An eight-fold challenge, ConocoPhillips octolateral well accesses oil pockets in maturing Kuparuk

In the early days of developing the huge Kuparuk River field on Alaska’s North Slope, producing oil involved drilling steeply inclined oil wells through a series of prolific reservoir sands. Now, with the easy oil gone but much oil still remaining underground, field operator ConocoPhillips is using ever more challenging techniques to access remaining pockets of oil in the field’s complex and fragmented system of reservoir sands.

The company recently drilled an octolateral well — a well with eight horizontal wells originating from a single near-vertical well bore — as part of its continuing efforts to extract as much resource as possible from the aging Kuparuk field. The well, drilled in what is referred to as the Kuparuk A sand, one of the main Kuparuk reservoir formations, used a technique called coiled tubing drilling, involving the use of a continuous length of flexible, small-diameter steel tubing, rather than the lengths of rigid steel drill-pipe used in a more conventional drilling operation.

Michael Braun, ConocoPhillips Kuparuk development supervisor, and Lamar Gantt, the company’s coiled tubing engineering supervisor, talked to Petroleum News about the evolution of coiled tubing drilling and the challenges of drilling a multilateral well using the technique.

The use of coiled tubing, which began in earnest on the North Slope around 1998, involves installing a device called a whipstock deep in an existing steeply inclined wellbore, to provide a ramp against the well casing, Gantt explained. That ramp allows the milling of a window through the casing, providing an opening through which coiled tubing drilling can be performed. Using a small drill bit driven by a “mud motor,” a device powered by the drilling mud that is circulated through a well during a drilling operation, the coiled tubing augurs its way through the oil reservoir formation, typically in a near-horizontal configuration, out to distances of perhaps 2,000 to 4,000 feet from the originating steep wellbore.

In a mature field such as Kuparuk, coiled tubing enables the drilling of new well bores out from existing wells, thus avoiding the cost and environmental impact of drilling completely new wells from the surface.

Braun said that coiled tubing has proved particularly valuable in the Kuparuk field because of the manner in which the reservoir rocks of the field are compartmentalized — split by a multitude of geologic faults into a series of individual sand pockets. Using coiled tubing techniques, drillers can thread a well horizontally through sand units, anywhere from 10 to 25 feet thick, accessing elusive pools of oil that make vital contributions to continuing field production.

“It is that compartmentalization that makes coiled tubing drilling an efficient tool to tap into these multiple fault blocks … from one existing wellbore, to access multiple, relatively small pockets of remaining oil,” Braun said.

Drillers steer the coiled tubing through the subsurface rocks using a drill bit motor that is bent, to enable it to be pointed in the required direction of drilling, while a gyroscopic device enables the drillers to monitor the orientation and location of the drill bit. Downhole, real-time logging tools provide insights into the nature of the rocks being penetrated, thus helping geologists to monitor drilling progress, making adjustments to the drilling plan as necessary.

Electrical wiring in the coiled tubing enables the drillers to communicate with the various tools at the downhole end of the well.

Drilling projects are dependent on the use of high-resolution seismic data, to ferret out potential drilling targets and plan well trajectories. However, one challenge at Kuparuk is the fact that many of the reservoir sand units are too thin to be resolved as images from the seismic data. Consequently there can be surprises and challenges, requiring changes to drilling plans, when the subsurface geology turns out to be different from what was expected, Braun said.

“It’s a pretty demanding drilling environment and requires some real close attention to the geology that we’re drilling and how the drilling machine is talking to us as we go along,” Gantt said.

Over the course of several years, coiled tubing drilling techniques evolved and improved — ConocoPhillips has developed a specialized drilling rig for coiled tubing drilling, configured to handle the coiled tubing and specially designed for use on the roads and drilling pads of the Kuparuk field.

Around 2004 a technique emerged for drilling so-called multilateral wells, in which one or more additional coiled tubing horizontal well are drilled out from the original coiled tubing well, all from the same pre-existing steeply inclined well. As people gained experience of multilateral drilling techniques, it became possible to drill an increasing number of laterals from the same wellbore, culminating in the octolateral well that ConocoPhillips has now drilled.

The drilling of multilateral wells provides economies in the re-use of existing well bores when accessing multiple, small reservoir targets, Braun said. The octolateral well, for example, has a total length of nearly 13,000 feet of well bore in its lateral wells, Gantt said.

The drilling of a multilateral coiled tubing well is somewhat analogous to the growth of a tree root, in which successive root tendrils grow out from a single original root stem. After drilling the first lateral well, the well bore is lined with small diameter slotted liner from the toe of the lateral back to the point from where the next lateral will kick off. Throughout this process, the “trunk” or “heel” of the multi-lateral wellbore remains open until all of the laterals have been completed, at which point the last lateral is fitted with a slotted liner, to allow oil production while maintaining well stability.

One of the major challenges in the technique stems from the fact that the original lateral well cannot be cased until all of the laterals have been drilled. With the wells typically passing through somewhat unstable shales, there is a risk of the uncased well collapsing before the drilling can be completed, requiring the lateral to be re-drilled at significant additional cost, Gantt explained.

Differences in reservoir pressure from one fault block to another, as a lateral well snakes its way through a series of subsurface structures, can also become a headache for the drillers, Braun commented. In particular, it may be necessary to design a project-specific drilling mud that allows drilling through multiple fault blocks of different reservoir pressures, maintaining well stability while containing the drilling fluids in low-pressure blocks.

Also, the demands of coiled tubing drilling require the use of solids-free drilling fluids, which is a limiting factor in terms of the mud densities that can be achieved. That in turn places limitations on the reservoir pressures that a coiled tubing drilling operation can handle, Gantt explained.

Another challenge at Kuparuk has been the fact that the “gas lift” artificial lift method used in the field has required the use of production tubing that is too small to accommodate the coiled tubing tools used elsewhere in the world, Gantt said. Consequently, the use of coiled tubing at Kuparuk has necessitated the pioneering development of exceptionally small diameter downhole tools, he said.

And the use of coiled tubing drilling, despite its many benefits, does not come cheap. Many coiled tubing projects require a workover of the original steeply inclined well, perhaps running a new completion into the well or installing new well tubing. A large team of reservoir engineers, geophysicists and geologists identifies subsurface drilling opportunities, while a team of drilling engineers executes the drilling. Geologists assist in guiding the drill bit through the subsurface rock formation.

But ConocoPhillips continues to find new opportunities to use coiled tubing drilling and multilateral wells to maximize oil production from the Kuparuk field, Braun said.

Interesting read — thanks for posting! When this eventually makes it to the MSM, I bet the (re-)writer will have to insert some gratuitous mention of hydraulic fracturing or, failing that, the effects on caribou migration patterns.

ConocoPhillips’ custom-built coiled tubing drilling rig, CDR-5, was designed to optimize drilling operations. It maximizes oil recovery through the use of a continuous string of tubing spooled off a reel into an existing wellbore. The flexible tubing is used instead of pipe to deliver and control drill bits and other tools in the reservoir.

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Aerial view of the Kuparuk Operations Center, including Central Processing Facility 1 (CPF1) in the foreground. The Kuparuk field is celebrating its 30th year of operation in 2012.

http://www.akbizmag.com/Alaska-Business-Monthly/August-2012/ConocoPhillips-Continues-to-Invest-in-Alaska/

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Without the arctic shelter, coiled tubing rigs can look like:

....some gratuitous mention of hydraulic fracturing or, failing that, the effects on caribou migration patterns.

No, I don't think they'll get to the caribou.

They'll be 'way too busy emoting about all the "hazards" and lobbying for controls on "potential for leaks or accidents".

....all of this probably run under pictures of the BP blowout, just for illustration.

GRRRRR

Is this truly a more economical way to drill for these pockets of oil, or is it simply more economical than drilling new wells because the EPA regs make them so expensive?

Similar to complying with the tax code, sometimes it’s cheaper to give accountants and lawyers millions to exploit a region of the tax code that the government slugs overlooked, than it is to do the deal in an otherwise cheaper, and more efficient manner which has been blocked by the afore mentioned slugs.

Is this truly a more economical way to drill for these pockets of oil, or is it simply more economical than drilling new wells because the EPA regs make them so expensive?

It is far more economical on the Alaskan North Slope to reach out in as many directions as possible from a single well pad. Between the frozen season and the short, swamping season, spreading out the wells is VERY expensive.

I helped engineer/design Alaskan North Slope production facilities for a few years. To prevent melting the permafrost and having your buildings and equipment sink down as you melt the permafrost, a gravel pad of 5~8 feet thick is built up. Gravel roads of similar thickness have to be built to connect each production facility.

Piping Systems often require Electrical Heat Trace; each well is connected to multiple manifolds between the test separator and other equipment. Cost go up greatly as the wells are spread out. We went to great lengths to get them as close as 25 feet and several dozen in a row.

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