Advances in Drill Pipe

Real-time drillstring telemetry passes final tests

Ultra-fast data transmission passes milestones in field tests. Commerciality is declared.

Perry A. Fischer, Editor

The oil and gas industry has been looking for ways to transmit downhole data to the surface for three decades. The limitation of mud pulse telemetry, even if pushed to 12 – 16 bits per sec., means that data must be decimated, summed downhole, and transmitted during pauses in drilling. Thus, the industry has spent the last 20 years trying to move more data through decimation and packaging. After more than five years in development and testing, a new type of wired drill pipe, with bi-directional data transmission rates up to 57,000 bits per second,¹ has now come to market. This is our third report on the technology (see World Oil, Oct 2003 and July 2005).

BACKGROUND

Wired drill pipe has been tried before, but reliability seemed unachievable by using hard-wired connections. Such connections would have to align perfectly each time the connection is made up, and yet remain electrically insulated from the drill pipe. To avoid this problem, Provo, Utah-based Novatek and Houston’s Grant Prideco, working, in part, with funding from the US Dept. Of Energy, decided to build a system using a wire induction loop “connection.” The loop is nestled in a ferrite trough and recessed into the end of the drill pipe connection, one, each, in box-shoulder and pin-nose ends, Fig. 1. An insulated, armor-encased wire runs the length of the inside of the drill pipe, before disappearing into the connection end to the induction loop. The wire is not attached to the inside of the drill pipe, allowing the pipe to bend without straining the wire.

Fig. 1. The armored cable runs inside the drill pipe, through the box/ pin shoulder, and terminates in a loop, surrounded by a ferrite trough. When made up, inductive loops are close, but not touching.

After 800 to 1,500 ft of drill pipe, the signal must be boosted by a special 4-ft amplifier sub, screwed to a 27-ft drill pipe joint, which adds the necessary signal conditioning and power (lithium battery). As the wired drill pipe nears the BHA, the signal must get through heavyweight drill pipe, drill collars and drilling jars, which require the wire to coil and recoil in the event that the jars are fired. In addition, string stabilizers, roller reamers and other accessories machined with double-shoulder connections have been modified with the wire/ induction loop.

The purpose of the technology, called Intelliserv network, is to allow live, high-speed, two-way communication with downhole devices. A physical and signal-protocol interface allows MWD/ LWD and other applications to arrive at the drill floor without having to stop drilling; the signal is stripped off by a slip-ring electrical swivel.

In total, the manufacturer says that the new telemetry system has been in 19 wells and accumulated over 7,000 hours of well time. The latest version is rated to 306°F and 20,000 psi. 

TOOL PROTOCOL

Baker Hughes INTEQ is the service firm that provided the MWD and LWD tools in field trials thus far. Other downhole measurement tools are expected to follow. Modifications were needed for an interface to the system, in the form of an interface sub above the MWD tool string. There are protocol converters at the downhole tool and surface computer interfaces. The company used its present MWD data bus for all components connected below the interface. This allows unaltered tools to attach to the network, with full-functioning, existing mud-pulse telemetry as a backup. When both telemetry systems are used in parallel, transmission is conventionally slow, at about 12 bits per sec.

However, when the conventional telemetry system is turned off, available only as backup, a higher-resolution data stream is available, composed of, raw, unaveraged, uncompressed data that can be sent to surface, resulting in real-time memory-quality logs. Data can also be transmitted downhole to the BHA, although the mode has to be switched to do so.

FIELD TESTS

Five previous field trials were covered in the Oct. 2003 and July 2005 reports. Data from the sixth well has not been released. Trial seven was presented at the annual IADC/ SPE conference.¹

This well was directionally drilled to a 14,065-ft MD, of which, 5,030 ft were drilled with air. Wired, 5-in. drill pipe was used, with 12 amplifier joints spaced at 1,200 – 1,500 ft. This was the first fully commercial deployment of a network-enabled MWD/ LWD tool. The tool included an integral mud pulser and an alternator for power. This tool was programmed to automatically begin to transmit, should the drill pipe network become inoperable, both of which indeed happened. The drillstring had 545 rotating and circulating hours, and 419 real-time transmission hours (94% availability). Downtime was due to damage to a heavyweight pin-end coil, caused by a mis-stab while running in hole.

Gamma ray, resistivity and drilling dynamics data were transmitted. Two cement squeezes were performed with a wiper ball, all through the wired drill pipe and without any problems. A programming error prevented a survey measurement from working properly. Ordinarily, this would have required a trip to surface, but the network was put in down-going transmission mode, and new programming was sent to the MWD, correcting the error. Overall, BP, INTEQ and Intelliserv considered the deployment of the new drill pipe network a success.

POTENTIAL BENEFITS

Take the not uncommon case of exploration drilling with a deep salt, overhung reservoir as a target. In this case, missing the target is common. Using the new wired drill pipe will greatly improve the chance of hitting the target reservoir, because of continual, real-time integration of sonic and perhaps VSP information for better time-to-depth control in prospect targeting. Data-intensive applications, such as seismic-while-drilling, together with high-speed satellite hookup and cluster processing, will make it possible to do a fast, post-stack depth migration, focused only in depth for targeting purposes, perhaps before the drillbit has gone another 30 ft.

Live bit-steering in rotary steerable systems becomes possible. Time-sensitive derivatives, such as pore-pressure prediction, BHA vibration and stick-slip bit rotation feedback, will clearly benefit. If desired, an operator can place sensor nodes in the drillstring wherever he wants. This will allow measurement of freepoints (if stuck), temperature (if a kick is working its way up the drill pipe annulus), hole angle, or anything else that an operator wants. All of which can mean fewer sidetracks and safer drilling conditions.

Fracture-based steering, fracture-oriented steering, visualizing induced fractures and borehole breakouts can all become a live, real-time part of the drilling process.

In extreme extended reach drilling, or when drilling with foamed fluids or air, mud-pulse telemetry is probably not viable. Downhole EM transmission to the surface or seafloor, often using downhole antennae, is the only other option. But these have proven to be problematic. The new system avoids these communication problems. Precise steering in long horizontals also has the ability to increase production and forestall water/ gas breakthrough, via proper borehole placement in the oil zone.

It is undoubtedly true that it will take years for the benefits to be fully realized, partly because of the huge investment spent on data decimation downhole for mud-pulse telemetry, and because most operators are in a proverbial race for second, or even third, place, preferring to let someone else be first to try out new technology. For now, the tools can be rented, and at least two operators with North Sea operations have contracted the service. 

LITERATURE CITED

¹ Reeves, M., J. Macpherson, R. Zaeper, D. Bert, J. Shursen, K. Armogost, D. Pixton and M. Hernandez, “High-speed drillstring telemetry network enables new real-time drilling and measurement technologies,” Paper IADC/ SPE 99134, IADC/ SPE Drilling conference, Feb. 21 – 23, 2006, Amsterdam, Netherlands.