SPECIAL REPORT: Long intelligent completion assemblies save rig time

April 23, 2007
Running extra-long intelligent bottomhole assemblies (BHAs) reduced rig time for completing wells in the ultradeepwater Independence project in the eastern Gulf of Mexico.

Running extra-long intelligent bottomhole assemblies (BHAs) reduced rig time for completing wells in the ultradeepwater Independence project in the eastern Gulf of Mexico.

Anadarko Petroleum Corp. operates the project that will bring on line 1 bcf/day of previously stranded gas.

The $2 billion project, scheduled to begin production in fall 2007, will tie together 10 gas fields in record-setting water depths of 8,000-9,000 ft (Fig. 1). These fields would be uneconomical to develop on a standalone basis (OGJ, Nov. 27, 2006, p. 43).

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The project’s production will add about 2% to the US supply of natural gas and account for about 10% of the natural gas produced from the Gulf of Mexico.

Anadarko selected Baker Oil Tools’ InForce intelligent well systems (IWS) with HCM-Plus shrouded and nonshrouded hydraulic flow control valves, Premier removable production packers, and Neptune safety valves to complete the project’s high rate, subsea, multizone wells.

To reduce installation time, Anadarko became the first operating company successfully to pre-assemble and test 90-ft plus completion assemblies and install them as a single unit rather than multiple components.

Anadarko and Baker Oil Tools devoted 18 months to project planning that involved equipment design, as well as designing and implementing lifting and transportation devices. This work thus far has enabled five successful intelligent well completions in four fields, while saving 12-14 hr of rig time/installation.

Fewer connections and pre-assembling and testing in controlled shop conditions away from the rig have improved reliability and assembly integrity, as well as reduced risk.

Extending technology

The Independence project is one of the industry’s most ambitious attempts to extend the limits of production technology. The fields are in deeper water than any other offshore development, and they will produce through a floating production system, subsea tieback, and pipelines installed in the deepest water to date.

The subsea umbilicals will contain about 1,100 miles of steel tubing, and flowlines will exceed 200 miles in length.

Flow-assurance measures will include chemical injection to control paraffin and scale, with hydrates controlled from subsea trees. Subsea wells will be frac-packed for sand management and production optimization.

For Anadarko and its partners (Dominion Exploration & Production, Devon Energy Corp., Murphy Oil Corp., and Hydro Gulf of Mexico), water depths and subsea infrastructure required team members to reach new levels of collaboration and technical innovation. The project complexity was heightened by the fact that the development involved contracts with several different service companies rather than a single vendor.

Anadarko as project operator developed a coordinated plan with one hub facility and a single hydraulic power unit (HPU) to power the control systems for all subsea wells in the project.

Studies of wells throughout the area formed the basis of a standardized development plan designed around a single set of parameters and standardized equipment for all wells rather than specific sets of parameters and equipment for each well.

The intelligent well completions with extra-long-assemblies were developed in keeping with the standardization philosophy and as a way to minimize BHA handling time.

Completion design

Spiderman field will be one of the first to come on stream, in fall 2007.

The dynamically positioned Transocean Deepwater Millennium drillship drilled and completed the wells in Spiderman.

The operator based the well completion design on the need to remotely control two frac-packed zones, produce the zones sequentially, monitor downhole conditions, and provide flow assurance. In addition, reducing rig time and ensuring reliability and safety were other critical needs for optimizing the installation.

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The selection of the InForce intelligent well system (IWS) was based on its functionality, inherent simplicity, and proven reliability. The selected intelligent control system (Fig. 2) includes:

  • Two 4½-in. flow control valves: one shrouded to control flow from the lower zone, and the other nonshrouded to control the upper zone.
  • A 9 7/8 × 4½-in. feed-through removable production packer V0 (zero gas leakage) rated as per ISO 14310.
  • A splice sub above the packer to house all control lines and cable splices.

The hydraulically operated control valves are controlled from surface and provide open-close functionality for multizone applications. The system includes a subsea control unit with hydraulic control lines that operates a balanced hydraulic piston for actuating the sliding insert in the valves. The piston develops an axial load exceeding 15,000 lb in both upward and downward directions to help overcome debris and scale buildup.

The valves have a diffuser ring system and equalizing slots that allow repetitive opening under high differential pressures, and a testable jam-nut connection ensures sealing integrity of the control chamber under extreme conditions. The valves’ gas-tight, chemically inert seal system protects them from erosion.

The removable production packer has no body movement during setting, which protects control lines fed through the packer during packer setting. A slip-element-slip configuration provides permanent packer-like performance, but with removability.

In addition to the IWS system, the single 93-ft BHA has a triple-gauge mandrel, chemical-injection mandrel, and depth-correlation sub and pup joints.

The triple-gauge mandrel holds three downhole permanent pressure-temperature gauges, provided by another supplier. These three gauges provide real-time pressure and temperature monitoring of each zone, as well as the tubing.

The dual chemical-injection system, also from another supplier, provides a method for treating the well against potential scale and paraffin accumulation.

The single 93-ft long BHA expedites the installation process and saves valuable rig time.

The installation process includes connecting and testing all control lines, cables, and chemical-injection lines before lifting the assembly to the rig floor. Having all lines attached to the BHA before its make-up to the production tubing meant that the BHA could not be rotated.

The assembly, therefore, has a Baker quick connect for connecting the assembly to the tailpipe without the need for rotation.

The water depth (deepest of any intelligent well system installation to date) required installation of a deep-set safety valve, which in this case was Baker’s nitrogen-charged Neptune safety valve.

The safety valves throughout the field were set with a standardized common pressure charge in the nitrogen chamber.

In addition to safety valve selection, deep water complicates completion string space-out. To compensate for any potential space-out error, the completion string included a 40-ft seal assembly in combination with a 20-ft seal-bore extension.

Installation approach

Intelligent well systems require several control lines and cable connections that are normally pressure tested after make-up. This process requires considerable time, which varies depending on the number of zones completed and instruments used.

In deepwater and ultradeepwater operations, rig time is expensive. Eliminating or reducing rig critical path time is paramount for project economics.

Working from this premise, Anadarko instituted the new installation approach of using the extra-long completion assembly. The rationale behind the approach was that the single-activity Deepwater Millennium could handle 90-ft joints of riser; thus, it had the ability to handle extremely long BHAs.

Onshore lift tests ensured the functionality of the compensating sling used for lifting the long bottomhole assembly offshore (Fig, 3).
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The risk-reward relationship promised big dividends if the approach succeeded. But the approach did required careful planning to mitigate any additional risk.

The planning revolved around addressing several concerns:

  • Would it be possible to safely pick up long assemblies on the single-activity drillship?
  • Would it be possible to eliminate bending and damage to intelligent well components?
  • Could components be tested on deck prior to going in hole?
  • Could logistics, such as transportation, be addressed satisfactorily?

Handling of the BHA required compensating slings. To ensure the functionality of these slings, the project team developed proper procedures and performed lift tests before shipping the equipment offshore (Fig, 3). Finding the balance point for the subassemblies and rehearsing the process several times onshore proved valuable when performing the job at the rig site (Fig. 4).

The work also included building an extra-long tool basket for transporting the subassembly and providing protection and stability during handling operations.

Rehearsing the process several times onshore proved valuable when lifting the BHA at the rig site (Fig. 4).
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Another key complication addressed during subassembly make-up was the alignment of key components to facilitate installation of multiple lines through by-pass slots and control-line ports. Utilization of timed couplings, provided by another supplier, solved this problem.

The assembly also had all control lines fed through the packers and connections made up and tested before shipment offshore. Pretesting also enhanced reliability because the connections were made in a controlled shop environment without time constraints.

Subsea interfacing

The functionality of IWS downhole equipment depends in great part on the surface control and data acquisition systems. Because the Independence project is a subsea field development, the intelligent completion systems must be monitored and controlled through the subsea control system.

A system integration test (SIT) before installation ensured a problem-free interface between downhole and subsea components. The SIT included the intelligent flow control valves, downhole gauges, control-line flat pack, tubing hanger, and subsea control module. The SIT proved out system compatibility and measured the response time of the control valves.

Planning pays off

Planning the first Spiderman IWS completion required 18 months, including time to design and test the long subassembly installation approach. During this time, the well was completed on paper with a focus on multidisciplinary teamwork. Involvement of rig personnel in advance of the installation also contributed to the success of the operation.

On Aug. 6, 2006, the rig team installed the first Anadarko Independence intelligent well system with no problems. The 93-ft completion assembly had six control lines (one electric and five hydraulic) that were terminated and tested on the riser skate before lifting.

The actual installation required 2 hr, during which the rig team tested the functioning of the sleeves and pressure tested the quick connect.

Initial well tests exceeded expectations, and the installation saved an estimated 12 hr of rig time.

Riser skate testing of four subsequent IWS wells in Spiderman, Jubilee, Mondo NW, and Atlas fields was a shorter 1.25 hr, with pickup and stabbing requiring as little as 15 min.

Working from a riser skate and using 30-ft assemblies where possible has been expanded to BHAs for wellbore cleanout, tubing-conveyed perforating, pulling packer plugs, and wear bushings, gravel-pack assemblies, safety valves, and tubing hangers.

Thus far, the project is on schedule for first production this fall, and under budget.

Independence is massive and ambitious.

The authors

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Jack Burman is manager for Exploitation Technologies LLC, Houston. He specializes in worldwide deepwater and shelf well completion, production engineering, and field implementation. Before forming Exploitation Technologies in 1999, he held various positions at Chevron Corp., Conoco Inc., Newfield Exploration Co., and Snyder Oil Corp. Burman has a BS in mining engineering from Virginia Tech and an MS in petroleum engineering from University of Wyoming. He is a licensed professional petroleum engineer and an SPE member.

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Ricardo Tirado is business development manager for Baker Oil Tools intelligent well systems. With Baker Oil Tools, he has held several positions in sales, operations, and marketing. Tirado has a BS in electrical engineering from Universidad Rafael Urdaneta, Venezuela and an MBA from University of Houston. He is an SPE member.

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Mark Teague is a project manager with Baker Oil Tools and is currently embedded with an independent operator providing in house technical, operational, and logistical support for cased-hole completions. Since joining Baker Oil Tools, he has held various positions as a technical specialist, district manager, and sales and applications engineer.