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Vol. 12, No. 20 Week of May 20, 2007
Providing coverage of Alaska and northern Canada's oil and gas industry

Extending the drilling envelope

ConocoPhillips: Technologies converge to enable development of more oil with less environmental impact on Alaska’s North Slope

Alan Bailey

Petroleum News

In these days of high-speed computers, modern home comforts and rapid transportation, many people are probably unaware of something that’s critical to maintaining their standard of life: high-tech oil and gas drilling technology. Without space-age drilling techniques we’d likely be short of many billions of barrels of oil production from increasingly challenging oil accumulations. And oil provinces such as Alaska would languish in a world of hurt, as remaining recoverable reserves dwindle to uneconomic levels.

Jerome Eggemeyer, ConocoPhillips engineering team lead, Randy Thomas, Greater Kuparuk Area drilling team lead and Terry Lucht, ConocoPhillips manager, drilling and wells, told Petroleum News about the evolution of drilling over the past few decades.

Rotary drilling

In its simplest form, rotary drilling involves turning a drill string in a well bore, with a drill bit at the bottom of the string grinding its way through the rock. That technique, dating back many decades, results in near-vertical wells.

But what if you want to deviate the well sideways, to penetrate an oil pool that is offset from the drilling pad or platform?

Back in the 1960s and 1970s wells could be deviated somewhat from the vertical, perhaps up to about 30 degrees, Thomas explained. But achieving that deviation involved “tripping” or pulling the drill string out of the well, to change the configuration of the drill string and thus achieve a bend in the well bore.

The first major innovation in this technique involved tripping the drill string and fitting a motor at the bottom of the string to turn the drill bit. The motor was set to an angle or “bend” that caused an accurate directional change. Drilling mud, a heavy fluid that is pumped through the well during drilling to maintain well pressure and remove rock cuttings, drove the motor.

The next step in technical development came when people worked out how to avoid having to pull the drill string from the well when changing direction.

“The step change then was the directional assembly that gave you the bend that you needed to point in the right direction with your surveys, but that assembly was able to rotate and drill ahead so you didn’t have to trip it out,” Eggemeyer said.

With this type of assembly a change in direction was achieved by stopping the rotation of the drill string, rotating the motor to the desired direction and then pushing the string forward without rotation while the motor-driven bit augured its way to the new direction. After completion of the change in direction, the drillers could resume the rotation of the drill string when drilling continued. But friction between the non-rotating drill stem and the sides of the well during this procedure imposed significant limitations on well lengths.

“When you try to get out to these extended reach limits you no longer have enough push to be able to slide it against that friction,” Lucht said.

A major breakthrough came in the mid-1990s, with what drillers call “rotary steerable technology.” With this technology, the drillers could steer the drilling direction of the bit while drill string continued to rotate. The rotating drill string enabled the drilling of extended reach directional wells.

Increasing displacements

These evolving drilling techniques gave rise to progressively larger amounts of well deviation over the years, with the ratio of bottom hole displacement to well vertical depth increasing from around one to one in the 1960s and 1970s to three to one in the early 2000s. Nowadays drillers have perfected the techniques to the point where five-to-one ratios are being achieved, with six-to-one ratios a possibility in the near future, Thomas said.

And 1987-88 saw the emergence of horizontal drilling with horizontal well bores extending at first to just a few hundred feet. Nowadays horizontal distances of up to 10,000 feet have been achieved in the Alpine field on the North Slope, for example.

The use of coiled steel tubing, 2 inches or two-and-three-eighths inches in diameter and reeled off drums in continuous lengths, has also revolutionized horizontal drilling — conventional drilling involves the use of 30-foot lengths of larger diameter steel drill pipe that need to be assembled when drilling and disassembled when pulling the drill string from the hole. Coiled tubing feeds continuously into the well when drilling is in progress and can be rapidly pulled from the well when necessary.

“When you pull out of a hole to change the bottom hole assembly … you just basically reel it up,” Thomas said.

Using a drill bit powered by a mud motor, coiled tubing can worm its way out the side of an existing well bore and thread its way through a thin reservoir sand, for example.

“Instead of having to drill a completely new well from the surface you can enter an old well and drill a lateral off of that,” Lucht said.

Although coiled tubing drilling is cheaper and more convenient than conventional drilling, it is also more limited in what it can do — the record distance for horizontal coiled tubing drilling is only about one-third of the record for rotary directional drilling, Thomas said. So, coiled tubing is used for the in-field development of existing wells, rather than the drilling of completely new wells.

And both conventional drilling and coiled tubing drill can be used to drill multilateral wells — multiple wells out from a single main well bore. This technique extends the life of existing wells and enables the drilling of multiple pay zones in the rock strata.

Top drives

The introduction of the top drive in the 1980s also proved to be a breakthrough in drilling technology.

In a traditional drilling rig a device called a Kelly bushing on the rig floor grips and rotates the drill pipe. Individual 30-foot lengths of drill pipe are attached to the top of the drill string as the string moves downward into the ground.

“You would pick up single joints of pipe, drill down 30 feet and make a connection,” Thomas said.

A top drive consists of an explosion-proof electric motor suspended near the top of the drilling derrick. Drill pipe is attached to the drive in 90-foot stands, with each stand consisting of three connected 30-foot sections. As the drive turns the piping, auguring the drill string into the ground, the drive is lowered downwards. A driller controls the drive from a console, Lucht said.

The ability of a top drive to handle multiple lengths of drill pipe greatly increases drilling speeds. And, unlike a Kelly bushing, the top drive can rotate the drill string when pulling the string from the well, thus adding flexibility and control to drilling operations.

Measuring, logging and controlling

Traditionally, drillers and well logging companies surveyed and logged wells by lowering wireline tools down the well bore. But the use of wireline tools required the pulling of the drill string from the well, thus delaying the drilling operations. Additionally, the drilling of increasingly deviated wells rendered the lowering of wireline tools increasingly difficult.

“It’s like trying to slide down a flat hill,” Thomas said.

A major technical breakthrough came in the early 1980s with the use of “measurement while drilling,” in which pressure pulses transmit data through the drilling mud, thus enabling continuous monitoring of well measurements while the drilling is in progress. This technology evolved in the late 1980s into “logging while drilling,” in which well log data could be transmitted to the surface using the same technique.

And the “Morse code through the mud” technology reached its logical conclusion with the ability to send signals down the well to control the tools at the bottom of the well and steer the drill bit.

“The tools are now interactive,” Thomas said. “You can send a signal down and tell them what to do and they’ll do it.”

Precision surveying

Surveying the underground trajectory of a well involves measuring how the orientation of the well bore changes along the length of the well bore. Computer software translates these underground survey measurements into a plotted well path.

In general, well orientation measurements are made using a kind of three-dimensional magnetic compass. Measurements near the surface, where a large number of closely packed steel well casings may distort the Earth’s magnetic field, may also require the use of a gyroscope.

But the proximity of the Earth’s magnetic north pole to northern Alaska poses particular problems when doing magnetic surveys in North Slope wells: the magnetic pole moves continuously.

“When you’re as close to the (magnetic) North Pole as we are, if the North Pole moves a little bit, it changes our survey a lot,” Eggemeyer said.

To deal with this problem, stations isolated from the drilling operations continuously monitor the Earth’s magnetic field and provide calibration data to correct the magnetic survey readings.

And the end result?

Stunning accuracy, with drillers able to penetrate a target a few tens of feet across several miles from the drilling rig (well logging techniques also enable a well to remain within a sand body just a few feet thick).

Seismic and computer technology

State-of-the-art seismic surveys provide many of the drilling targets. Nowadays 3-D seismic surveys, involving the deployment of arrays of huge numbers of seismic receivers, routinely produce high-resolution sound reflection images of oil fields — it’s a bit like taking an x-ray photo of an oil field using sound vibrations transmitted from the surface.

A 4-D seismic survey involves repeating the same survey at regular time intervals and then comparing the results. A difference in a seismic reflection between two successive surveys might, for example, pinpoint a pocket of oil that has eluded production. That pocket of oil might then become the target for a coiled tubing sidetrack well, Lucht said.

And computer systems support all of the drilling activities by modeling the friction in the hole, the torque on the drill string and by monitoring the progress of the drilling operation. Nowadays, drilling engineers use computer systems to plan a well before the drilling starts. Engineers on the drilling rigs then continuously refine the plan, using data obtained from the drilling operation.

“At the planning stage we’ll model the well, but as we’re drilling we’ll collect data every day and plug it back into the model, update the model and project ahead, so we can make adjustments as we go,” Thomas said. “So, we keep fulltime drilling engineers on the rigs today, just to keep up with that modeling.”

Combined impact

The combined impact of all of these technologies — steerable drill assemblies, top drives, coiled tubing, mud data transmission, magnetic monitoring and so on — has resulted in dramatic environmental and productivity benefits.

Deviated wells drilled from new compact rigs are enabling the development of large reservoirs from small drill pads or from single offshore platforms. The resulting “small footprint” developments, exemplified by fields such as Alpine on the North Slope, minimize impacts on the surface land. Downhole injection of drilling wastes has also eliminated the need for surface reserve pits for waste disposal.

“Safety and environmental is a priority at the rig site,” Lucht said. “We model our drilling operations around how to do it safely and environmentally friendly, and still accomplish what we want to do.”

Precision wells, including horizontal wells, are enabling drillers to thread the drill strings through elusive pockets of oil, thus greatly increasing the volume of oil recoverable from oil fields.

And the use of multilateral, horizontal wells is making possible the production of thick, viscous oil. In the West Sak field, for example, viscous oil in a pay zone 75 to 100 feet thick would not produce in viable quantities into a traditional near-vertical well. But horizontal well bores have now exposed as much as 20,000 feet of pay in one well, thus making economic production feasible from an oil pool discovered many years ago, Eggemeyer said.

“By exposing that much reservoir rock you’re able to open the door on this whole new development of West Sak oil,” Eggemeyer said. “It’s strictly a technology discovery.”

And Eggemeyer credits the various service companies involved in the drilling industry for much of this continuing success in expanding the drilling envelope.

“We’ve got a lot of service companies that are just pushing everything they can to get to the next step on technology,” Eggemeyer said. “It’s certainly an industry effort.”

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