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Multilevel Completions in One Trip: Development and Deployment

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Typically, the completion of certain deepwater wells will necessitate the separate deployment of sandface, intermediate, and upper completions. What if this could be achieved in a single trip? In the simplest terms, completing in a single trip reduces the overall completion time by half and more. The complete paper describes the hurdles that have prevented single-trip installation of upper and lower completions in the complex world of subsea and deepwater applications and examines the processes, technologies, and risk-mitigation steps that took a concept from pilot to successful deployment.

Introduction

Almost universally in offshore operations, operators have elected to deploy completions in multiple trips. Simple completions on land are often deployed in a single-trip fashion, and the deployment of cemented single-trip gas-lift systems on platform locations in the Gulf of Thailand is commonplace. Subsea single-trip systems have been deployed in the Campos Basin; however, these tend to be relatively simple and in wells not requiring sand-control solutions. They typically consist of a safety valve, gas-lift mandrels, polished bore receptacle (PBR), production packer, and re-entry guide. At the time of writing, no one has run standalone screens as a single-trip system in deepwater applications.

Torque and Drag (T&D) Modeling

A T&D study was conducted based on a representative deepwater well. The ­limiting factor to the amount of setdown weight is the design limits of the stand-alone screens. These depend on design but are typically on the order of 30,000 lbf; thus, this was used as the upper limit. The assumptions made include the following:

  • Friction factors: 0.25 for casing and 0.3 for open hole
  • Block weight: 175,000 lbm
  • Mud density: 10.2 lbm/gal
  • Yield of pipe: 90%
  • Tripping in and out speed: 60 ft/min
  • Completion interval: 10,253–10,685 ft
  • Maximum allowable screen running setdown weight: 30,000 lbf
  • Fluid levels to surface

First, the existing two-trip system was considered. The study considered the expected string weight and the actual weight seen on the driller’s console during deployment as well as the minimum weight to buckle the deployment string helically. The string can be installed to depth successfully, and, if necessary, 30,000 lbf can be set down in order to overcome any obstructions without buckling the deployment string. The completion can be run to depth successfully without exceeding the 30,000‑lbf limit.

The same well was then considered using the single-trip completion. The completion can be run to depth successfully without exceeding the 30,000-lbf limit. While less setdown weight is available in the single-trip completion case, the limiting factor is the limit on the screen joints (30,000 lbf), which is the same in both types of completion.

Technology Selection

Before elements of a completion can be combined, the role of each element needs to be understood. In the case of a deepwater stand-alone-screen completion, the entire system must achieve the following:

  • Deploy the entire completion in one trip
  • Manage all well-control situations during deployment
  • Land the completion hardware on depth
  • Displace the openhole-to-breaker fluid
  • Close and test the toe isolation remotely
  • Set and test the production packer
  • Operate screen sleeves remotely and confirm communication with the reservoir
  • Operate and test the reservoir barrier valve remotely
  • Displace the annulus-to-packer fluid
  • Operate and test the safety valve
  • Pressure-test all barriers

The primary goal in the deployment is for the completion to reach total depth (TD). The primary technological ­driver is maintaining the pumpdown capability of the string. In this respect, the first aspect of the technology selection that was considered was the method of achieving screen-sleeve integrity. Ball-sealing injection-control-device (ICD) and chemical-sealing ICD technologies were considered. Once these technologies were discounted, however, the technologies listed as follows were considered in a ranking matrix determining how their use in a single-trip completion would affect each one of the previously described functions. The simplistic ranking method considered the goals of the complete system based on the given technology platform.

  • Control line Electronic timer
  • Electronic hydraulic pressure [without radio frequency identification (RFID)]
  • RFID

Ultimately, the RFID option was recommended for a single-trip completion, offering the benefits of being hydraulically insensitive; having a function-on-­demand ability; and possessing multi-level contingencies, operational flexibility, and an extensive run history.

Proposed Single-Trip System

Fig. 1 illustrates the schematic that was constructed and reviewed against the input specifications for a single-trip system. The proposed completion program is shown below:

  1. Assemble reservoir section assemblies in the rotary table
  2. Pump (or drop) RFID tags to close the lower RFID ball valve
  3. Pressure-test liner to full test pressure
  4. Apply pressure cycle to open the lower RFID ball valve
  5. Assemble the rest of the components
  6. The upper ball valve can be cycled closed to test the upper components; the safety valve can also be tested (optional)
  7. Run in hole to TD
  8. Land tubing hanger
  9. Circulate RFID tags with breaker fluid to isolate toe
  10. Pressure-test liner
  11. Pressure up to set the lower packer
  12. Apply pressure cycle to open RFID ICDs
  13. Close and test RFID ball valve
  14. Apply pressure cycle to open the production sliding sleeve
  15. Circulate packer fluid to clean up the annulus
  16. Test safety valve (optional)
  17. Set and test the production packer
  18. Suspend the well
  19. Using a remotely operated vehicle, apply a pressure cycle to open the upper ball valve
Fig. 1—Schematic constructed and reviewed against input specifications for a single-trip system.

Results

The RFID components were taken from the proposed system and deployed in a test well in Aberdeen. The goal of this system-integration test (SIT) was to iron out any issues related to deploying the new system in a low-cost environment at a pace that allowed any issues to be diagnosed, learned from, and trialled to find an optimal solution. The final offshore well program could be built on these learnings.

Following the successful SIT, the components were deployed offshore west Africa as part of a single-trip completion. A typical two-trip system takes 9.96 days to deploy. In one representative case described in the literature, the first well took 6.1 days to deploy the single-trip completion. This represented a 40% savings in rig time. It is worth noting that this was a new rig deploying its first completion. Thus, apart from optimizing the ­single-trip completion system, the rig itself had to learn how to best handle completions in general. For the next two wells, the total completion deployment time dropped below 4 days. This represents a total savings of 60%, or, in financial terms, $3.8 million per well when compared with the existing two-trip system.

Future Direction

The single-trip system creates new possibilities both in technical and financial terms. Operators identify better reservoir surveillance routinely as a priority, but this is rarely possible. The technical solution that currently offers the most information in a real-time situation is distributed acoustic sensing and distributed temperature sensing. Early in the development of the technology, fiber systems suffered from hydrogen blackening; however, this appears to have been overcome, and life-of-well fiber can now be considered for use in sandface applications.

A recent job performed with RFID tools in the North Sea demonstrated that RFID components could be housed to allow the feedthrough of fiber within the given geometry. Nine tools were deployed in the well. The first was programmed to close on an RFID tag; the rest were programmed to open on various delays following a pressure cycle. All tools performed successfully, and, in each case, the opening of the tool was observed in real time on both a downhole gauge and the downhole fiber.

However, sandface applications have one major obstacle—how to connect the fiber between the upper and lower completions reliably. By adopting a single-trip philosophy, the need for a wet connection can be eliminated. This would result in a more-reliable sandface fiber solution. The greater volume of real-time data that can be gathered by the operator could be used to optimize the reservoir model and make production decisions more quickly.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30747, “Tripping the Light Fantastic: When Three Become One,” by Euan Murdoch, SPE, Paul Day, and Steven Walduck, Weatherford,  prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission.

Multilevel Completions in One Trip: Development and Deployment

01 October 2020

Volume: 72 | Issue: 10

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