Remote actuation system speeds deepwater well completions

Oct. 7, 1996
Terry Bussear Baker Oil Tools Houston Substantial savings in rig time, operating expenses, and overall completion costs, particularly in extended-reach and deepwater wells, can be realized with advanced wireless communication techniques and electronically enhanced pulse-actuation systems for completing wells. With drilling and completion costs climbing steadily, especially offshore, operators need to minimize rig time without sacrificing reliability, safety, or ultimate well productivity.
Terry Bussear
Baker Oil Tools
Houston
Substantial savings in rig time, operating expenses, and overall completion costs, particularly in extended-reach and deepwater wells, can be realized with advanced wireless communication techniques and electronically enhanced pulse-actuation systems for completing wells.

With drilling and completion costs climbing steadily, especially offshore, operators need to minimize rig time without sacrificing reliability, safety, or ultimate well productivity.

During the past several months, Baker Oil Tools' EDGE remote actuation system, a surface-controlled communications system that relies on pressure-wave pulses to actuate electronics-equipped downhole completion tools, has been deployed commercially in a number of deep, high-pressure, high-temperature wells in the Gulf of Mexico.

Deployment times to date average 2 hr, and range from 4 hr (for the inaugural job), to less than 1 hr (Table 1 [28223 bytes]).

System basics

A typical actuation system is comprised of a portable surface module, the communications medium, which is the fluid column in the completion string, and a downhole module (Fig. 1 [124463 bytes]).

The surface module consists of a computer-controlled, pulse-generating unit, an interface box with manual controls, and a computer controller. The downhole modules are electronically enhanced completion tools (such as permanent or retrievable packers, or sliding sleeves), that include a pulse-frequency detector, an electronic control system, and the tool-actuation system powered by a battery pack.

The completion system works as follows:

  • Prior to installation in the well bore, the downhole tools are programmed at surface to selectively recognize one of 15 discreet actuation commands.

  • Following initialization of each downhole tool, the onboard frequency detector in each tool constantly samples all pulses traveling through the fluid in the completion string, while the control system filters and recognizes only the pulses of preprogrammed magnitude.

  • At the surface, the pneumatic/hydraulic pulser unit transmits a specific pulse sequence into the well fluid. The pulsing unit consists of two nitrogen/water accumulators, an air-driven water pump, and two electropneumatic, actuator-operated valves that control fluid movement into and out of the well. The pulse transmission process is initiated and supervised by the system operator.

  • Following initiation, the pulse-generating process proceeds automatically under computer control. The onboard supervisory control and data acquisition (scada) system allows continuous logging of pulse transmissions and reflections, thus allowing the operator to assess, in real time, the quality of pulses delivered and, therefore, to ensure that effective communication is established between the surface system and the downhole tools. In the event of computer-related problems, the operation may be run manually via the interface box.

  • The downhole completion tool will not activate until its unique pulse waveform is detected and confirmed four times by the internal control system. Once the programmed time delay elapses, the actuation mechanism receives operating power from the battery pack.

To enhance reliability, most of the electronic completion tools contain a contingency setting feature that allows conventional wire line or coiled-tubing actuation methods to be employed in the event normal pulse actuation fails.

Currently, downhole completion tools available for use with this remote actuation system include retrievable and permanent packers, which set upon actuation; and sliding sleeves, which shift one time, either open or closed, upon actuation.

Design engineers are now at work adapting the pulse communication technology to many other types of downhole completion devices.

Mars installation

The remote actuation system was first deployed commercially in March 1996 at Shell Offshore Inc.'s Mars deepwater development project in the Gulf of Mexico. This event is believed to have marked the first time in offshore oil and gas development history that a conventional, hydraulically set completion packer was activated remotely from the surface without having to first run and set a tubing plug.

The system set a retrievable packer at 16,894 ft measured depth.

The well, in 2,962 ft of water, was drilled from the Mars tension-leg platform in Mississippi Canyon Block 807, off Louisiana. It was completed with a 3,000 ft, 5-in. OD riser, a string of 7-in. OD, 35 lb/ft production casing, and a string of 31/2-in. OD, 9.2 lb/ft production tubing. The completion fluid was 13.1 lb/ft CaBr brine.

The time breakdown for the installation included set-up surface gear, test pulse transmissions, deliver proper pulse frequency sequence for packer-setting, and rig-down system. A delay was experienced because of air entrained in the completion fluid, which tended to interfere with proper pulse transmission.

However, once the service engineer identified the problem and took measures to eliminate air from the well, the pulse frequencies transmitted from the surface were received without error and packer setting occurred normally.

Time to identify and solve the air problem added about 1 hr to the job. This brought the total time to just under 4 hr. That, however, was still much shorter than the estimated 12 hr for a conventional completion sequence for this type of well.

The one-trip completion was designed, tested, and manufactured to Shell's specifications. It consisted of a 7-in. retrievable seal-bore packer as well as a Model TSL tubing stability latch. The packer suited the application because of its adaptability to the actuation system, as well as its capabilities under high-pressure, high-temperature, and high-compressive-load conditions, and its proven track record in deepwater applications.

The operator chose the TSL because it allows the seal assembly to remain anchored for the most of the well's life and permits movement only during times of extreme loading, such as during stimulation operations.

Reflections, attenuation

The Mars completion design was a significant challenge to the team charged with deploying the remote actuation system. For example, because all pulses delivered downhole were reflected by the fluid-loss control device (FLCD), the pulses had to be kept at a lower intensity than that required to shear FLCD actuation pins. This required precise pulse frequency control on the part of the engineer.

Additionally, the system had to handle reflections and attenuation associated with each tool in the completion string. And finally, the Baker operator had to accommodate extreme pulse reflections caused by a large tubular diameter change, 5 in. to 31/2 in., at the tubing hanger.

Benefits, limitations

The inaugural deployment of the actuation system confirmed the following benefits of pulse communications technology:

  • Allow one-trip, flanged-up completions.

  • Eliminate well intervention because of remote actuation.

  • Minimize rig time, which is estimated at 1-4 hr.

  • Allow setting multiple completion devices selectively using different predetermined pulse frequencies.

  • Include a conventional back-up actuation mechanism, which was not needed.

    Conversely, some potential system limitations were observed as follows:

  • In the surface module, the pulsing unit requires 2,000-psi nitrogen bottles and the computer controller requires wellsite electric power.

  • To properly transmit pulses, the communications medium in the completion string must be a full fluid column, purged of any gas.

  • In the downhole module, the downhole tool battery pack limits applications to temperatures less than 250° F., and tools have to be actuated within 30 days following initialization.

Simulator developed

Because every well completion is different, and pulse-frequency communication is sensitive to well characteristics for the proper transmission of pulse waves, Baker developed a computerized pulse-transmission simulator to model the well bore as a waveguide. The results are used to preset parameters in the surface unit for pulse-frequency generation.

When on-site, test pulses are initially sent to confirm the premodeled results. The test pulse results are then compared to the model prediction, thus increasing reliability and ensuring proper field application.

The simulator graphically outputs the predicted wave profile at the downhole device so that the pulses transmitted from surface can be adjusted by the completion engineer to provide the required downhole pulse.

Field tests prove that the simulator is a good model for predicting suitability of the remote actuation system for a specific or prospective well-completion design.

Time improvements

After the first successful remote actuation system deployment, five more downhole tools were successfully deployed for Shell in the Gulf of Mexico before the system was introduced to the North Sea in June.

In four of those five jobs, total rig time was less than 2 hr. In the fifth, it was 2.5 hr.

Following the North Sea introduction, three additional packers were remotely actuated in the Gulf of Mexico: one each in Shell's Mars and Tahoe fields, and one in BP Exploration Inc.'s Pompano field. Rig times for these three deployments were 2 hr, 1 hr, and 40 min, respectively.

Tangible savings

The monetary value of remotely actuated, electronically enhanced completion products lies primarily in time and risk-related savings. For example, for conventional completions, it is estimated that an average of 24 hr is needed to rig up, run and test the plug, set the packer, retrieve the plug, and rig down.

For this remotely actuated system, the time required to rig up the surface system, actuate the downhole tool, and rig down the surface system drops to about 2 hr or less. Service and rental costs also drop, although not quite as dramatically.

Additionally, the risks associated with using conventional retrievable plugs (estimated at $16,000-45,000/completion, depending on whether deployment is with a wire line or coiled tubing) are eliminated.

More jobs

Baker Oil Tools is currently manufacturing more than 20 EDGE-actuated completion tools. At the present rate, it is expected that two systems per month will be run during the next year in the Gulf of Mexico and the North Sea.

Acknowledgment

The author and Baker Oil Tools wish to thank Shell and BP for their cooperation in preparing this article.

The Author

Terry Bussear is the manager of electronic completion systems for Baker Oil Tools, in Houston. He is responsible for electronics-based technologies, systems, and market development. Bussear has been with Baker for 18 years. He has a BS in economics from the University of Nebraska.

Copyright 1996 Oil & Gas Journal. All Rights Reserved.