey fields, all in deepwater Gulf of Mexico.
Based on Gulf of Mexico deepwater drilling-rig day rates and the fact that about two thirds of completion costs directly relate to the time required to complete a well, Shell projects that removing the subsea tree installation from the rig's critical path will save about 25% from the completion budget.
Shell completed wells in the Crosby project, the first application of the FBIV and MCT in the Gulf of Mexico, in less than 60% of the expected time and 20% below budget.
The wells did not require wireline or slickline work, other than for logging wells and setting sump packers.
Conventional tree installation
On a conventional single-derrick rig, crews must pull the marine riser and blowout preventer (BOP) stack before running the tree on drillpipe or with a completion riser system.
Each round trip of the BOP stack and marine riser, depending on water depth and weight or rig space limitations, can require up to 8 days, even in good weather. Costs can easily approach $2 million.
The conventional sequence for completing a well and installing the subsea tree is as follows:
- Complete the well, and set and test the barriers.
- Disconnect the BOPs and pull the marine riser and BOP stack.
- Run the tree on the completion riser.
- Remove the second tubing barrier.
- Pull the completion riser.
- Install jumpers and umbilicals and turn the well over to the host facility.
The first five of these six steps typically occur on the rig's critical path.
Alternate subsea equipment installation methods, which eliminate the need for a BOP stack trip in between each completion, can save significant time and cost in multiple well developments.
For example, installation vessels have run tubinghead spools and subsea trees on rig-based winches and on wire. But even if one installs all trees in a development by alternate means, the deployment of the completion riser and removal of the second tubing barrier requires the BOP stack be pulled at the end of the program.
Alternate barriers
The disappearing plug provides a barrier to well flow when crews remove the BOP stack and marine riser from the well and thus is the key for removing the subsea tree installation from the rig's critical path.
In subsea development projects, government regulations and safe operating practice require a dual-barrier system at all times between the reservoir and the environment. Typically a closed surface controlled, subsurface safety valve (SCSSV) and a backpressure valve provide these barriers.
For its deepwater Gulf of Mexico developments, Shell uses a standardized, vertical, guidelineless, subsea tree system developed in an alliance with FMC Inc.
The standard tree system includes a tubinghead spool locked onto a wellhead, a tubing hanger, and a subsea tree (Fig. 1).
Among this system's advantages is an integrated annulus bypass circuit around the tubing hanger that eliminates the need for an annulus bore. Instead, a valve operated by a remotely operated vehicle (ROV) provides annulus access. This inherently is more reliable than the wireline plug it replaces.
The concentric monobore tubing hanger has a 4-in. bore that contains a landing nipple profile to accommodate a wireline lock mandrel, or tubing-hanger plug. The Shell-FMC standard tree system uses the tubing-hanger plug to replace the backpressure valve as the second tubing barrier.
The FBIV-MCT disappearing plug tools perform the same well barrier function as the tubing-hanger plug but permit opening of the valve remotely when required, without well intervention (Fig. 2.).
Disappearing plugs
The search for an alternate barrier system originated as an effort to simplify well completions by eliminating the need for slickline intervention, particularly during setting of production packers.
Slickline operations in deep wells or deep water can consume time and involve substantial risk of lost or stuck tools. Additionally, remediating slickline tool problems may lead to extensive and costly intervention operations.
The search for an alternate barrier system for setting a packer made clear that the ideal system would also provide a tubing barrier that could meet regulatory requirements. This realization led to the development of disappearing plug technology, which offers several advantages over conventional barrier systems.
Disappearing plugs are set deep in the well, where the potential differential pressure across the barrier is less than across a plug at surface.
A second advantage concerns hydrocarbon migration. In a suspended live well, hydrocarbons migrate up to the first solid barrier, which conventionally is the SCSSV, located thousands of feet up the wellbore.
The SCSSV also allows a specified leakage rate, which creates the potential for hydrocarbons to migrate up to the wellhead.
A deep-set disappearing plug, however, holds solidly from below and eliminates any hydrocarbon migration into the tubing string.
The disappearing plug creates an inherently superior barrier because it is run and tested as an integral part of the tubing string rather than run separately on wireline.
Finally after the installation of the subsea tree, the capacity of the plugs to be opened when desired from the host platform without well intervention eliminates the need for a completion riser for well completion operations and enables the BOP stack and marine riser to stay down for the entire duration of a multiwell completion program.
Shell conducted an extensive review of the capabilities and functionality of commercially available equipment before selecting the appropriate disappearing plug for its Gulf of Mexico subsea completions. The review included:
- Pressure and temperature ratings.
- Number of open-close cycles available.
- Ability of the barrier to hold from both directions.
- Reliability over long durations.
- Placement location of the tools in the production string.
- Functioning properties of the tools.
- Overriding capabilities and ramifications to the optimized installation process.
The review chose the full-bore isolation valve and multicycle tools because of their optimum functionality and run histories.
FBIV, MCT
As part of the tubing string, the FBIV and MCT are run together below the production packer.
The FBIV is a single action, disc-type disappearing plug or valve that holds pressure from both above and below to provide isolation within the tubing string.
Normally closed, one cycles the FBIV open after applying a predetermined number of pressure cycles to the tubing. A pretensioned spring forces the flapper or disc to the open position, and a flow tube drives down to isolate the flapper.
The FBIV incorporates a mechanical override profile and also is coiled-tubing millable (Fig 3).
The MCT is a sliding sleeve that is run in the open position above the closed FBIV. It allows the tubing string to self-fill while being run in the hole.
After landing the tubing hanger and setting the tubing string on depth, one permanently locks the MCT closed by applying internal tubing pressure and creating a pressure drop across the tool.
The number and size of the circulation ports in the MCT determine the circulation rate and pressure drop. An external pressure differential will not close the MCT.
Both the FBIV and MCT can be sized so that they do not restrict the tubing bore. Both tools are closed after landing the tubing hanger.
Setting the production packer requires pressure be applied against the FBIV and MCT. Holding and charting this pressure allows assessment of the integrity of the tubing string from the tubing hanger to the FBIV and MCT.
One can remove the BOP stack after demonstrating a complete barrier by successful pressure tests of the FBIV and MCT, the SCSSV (from below), the production packer, and the annulus access valve around the tubing hanger.
The tubing string then remains open to the environment above the SCSSV until installation of the subsea tree.
The use of the FBIV and MCT as a barrier system reduces the well completion-tree installation sequence from six to four steps, as follows:
- Completing the well and setting and testing the barriers.
- Disconnecting the BOPs and skidding the rig.
- Running the tree on an alternate installation vessel.
- Installing jumpers and umbilicals and turning the well over to the host facility.
Only the first two steps of this shorter sequence are on the rig's critical path. After one disconnects the BOP, the rig can begin completion operations on another well in the same cluster or to pull the marine riser and move to the next assignment.
After installing the subsea tree, one can test the connector cavities with an ROV, and then commission the tree from the host facility. Pressure applied down the wellbore with the subsea chemical injection system opens the FBIV.
To function, the FBIV must be in an underbalanced state, which results from removing the "riser margin," the hydrostatic pressure difference between the completion brine and seawater at the wellhead depth.
Opening the FBIV is by application of pressure to the tubing string until it reaches activation pressure, which is the recorded pressure before running the tool plus the riser margin.
One then bleeds off this pressure and repeats the cycle up to 11 more times before the FBIV opens.
The FBIV opens on the bleed-off rather than the pressure-up cycle to avoid surging the formation. On all previous pressure cycles, the tubing is bled off to hydrostatic pressure imposed by the chemical injection system at the wellhead depth.
When the FBIV opens on the last cycle, the pressure bleeds off to a higher value because the system is now open to the underbalanced formation, and the well is ready to flow.
Crosby prospect
Shell's first application of the FBIV and MCT disappearing plug technology in the Gulf of Mexico was at its three-well Crosby subsea oil development, in 4,400 ft of water. This was the first time the industry used the tools in the Gulf of Mexico, although it had used the tools for several years in other areas.
The clustered Crosby wells tie into the Ursa tension leg platform, which is 10 miles away in 3,900 ft of water.
Crosby reservoirs are between 17,000 and 18,000 ft beneath the seabed. The wells have moderate-to-high deviation.
The well completion plan included contingencies in the event that the MCT did not close or the barrier system failed to test.
Contingencies included use of wireline-set tubing plugs to set the production packers and in the tubing hangers to act as barriers to well flow.
Shell made preparations to use the full drillpipe riser system because these contingencies would require a completion riser to remove tubing hanger plugs.
Hydrate inhibition for flow assurance also required a change in procedure from the base case, traditional-barrier plan.
In a conventional completion and subsea tree installation, one bullheads the wells with methanol to the SCSSV depth prior to setting the plugs. The methanol inhibits hydrate formation in the event any hydrocarbons migrate past the SCSSV to the wellhead.
The FBIV-MCT well completion plan included procedures to open the FBIVs from the Ursa host platform through one of the methanol injection lines at the subsea tree.
Pressure response on the methanol system indicates when the FBIV actually opened. After opening, one then bullheads a volume of methanol into the tubing string.
Shell completed the first two Crosby wells with FBIVs as barriers and installed the trees from a specialized rig-based winch in record time.
By the start of the third completion, Shell had saved enough rig time that the well completion operations dropped from the rig's critical path. But because the host facilities would not be commissioned in time to open the FBIVs before the rig left the field, Shell changed the plans and ran the last of the three subsea trees with a drillpipe riser system and then "hopped" from well to well to open the FBIVs and bullhead methanol into the tubing strings.
The operation was flawless, and the work opened all FBIVs as planned, demonstrating the viability of the technology.
Manatee, East Anstey
The tools and procedures used on the Crosby project then became the basis for subsequent well completion plans for the Manatee and East Anstey projects in 1,939 ft and 6,623 ft of water, respectively.
Shell successfully opened FBIVs on two Manatee wells from the Bullwinkle host platform, 17 miles away. This eliminated the need for the rig to be on location during installation.
The East Anstey completion included the use of an FBIV and MCT to set a Baker Premier packer. The work established a new Gulf of Mexico subsea completion time for Shell that cut almost a day off the previous best time.
The rig left the location after the packer was set at a 15,049 ft. Shell will open the FBIV remotely from the Na Kika host platform when it arrives on site.
The Na Kika project includes an additional five similar completions to the East Anstey well.
Acknowledgment
This article contains information from Paper No. SPE 77712, presented to the SPE Annual Technical Conference and Exhibition, San Antonio, Sept. 30-Oct. 2, 2002.
The authors
Craig Stair is a senior staff completions engineer for Shell International E&P Inc., New Orleans. Stair has a BS in engineering from Harvey Mudd College.
Joe T. Stuckey is a technical representative for Baker Oil Tools in New Orleans. During the last 6 years, he has worked on many of Shell's deepwater projects. Stuckey holds a BS from Louisiana State University, Baton Rouge.
Graeme Walker is a senior applications advisor for Baker Oil Tools in Houston, where he works in the completions group. Graeme previously was the operations manager for Ocre Scotland.
