BP Milne Point focus on viscous oil

Ugnu well drilled in 2003; more wells into shallowest formation planned for 2005; Northstar tubing record

Kristen Nelson

Petroleum News Editor-in-Chief

At the Alaska North Slope Milne Point field development drilling encompasses both conventional Kuparuk formation oil and shallow viscous Schrader Bluff oil.

BP Exploration (Alaska), the field owner and operator, has even drilled into the shallowest and most viscous formation, the Ugnu, and plans more Ugnu wells next year.

Probably two-thirds of the drilling at Milne Point this year has been viscous, says BP senior drilling engineer Pat Archey. A rotary rig, Doyon 14, is used for both viscous Schrader Bluff wells and Kuparuk formation wells at the field on the edge of the Beaufort Sea northwest of Prudhoe Bay.

On the conventional oil side, “Milne still has several targets to exploit in the field” from the farthest north drill site, F pad, Archey said, These are Kuparuk formation targets out under the Beaufort Sea which will be reached with extended reach drilling technology and are planned for next year, although some of the targets, he said, are far enough out to be beyond the reach of current ERD technology.

But Schrader Bluff viscous oil (also referred to as “heavy oil”) is the biggest part of Milne Point drilling right now, with production primarily from the Schrader O sands, and to a lesser extent from the Schrader N sands. Schrader Bluff is a shallower formation than the Kuparuk.

“These sands are really equivalent with the West Sak” at the Kuparuk River unit and with what BP is developing at Orion in the western part of Prudhoe Bay, he said.

Ugnu wells planned next year

“The Ugnu reservoir … is thicker yet and colder (than Schrader Bluff), making it harder to produce,” Archey said.

Conventional oil is a free-flowing liquid; shallower Schrader Bluff oil is thicker and not as free flowing; and Ugnu, the shallowest of the formations, is closest to permafrost and colder, with a consistency that makes it difficult to flow the oil.

BP drilled an Ugnu well in 2003, but hasn’t yet produced any oil from the formation and the well “plugged off pretty quickly,” Archey said.

BP has been trying to determine what to change down hole so the Ugnu oil can be produced, difficult both because the oil is cold and thick and because of the associated sand. Shallow viscous oils are in what are called unconsolidated reservoirs, bits of which are produced, as sand, along with the oil.

The Ugnu well BP drilled had screens to try to keep the sand in the formation and out of the oil flow, with screen mesh wrapped around perforations. The screen mesh in the existing well must be too tight, Archey said: “It’s filtering out everything. So our next attempt would be to change the size of those passageways,” perhaps using slots or perforated pipe, to get the oil to flow.

“Then the challenge is sand,” he said. Ideally, you keep the sand in the ground, because if it is produced, it has to be re-injected, which requires a grind and inject facility, all of which is expensive.

Individual multi-laterals can be shut off

Milne Point, like other North Slope fields, uses multi-lateral wells to reach multiple targets from a single well bore, and technology is helping BP produce these wells effectively, Archey said, because “we have the ability to shut off or produce those zones independently.”

Where multiple zones are in production from a multi-lateral well, and one leg of the multi-lateral starts to produce water, he said, that leg can be shut off, and production of oil continued from the other leg of the well.

And the technology to get those long directional wells drilled into the formation has also improved.

Directional drilling advances now allow the driller “to stay within 10 feet … out at a couple miles-plus from the surface location.” This wireless mud-pulse technology “sends pulses up through the mud” and the pulses tell the driller “if they’re in a sand or a shale” and “when you’re in that sand, if there’s water or oil” so you know whether you want to continue drilling in that direction or not.

What is missing now, Archey said, is a tool that will tell drillers how thick or thin the oil is, and whether if will flow. That could be technology that is run with the drill bit, or it could be technology that is used in pilot holes, he said.

Record at Northstar

Gary Christman, BP’s Alaska drilling and wells manager, said directional drilling equipment available this year enabled BP to set a record at Northstar. This wasn’t technology developed in Alaska, he said, but is an example of making “effective use of technology that exists in the oil patch.”

The record set was “for the longest string of 9-5/8 inch ever set” on the North Slope, Christman said. The 20,207 feet of tubing was set at a 70-degree angle, in Northstar No. 21, a 22,261-foot well reaching to the farthest north part of the reservoir.

Andy Kirk, Alaska drilling and wells performance consultant, said with rotary steer-able technology instead of bent-motor slide drilling, “you drill a straighter well bore” than you can get with slide drilling, which is “the key to getting casing down.” The “straighter the well bore, the less friction,” he said, making it possible to set longer strings of casing.

Editor’s Note: Members of BP Exploration (Alaska)’s drilling group sat down with Petroleum News Sept. 28 to talk about the company’s development drilling program, recent drilling records and about the technology that is driving the company’s North Slope development drilling. Part 1 of this story, printed in the Oct. 10 issue of Petroleum News, included an overview of the company’s North Slope drilling activity and an update on its coiled tubing drilling program. Part 3, which will appear in the Oct. 31 issue, describes multi-lateral drilling for viscous oil at Orion in the Prudhoe Bay unit.

BP’s wells group: from bringing a well on production to plugging and abandoning

The wells group uses slick line, electric line, coiled tubing and fracture stimulation, “everything except rotary and CTD (coiled tubing drilling),” Kirk said, with well work done with coiled tubing units, as distinguished from coiled tubing drilling units.

Work includes patching tubing with wireline and coiled tubing to extend the life of a well, and deferring or delaying “a rig workover where the tubing would be pulled and replaced, which is an expensive operation,” Kirk said.

A new technology, called “cladding,” uses long patches “which are a metal-to-metal seal or extruded, expanded metal inside of an existing tubing” and sealed to existing tubing at the top and bottom of the patch “so effectively you can cover up a couple thousand feet of corroded tubing.”

And, with co-owner ConocoPhillips, BP is using “some high-strength coiled tubing” which is being tested for dislodging plugs with coil, and is “going to be deploying some chrome coil velocity strings,” Kirk said.

Velocity strings are used to improve production, said BP senior coiled tubing drilling engineer Mark Johnson.

“Sometimes wells produce better through smaller tubing,” Johnson said. “A velocity string is … a smaller string of tubing inserted into a well to shrink its tubing size, but actually get more production rate out of the well because it flows better.”

Kirk said they’ll also be testing the 16-chrome corrosion-resistant coil “as a work string,” to see if it lasts longer than standard steel coiled tubing in use.

Wells does field trials

So in addition to developing technology (see part 1 of this story in Oct. 3 issue of Petroleum News) such as coiled tubing, “we also help test technology for the rest of the corporation,” Christman said.

A two-man slick-line unit, designed to be operated by two men in the Arctic, was brought to the slope by Schlumberger in May, said Christman, the result of a contracting effort last year. There was a “collaborative effort to actually design and commit to the utilization of these units, so they’re very unique to the Arctic, you don’t see these kind of units anywhere else.”

A standard slick-line unit is designed to be operated by three men, Kirk said, but with the two-man unit, there is “less personnel exposure on location.”

The goal, Christman said, is to spend dollars efficiently, “to do the same amount of work at a lower cost and as safely as we did it before.”

He said that effort has been successful, as BP’s Alaska drilling group has improved its safety record over last year. “We’re actually twice as safe this year as we were last year at this same point in tine,” with a recordable incident frequency of 0.91, compared to 2.02 for all of 2003.