Electronics adds new dimension to well completions

Kevin R. Jones
Baker Oil Tools
Houston

Downhole wireless communication techniques and electronically enhanced remote-actuation completion equipment reduce, and in some cases eliminate, many common well interventions.

The resulting savings in operating expense and overall completion cost can be substantial.

To cope with increasing operating costs, today's oil and gas companies are looking for economical ways to minimize well interventions without compromising reliability, safety, or ultimate well profitability.

This becomes more important in extended-reach wells where completions are run in ultra-long horizontal and near-horizontal well bores.

In these wells, wire line, and often coiled tubing, intervention is impossible. Drill pipe has been the only remaining option.

Wireless communication

An electronically enhanced remote-actuation system consists of a downhole module and a surface unit, connected by a primary communication medium (Fig. 1). The downhole module contains the actuation system, control system, a power source, and a communication receiver.

The surface unit contains the communication transmission device and, if necessary, associated control systems. The communication medium carries the command one way, from the surface to the downhole module.

Currently, three wireless communication options are available for remote actuation systems: low-frequency electromagnetic fields, absolute pressure, and frequency-based pulse wave energy.

Frequency based

Frequency-based communication is a relatively simple, inexpensive method of wireless communication that can be used to actuate many traditional downhole tools.

A recently developed frequency-based system relies on recognition of a predetermined frequency of pulse-wave energy imparted onto the tubing fluid as its primary means of communication. The simplicity of this downhole communication system, combined with some ingenious actuation methods, makes it easy to retrofit onto existing completion tools.

Prior to installation in the well bore, the downhole device is initialized by selecting an available frequency (dt = t0) and setting up the control system to recognize this frequency (Fig. 2). An optional time delay can also be selected.

Once in the well bore, the system constantly measures the frequency of any rapid changes occurring in the tubing fluid. The setting device will not activate until the proper frequency is matched. When the matching frequency is received by the control system, it actuates a device that causes the completion tool to operate.

Frequency-based communication can prove particularly beneficial with disappearing plugs in extended-reach horizontal wells. The disappearing plug can be removed from many extended-reach horizontal completions without a costly well intervention. This provides substantial benefits over conventional plugs, which must be retrieved on coiled tubing or drill pipe, and other disappearing plugs, which do not have the pressure-containing capability of the electronically enhanced version.

By using a disappearing plug (Fig. 3), a completion can be run in plugged so that many conventional hydraulic functions, such as testing the tubing and setting packers can be done. However, to work effectively, the disappearing plug must be rated to 5,000 psi applied hydraulic pressure in either direction with a 5,000 psi hydrostatic pressure. Also, the plug must completely disappear upon command from the surface.

Traditionally, various pump-open subs served this function. These require many trade offs, such as severe ID restrictions and parts left in the hole that can actually be produced up the hole and damage expensive production equipment.

The electronically enhanced disappearing plug is commanded from the surface. When the remote actuation system is activated, the control system detonates an explosive charge. This detonation is of a magnitude to pulverize the pressure-containing plug without damaging the completion hardware.

Frequency-based communication technology can also enhance conventional completion tools, such as permanent and retrievable packers, liner hangers, and flow control equipment. None of these enhanced tools require well intervention prior to activation. Because the communication system does not require applied pressure, the tubing does not have to be closed-ended (plugged). The only requirement is a full column of fluid from the downhole device to the surface.

To date, two electronically enhanced completion tools have been successfully installed:

• A frequency activated retrievable packer was remotely set in offshore Louisiana at a measured depth of 9,235 ft. Because the well was taking fluid, the required fluid column in the 278-in. tubing was difficult to maintain and a gel pill had to be circulated to depth to alleviate this problem prior to activating the packer.

• A 7-in. OD disappearing plug was activated at 15,221 ft measured depth in a 77 maximum deviation well for a Norwegian operator. The activation used negative pulsations. These pulsations were generated by pressuring up the 7-in. tubing against the disappearing plug and then rapidly bleeding off the pressure.

Absolute pressure

A second communication method for electronically enhanced remote actuation of downhole completion tools is absolute pressure (Fig. 4).

An electronically actuated packer setting (EAS) tool, designed to sense applied pressure sequences that are maintained for a given time, has been used successfully in the North Sea since 1992. The highly sophisticated, autonomous setting tool is an annular shaped, expendable, pressure-setting assembly that carries its own control electronics, batteries, pressure sensor system, and gas-generating propellant charges.

The tool contains three separate annular-shaped chambers on a central mandrel that is an integral part of the production tubing (Fig. 5). The electronics chamber houses the control electronics, batteries, strain gauges, and gas-pressure transducer. This is an atmospheric chamber and should not see any pressure increase during normal operation.

The propellant chamber houses the gas-generator assemblies, and the hydraulics chamber contains the hydraulic fluid to be supplied to the packer. It is separated from the propellant chamber by a Teflon piston.

Communication from the surface to the downhole setting tool is by absolute pressure changes in the tubing string. A proprietary sensing technique constantly monitors the pressure inside the tubing. When a unique, predetermined pressure/time sequence is recognized by the control system, the tool begins the setting sequence (Fig. 6).

Setting is accomplished by a closed-loop technique that provides the optimum setting pressure to the packer (Fig. 7). The control system monitors the pressure in the propellant chamber and initiates the proper-sized gas generator, which increases pressure in the propellant chamber.

The control system continues to monitor the propellant chamber pressure until either the gas generator expires or a predetermined threshold is reached. At that time, the control system initiates another gas generator to keep the pressure rising.

All tubing-to-annulus elastomeric seals have been eliminated from this packer setting tool. This increases long-term completion reliability and saves rig time by allowing the entire completion to be run in one trip.

Full working pressure tests of the tubing string can safely be conducted without fear of premature actuation.

The first electronically actuated packer setting tool was developed for a U.K. operator and successfully put in use in 1992. Since that time, more than 50 successful installations have been done in the North Sea.

Electromagnetic fields

The third communication medium for electronically enhanced remote actuation systems is encoded low-frequency electromagnetic fields (emf). Low-frequency emf was first used by the U.S. Navy for satellite-to-submarine communications in 1958 and later was used for nuclear test monitoring systems. During the late 1980s, emf technology was transferred to oil field operations.

In wireless communications, the attenuation or loss of signal strength through the transmission medium is directly proportional to the transmission frequency. Low-frequency emf does not suffer the same signal degradation through the earth's strata as high-frequency or radio transmissions. Thus, the operating range of electromagnetic (EM) communications is above the micropulsation range but below the audio/acoustic range (Fig. 8). This emf range allows for low attenuation with maximum data transfer rates.

The first downhole completion tool to use an electronic actuation system was an electromagnetic surface-controlled subsurface safety valve developed in 1989 (Fig. 9). The valve was preprogrammed at the surface to respond to a unique frequency. During normal operation, the subsurface unit constantly received the correct frequency to remain in the open position. If this signal was interrupted for any reason, the subsurface safety valve closed immediately.

This valve met with limited success because of its dependence on formation resistivity for depth of penetration and because of the unavailability of a safe, reliable, downhole power source.

However, the electromagnetic communication technique proved very reliable, and many uses for electromagnetic communications have since been found within drilling and completions. None have the stringent time, temperature and electrical requirements of subsurface safety systems.

One of the more widespread uses for EM communication technology currently is in drillstem testing. Here no device is actuated, only data are recorded, and time in service is kept to a minimum.

Future systems

As deepwater subsea developments mature, many oil and gas companies are re-evaluating the relationship between operating expenditures (Opex) and capital expenditures (Capex) over the life of the reservoir.

During the life of most conventional developments, Capex accounts for a large percentage of the total costs, whereas Opex accounts for a much smaller share. In deepwater subsea developments, however, primarily because of the high cost of rig mobilization, Opex becomes the major cost of the development.

Because of this changing relationship, a relatively small increase in Capex that will reduce overall Opex by eliminating well interventions, and therefore eliminating expensive rig mobilization is easily justified.

Large reservoirs, such as the recent discoveries west of the Shetland Islands, offer huge financial rewards if the recoverable hydrocarbons can be removed economically. Many of these reservoirs are being developed on the basis of recovering a very low percentage of the reserves in place. If additional reserves can be recovered, this will justify an increase in Capex.

Controlling reservoir drainage from the surface can eliminate expensive well interventions. With downhole flow control devices that are actuated from the surface in conjunction with well bore sensors in the producing zones, reservoir control is achieved without entering the well, therefore significantly reducing Opex with only a small increase in Capex.

Thus, the next generation of electronically enhanced completion systems will incorporate traditional well bore sensors with field-proven flow-control technology.

Bibliography

Drakeley, B., Meadows, M. Deaton, M., and Pelletier M., "Wireless Control of Subsurface Completion Systems," Paper No. OSEA 90125, Offshore Southeast Asia Conference, Singapore, 1990.

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