COMPLETION TECHNOLOGY: Part I: Reducing completion costs in deepwater subsea developments

Carrying ideas through to reality

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PART I: This is Part 1 of a two-part series on completion costs in deepwater. Part II will appear in the August issue.

One of the largest components of the cost of deepwater (greater than 1,500 ft water depth) subsea developments is the day-rate of the drilling rig spread, combined with the substantial costs of the normally required installation tools and other equipment that must be installed on the rig during completion work.

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In an effort to reduce these substantial capital costs, several combinations of drilling vessels (MODUs) and construction vessels over the past several years have been rented or purchased for some specific pieces of equipment. Shell Deepwater has also studied the entire completion process thoroughly, identifying opportunities for improving effiency and eliminating all but essential activities.

The efforts have proved worthwhile, saving literally millions of capital dollars over four of its most recent major subsea projects in the Gulf of Mexico and promising to greatly improve the profitability of its future subsea projects.

Estimating the costs of the first deepwater subsea developments in the early 1990s and several portions of the cost areas were highlighted for immediate further study. As these study efforts grew, standardization of subsea equipment and value engineering quickly began to show promise, but it was evident that this would require a substantial investment of time and considerable cooperation from the leading industry suppliers.

However, investigating the more efficient use of existing equipment such as the MODU spread itself and improvements in the design/use of the existing equipment that have been historically required during well completions promised immediate substantial savings. After its initial experiences with Tahoe (1,500 ft water depth), Popeye (2,040 ft), Mars (2,900 ft) and Mensa (5,200 ft), Shell Deepwater Services (SDS) continued its focus on improving the profitability of subsea developments, capturing the learnings from these projects and applying them to the early planning stages of the next group of subsea projects. Concentrated efforts were made at several specific targets, such as:

  • Efficient utilization of the MODU on location (deck layouts, subsea tree handling equipment capabilities, interfaces with completion tools/equipment)
  • Proficient use of existing tools and procedures (technical limit completion exercises)
  • Development of new more efficient tools (more efficient completion riser designs, use of a larger winch for lowering subsea equipment packages to the seafloor, a subsea-releaseable BOP funnel)
  • Overall technical review of the entire completion process (unloading the well to the pipeline, instead of conventionally unloading to the rig)

US Gulf developments

The first Tahoe deepwater subsea development project using 4th generation MODUs built in the mid-1970s was completed. The next several subsea projects utilized similar MODUs with variable deck loads averaging from 3,000 tons to 4,500 tons. With the Popeye and Mars subsea wells at 2,040 ft and 2,900 ft water depth, respectively, deck space was already a critical issue, along with limited crane capacities for lifting the required equipment onto the rig from supply boats.

Weather downtime due to the different MODUs' motion characteristics also became a more noticeable problem. All the while, the number of planned subsea developments was rising fast. Therefore, in expectation of the increased demand on MODUs suitable for completion work in deepwater, contracts were entered into with Noble Drilling to convert two submersible, shallow-water drilling rigs into two semisubmersible deepwater MODUs. Several other new-build rig contracts were subsequently initiated in order to meet planned deepwater drilling commitments (up to 10,000 ft water depth) over the next several years.

The suitability of current MODU designs was not the only issue in stepping out to deeper water. Installation techniques, specifically the completion riser connection of the subsea tree to the rig, had to be reviewed closely. Structural strength and pressure-containing capacity were the first hurdles to overcome.

The first well at the Tahoe field development (1,500 ft water depth) was a simple installation, by today's standards, using guidelines and a refurbished direct hydraulic controlled dual-bore non-jacketed riser. Looking forward to deeper water (up to 6,000 ft water depth), development of a high-pressure riser system with electro-hydraulic controls (in order to speed response time for control signals) became a necessity.

Concentric riser

An equipment supplier entered into a unique agreement that allowed spreading the costs of developing a unique deepwater "concentric" riser system in stages over the life of three subsea projects. The agreement also allowed the third party to enjoy a semi-captive rental agreement and the opportunity to enter a new market, since they were already an established ROV service company.

The successes in the use of the riser on the Popeye and Mars projects and the planned further development of the riser for use on the Mensa project were previously presented to the industry. In using the concentric riser, Shell was able to stretch the world record for deepwater completion depths. However, the problems of heavy riser joints due to the concentric design, slow running speeds and a general lack of reliability of the particular multi-plexed electro-hydraulic (MUX) control system, caused Shell to seek alternatives for a completion/workover riser.

After several deepwater completions, the extremely high costs and the increased amount of specialized equipment predicated a study of the absolute minimum requirements to complete a deepwater subsea well and get it producing to a platform or remote facility. Up to this point, deepwater well completions were being carried out in a similar manner to shallow water completions.

The well was completed using the MODU's blowout preventer (BOP) stack and marine riser, then the marine riser was retrieved and offloaded from the MODU to free up deck space. The subsea tree was brought out to the MODU, tested on deck and installed using a completion/workover riser which also served to carry released hydrocarbons to the rig during the unloading and cleanup of the well.

The testing of the tree and the riser system required the exclusive use of the moonpool area and limited other operations on the rig. The produced fluids were processed and/or flared by specialized crews using equipment installed onto the decks of the MODU. All these activities were individually identified and examined as part of the new "technical limit" initiative that originated in the drilling group.

By adding certain equipment to the MODU, such as a new tree handling system and modifying the BOP stack to accept a new subsea releasable BOP funnel, the amount of time required for installing a deepwater subsea tree has been dramatically reduce. Eliminating the production of hydrocarbons to the surface after the subsea tree is installed by unloading the well directly to the flowline contributed further to the reduction of rig time since the requirements for a completion riser were reduced and faster running alternatives could be utilized.

New design MODUs

Actually, the design of Noble's Jim Thompson and Paul Romano is not really new. The rigs were built in the 1970s as submersibles for use in shallow water. With major structural additions (new derricks, new BOP stacks, new marine risers and other new drilling support equipment) the rigs were contracted for water depths of up to 4,500 ft.

The conversion work was performed at Pascagoula, Mississippi. The triangular shapes of the rigs presented a novel approach in improving vessel motion characteristics, but they had never been applied as a standard MODU design. Preliminary investigation showed that the tri-shaped hull design would be an improvement over previous designs, but exactly how much was dependent on too many variables to be quantified without extensive testing. The most influential change in the design of these rigs compared to previous drilling rigs was that each rig was equipped with a unique subsea tree handling system.

An extensive interface study was performed on the Noble rigs to check all interface requirements between the rig and the completion equipment that is necessary to use during completion operations. This included interface requirements of both the Sonsub and the FMC completion riser systems with the derrick handling equipment, as well as checking interfaces between the BOP stack/marine riser and the completion equipment. Some of the particular interface areas were: deck layouts, riser analyses, deck extensions, reel locations, tensioner interface, rotary table/riser, spider interface, surface tree issues, completion riser storage, marine riser storage, and riser cleanliness.

Finally, a thorough check of the interfaces with the tree handling system and the subsea tree system with both completion riser systems was performed. Since this was a new design presented by Noble, consisting of a trolley mounted underneath the rig decks and an elevator at deck level allowing the subsea tree to be lowered to the trolley, all structural engineering analyses of the system were reviewed. Some of the particular areas studied for the trolley system and the elevator system were:

  • Initial dynamic analysis check
  • FEA model and review
  • Addition of tree guidance structure
  • As-built dimension checks
  • Commission procedure review
  • Mock-up tree test
  • Work platforms/lighting issues

New design BOP funnel

Out of one of the interface checks from above, a novel design to replace the standard BOP stack funnel was developed. After a well is drilled, cased, and tied-back, some type of guidebase or tubing head spool (THS) must be installed onto the wellhead to receive the tree. Historically, the BOP stack (with a funnel facing downwards) must also be released from the wellhead and retrieved to the surface in order to have the downward-facing funnel removed so the BOP stack connector (now bare or with a guide shroud) can then mate with the funnel-up on the THS. As soon as the THS is installed (usually by running on drillpipe through the moonpool), the BOP stack is landed onto the new wellhead profile in the THS to resume completion operations.

On the Mensa project, a funnel tied onto the stack with wire slings was used. The THS was run subsea on drillpipe prior to beginning completion operations and parked on a parking pile. When the BOP stack was finished with the drilling operation, the rig moved over, the wires holding the funnel were released by the ROV, the funnel was retrieved to the surface and the marine riser/BOP stack was hung off on its tension wires.

The marine riser/BOP stack was used as a conduit for drillpipe to extend down to the THS through the bottom of the stack where an ROV attached wire slings to the THS, allowing the drillpipe string to lift and move the THS onto the wellhead. Although this was successful, many operators dislike the idea of hanging the marine riser/BOP stack on the tension lines without any controlled compensation.

A design for a subsea-releasable funnel (patent-pending) that is controlled by the BOP control system was developed. It may be released and re-attached subsea without retrieving the stack to the surface. Now, when the BOP stack is finished with the drilling operation, the rig may be released from the wellhead and moved away, the funnel can then be released and parked either on a pile or retrieved to surface via a downline.

The THS can then be installed on the wellhead via a downline or via drillpipe (in the case of a dual-derrick rig). After the THS is installed on the wellhead and tested, the rig can move back over to the well and land in the funnel facing up on the THS. Saving a round trip of the marine riser in deepwater can easily amount more than $1 million per trip. Two of the new funnels are now installed on both the Noble rigs.

Tree handling system

A combination of a trolley under the rig and a main deck-level elevator system to lower the tree to the trolley allowed the subsea tree and its associated control system/running tools to be stacked up and tested totally offline from any ongoing rig floor operations. Using a conventional handling system, the stack-up and testing of the tree and its running tools require the BOP stack to be clear of the moonpool.

The Noble design saved up to a full day of rig time by allowing the testing of the subsea tree to occur prior to moving the tree to the moonpool. In addition to the time savings in testing, the Noble design suspends the tree underneath the rig floor, supported by bracing while it is in the moonpool.

When the tree is ready to launch, it is a simple operation to retract the trolley away from the tree, allowing it to enter the water quickly and under more severe weather conditions. On Europa, it was possible to launch one of the subsea trees in seas of over 8 ft. This is a dramatic improvement considering that the Mensa project on stand-by for over eight days, waiting on 6-ft seas to calm down enough to release the tree from the moonpool.

Total cost for the delays to the Mensa project using the normal method used to launch a subsea tree was almost $2 million. On the Noble rigs, using the new launch capability, no weather stand-by has occurred for this operation in the last seven installations.


Recognized for their contributions are the following: SEPCO completion engineers for Macaroni and Europa; SEPCO completion foremen from both teams; Noble Drilling, Intec Engineering, Horizon Engineering and FMC; SEPCO completion engineer in open water operations planning (developing drillpipe riser concept for Macaroni); riser engineering manager at FMC (development of monobore completion riser system); lead service technician from FMC; and Shell-BTC (refining tree wireline and multiple riser analyses).


Guinn, R., Parks, W., Forster, L., Pritchard, J., "Propeye Project: Completion Riser/Workover Control System," OTC 8128, 1996 Offshore Technology Conference, Houston, May.

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