Dual String Retrievable Packers for Complex Completions

The Challenge of Dual Completions

Running two tubing strings into a single wellbore for production or injection, often to target different zones, adds a layer of complexity to well completions. You need to isolate those zones effectively, and you need to be able to retrieve your equipment if things go sideways or the well plan changes. That’s where a dual string retrievable packer comes in. It’s not just about setting a seal; it’s about managing two strings, often with different loads and operational requirements, all while ensuring long-term integrity.

What is a Dual String Retrievable Packer?

A dual string retrievable packer is a high-performance downhole tool designed to provide zonal isolation between two parallel tubing strings and the casing. It’s set hydraulically, meaning you apply pressure down one of the tubing strings to activate the setting mechanism. A key design aspect of these packers is that they don’t require any mandrel movement during the setting sequence. This is a big deal, especially in complex hookups. Once set, you can release the packer by applying tension to either or both tubing strings simultaneously, which is a significant operational advantage for workovers.

These packers are built to be compact. That helps a lot with handling on the rig floor and makes running in tight or deviated hole sections easier. They also incorporate features to prevent premature setting while running in, which can save you a lot of grief and expensive fishing jobs.

Where We Use Them

You’ll find dual string retrievable packers in a few common scenarios:

• Dual Production and Injection Wells: Isolating two producing zones or an injection zone from a production zone.
• Upper Packer in Tandem Completions: When you have a single-bore packer below, this tool can serve as the upper packer, isolating the annulus above the lower zone.
• Upper or Intermediate Packer in Selective-Tandem Dual Completions: For more complex scenarios where you’re isolating multiple zones with multiple packers.

The design, particularly the packing element system, makes them well-suited for high-pressure gas wells where maintaining a gas-tight seal is critical over the long term.

How They Work

Setting the Packer

Setting this packer is a hydraulic operation. Here’s the general sequence:

1. You run the packer to your target depth. The tool has a ported mandrel and a non-ported mandrel. The ported mandrel is the one you’ll use to apply setting pressure.
2. Before applying pressure, you need to blank off the setting string below the packer. This can be done with a wireline-set plug in a seating nipple, a shear-out ball seat sub, or a hydro-trip pressure sub. Make sure your blanking device’s minimum tripping pressure is above the packer’s minimum setting pressure (which is 2,500 psi).
3. It’s critical to ensure fluid communication in the annulus above and below the packer. Open any sliding sleeves on the non-ported string and keep surface manifold valves open. This prevents pressure buildup that could prevent the packer from setting correctly.
4. Apply a minimum differential pressure of 2,500 psi in the ported string and hold it for 5 minutes. For stacked completions, hold it for 15 minutes to allow all packers to fully set. While 2,500 psi is the minimum, slightly higher pressures (up to the maximum differential rating) can improve seal life.
5. Slowly bleed off the pressure.
6. Test the packer seal. Check for leaks from above or below. If it leaks, you might need to increase the setting pressure to 4,500 psi and hold for 10 minutes, or apply maximum allowable backside pressure while maintaining 2,500 psi in the tubing.
7. Once the packer is confirmed set and sealing, trip the blanking device.

Internally, the applied pressure acts on an interlock piston, shearing brass screws at around 1,800 psi. This releases a C-ring, allowing the packer to activate. A piston housing then moves down, pushing the slips out against the casing. Once the slips bite, more shear screws fail, letting the upper cone fully set the top slips. The setting force then compresses the packing element system, expanding metal back-up rings against the casing before the elastomer fully packs off. This force is then mechanically locked in by lock nuts and body lock rings.

Retrieving the Packer

Retrieval is generally straightforward, but it’s important to follow the procedure to avoid issues:

1. First, equalize pressure across the packer. You can do this by opening sliding sleeves or perforating the tubing. If a scoophead assembly is used, pulling the short string out of it will equalize pressure, assuming the short string is open below the packer.
2. Apply tension to either the short string, the long string, or both simultaneously. This shears the shear rings that hold the packer set. Keep in mind that pulling both strings can sometimes increase the effective shear value.
3. As you pull up, the mandrel shoulders against a retainer, shearing another set of screws and releasing the lock nuts. This allows the packing element system to relax and retract. An internal fluid by-pass opens, further aiding pressure equalization.
4. Continued upward movement pulls the upper cone from under the slips, and the slips retract into the slip cage. If you’re releasing on only one string, the shear ring on the opposite mandrel will shear at this time due to load transfer.
5. Once the slips are fully retracted, the packer is free to move up the wellbore.

If retrieval becomes difficult, there’s a specific flow chart to follow, which might involve jarring or even chemically cutting the long string if necessary. In extreme cases, a specialized mill can be used to mill out the packer, designed to minimize mill-up time.

Key Features and Engineering Considerations

• No Mandrel Movement During Setting: This is a big advantage for complex completions, especially with Electrical Submersible Pump (ESP) hookups or in tandem packer arrangements, as it simplifies the setting procedure and reduces potential for damage.
• High Performance Packing Element System: The packing elements feature a “zero gap” back-up system. This is critical for preventing elastomer extrusion, especially in high-temperature and high-pressure environments common in gas wells. The design traps energizing loads, which helps maintain a reliable, gas-tight seal over time.
• Tubing and Pre-Set Interlocks: These systems prevent loads encountered during run-in from prematurely setting the packer or damaging the shear release mechanism. It means you can run the tool faster and with more confidence.
• Modular Design: The packer can be easily configured with optional modules like a scoophead or selective set module without needing to disassemble the core packer. This flexibility is good for inventory management and adapting to different well designs quickly.
• NACE Compliance: Available in materials compliant with NACE MR0175/ISO 15156 for sour service environments, though this often comes with slightly reduced pressure ratings.

Technical Specifications (Representative Ranges)

These packers are available in various sizes to suit different casing specifications and operational requirements. Here are typical specifications:

• Casing OD Range: Commonly 7 inch to 9-5/8 inch.
• Casing Weight Range: For 7 inch casing, 20-32 lb/ft; for 7-5/8 inch, 26.4-39 lb/ft; for 9-5/8 inch, 40-53.5 lb/ft.
• Nominal Bore Through Packer: Typically 1.939 inches for 2-3/8 inch tubing and 2.939 inches for 3-1/2 inch tubing.
• Thread Specification: Commonly API-NU Pin x Pin (10 Rd).
• Maximum Differential Pressure:
  • Standard Service (4140 steel, 30-36 Rc): 6,000 psi (unplugged, from above or below).
  • NACE Service (4140 steel, 22 Rc Max.): 5,000 psi (unplugged, from above or below).
• Temperature Range: 70°F to 300°F in both gas and liquid environments.
• Minimum Setting Pressure: 2,500 psi.
• Actuation Pressure Per Shear Screw: 600 psi (for smaller sizes) to 400 psi (for larger sizes).
• Shear Release Values: Configurable via shear screws, with options from 30,000 lbs to 90,000 lbs, depending on packer size and whether a top shear ring is used.
• Mandrel Tensile Ratings (Standard Service):
  • Size 47: 125,700 lbs
  • Size 51: 216,500 lbs

  Note: These ratings do not include joint yield strength. Always use 80% of tensile limitations to avoid shear ring failure.

• Maximum Load Between Mandrels While Running:
  • Size 47: 52,000 lbs (Standard), 38,000 lbs (NACE)
  • Size 51: 106,000 lbs (Standard), 77,000 lbs (NACE)
• Maximum Set-Down Weight (Packer Set):
  • Size 47: 52,000 lbs (Standard), 38,000 lbs (NACE)
  • Size 51: 90,000 lbs (Standard), 65,000 lbs (NACE)

Limitations and Redress Considerations

While these are retrievable packers, they do have limits on how many times they can be redressed. After each run, a thorough visual inspection is critical. You’re looking for scored seal surfaces, damaged threads, or worn wickers. Certain components, like the interlock C-ring, lock nuts, and stop ring, should generally be replaced after every run to ensure reliable performance on subsequent jobs.

During redress, pay close attention to the piston housing. Check its internal diameter for any deformation, especially in line with the mandrel bores versus the setting bar and interlock pin holes. If the difference is more than 0.010 inches, the housing needs replacement. Also, inspect the face of the piston housing that contacts the interlock C-ring for indentations, as these can increase the actuation pressure required to set the packer.

When reassembling, make sure the body lock rings don’t bottom out against the lower cone. This can cause the internal bars to bind, impacting operation. It’s also important not to test the ported mandrel plugged above 3,500 psi, as this can overstress components.

The Bottom Line

Dual string retrievable packers are essential tools for managing complex well completions, offering reliable zonal isolation and the flexibility to retrieve the assembly. Their hydraulic setting mechanism, compact design, and robust packing elements make them suitable for challenging environments, including high-pressure gas wells. But like all downhole equipment, understanding their operational limits, proper setting procedures, and diligent redress practices is key to maximizing their performance and ensuring long-term well integrity.