Skip to main Content

Halliburton, Great Bear team up in shale play on North Slope

  • Author: Kay Cashman
  • Updated: September 29, 2016
  • Published November 5, 2011

Skeptics beware. If you thought Great Bear Petroleum's plan to drill 200 wells a year in its North Slope shale acreage was unrealistic, the world's second largest oil field service company thinks you're wrong.

Halliburton, an expert in extracting oil and gas from source rock in major resource plays outside Alaska, has partnered with Great Bear. In the next year Halliburton will conduct a parallel "proof of concept" multiwell program on Great Bear's acreage along the Dalton Highway -- at the same time Great Bear is executing a similar program to the south, along the highway. In the next year, each company plans to drill as many as three vertical wells and a lateral off each of those.

"We are partnering with Halliburton on an area-limited basis where they are bringing in world-class technology," Great Bear President and COO Ed Duncan told a special meeting of the Alaska Legislature's House Resources Committee on Nov. 1. (Go online to for eight slides Duncan used in his presentation.)

In the year since Great Bear first entered Alaska by winning about 500,000 acres in the state's Oct. 27, 2010, North Slope lease sale, Duncan said his company has made "a huge amount" of progress and is working closely with its industry partners, the service industry, state agencies and North Slope villages to develop shale resources.


But none of the challenges, he said in his presentation, are major impediments, including the water needed for fracking. Fracking has been controversial because of its potential to pollute ground water supplies.

Unlike North Dakota and Texas, Great Bear's acreage south of the giant Prudhoe Bay and Kuparuk River oil fields, has a near limitless supply of brackish water, between 2,000 and 5,000 feet deep, that is "very likely ideal for frack make up," Duncan said.

"We thought this going in but it has been confirmed repeatedly in the last several months of work. ... That's a really good thing for Alaska," he said.

Water makes up about 98 percent of the solution needed for the hydraulic fracturing that Great Bear will have to do to coax the hydrocarbons from Alaska's three world-class shale source rocks beneath its acreage.

Current water cycling technologies allow Great Bear to recover about 90 percent of used water for reuse in fracking operations. The remaining water, Duncan said, "will be disposed of in either existing disposal facilities in north Alaska or in our own in-field, custom-built facilities as our program grows and those facilities become ... necessary."


"We have worked very, very hard in the last year to build a testing program that will allow us to have (about a year from now) ... a very technically based, hard science discussion about what this play means for Alaska," he said.

Assuming the partners are successful with their "proof of concept," this time next year Duncan said he hopes Great Bear will be "moving toward constructing a pilot development pad ... with a modular processing unit on it that is capable of processing the produced fluids to TAPS-spec oil." Duncan said oil from the pilot development will be trucked from the gravel pad to Pump Station 1.

Great Bear intends to produce oil from the development pad for a year to create "a collection of well production curves for North Slope shale oil development."

Great Bear's "Plan of Development," shows the pilot gravel pad having up to 24 wells, with one or two production modules that can each handle 5,000 to 10,000 barrels of liquids a day, but Duncan said he thinks six wells and a 5,000-barrel-a-day module will likely be sufficient.

Sen. Tom Wagoner asked whether Duncan expected to produce 5,000 barrels a day from the six wells. Duncan said he would be able to provide a definitive answer after the wells are drilled, fracked and tested. Once Great Bear has all its permits and authorizations in place -- and has secured a drilling rig -- the program could get under way in November or December, state regulators said.

However, Duncan said he does not expect production from the wells on the development pad to be significant.

"A certain amount of water production is expected; a certain amount of gas production is expected," he said. "Gas production is good. Gas provides us reservoir energy to help lift oil to surface. ... All of our rigs, all of our pumps, all of our equipment are AC. We will have a huge power demand from our in-field operations. It's our expectation that much of the gas production will be for in-field use. In our plan ... we are also budgeting for a gas line to Prudhoe. If we have excess gas production we have no intention of venting it, we have no intention of flaring it. Our gas will be taken to Prudhoe or, just as with water disposal, we will build a subsurface storage facility on our own acreage. We have the capability of doing that. Our objective is not to waste the molecules. Not one Btu, actually, will be thrown away."


"Roughly two years from now," Duncan said he hopes to be holding up a graph that shows a tight curve and saying, "Here's the flush production in the first few months, here's what the decline curve looks like after a year of production."

Wells that produce liquids and gas from source rocks like shale tend to produce at relatively strong rates for the first few months and then drop off fairly drastically, leveling out to produce at a lower, but steady, rate for many years.

Having a year of production experience will allow "us to make a very educated judgment on how aggressively we pursue full field development," Duncan said.

"One year from now we'll be going to pilot development; a year after that we'll have tight curves in front of us and we'll be sanctioning then, hopefully, corridor development -- that's the 200 hundred wells a year."

Duncan said "our current plan . . . calls for a dedicated Great Bear pipeline system that connects all of our corridor development wells to the north, to TAPS."


At some point Great Bear will move from modular processing units on individual pads to a central processing facility.

Will it be shared with other operators?

"We presume that if others move at the same pace that we're moving, and develop oil and gas in the general area of our central processing facility that we're proposing, simultaneously then certainly a discussion can be had about shared facilities," Duncan said.

"Currently we're planning central processing facilities specifically for our production, but we're not opposed to shared facilities. There's no one else doing this right now, so for the sake of planning it's our central processing facility."


When asked where the work force to execute Great Bear's plans would come from, Duncan said, "The short answer is, the work force doesn't exist today in Alaska. He said he hopes that by working with local educators, that will change.

"Early on we visited the Fairbanks Pipeline Training Center, specifically to talk to the staff there about the sheer scale of what we were embarking on -- the sheer number of jobs that we expected to be required. Imagine the hundreds of miles of gathering lines, the pipefitters, welders, truck drivers, skilled labor of all kind that will be employed here."

And Duncan was quick to point out that source rock exploitation doesn't involve just a temporary increase in jobs.

"In full field development, this program will generate, long-term, thousands of jobs. Not a spike. There's constant upward pressure on activity. ... There's constant, long-term, accretive investment. That backdrop of activity requires a tremendous number of skilled people, and for that matter a tremendous number of grocery store clerks and teachers and all the rest," he said.

So what about those 200 wells Great Bear expects to drill every year, starting in 2014?

Duncan said the reaction he gets to that number from some Alaskans is "almost recoil," because it's so many more wells than are drilled annually in the entire state.

What's more, Great Bear's earlier presentations showed that level of drilling would continue for 45 years.

According to Duncan, more than 200 wells are drilled each month in both South Texas' Eagle Ford and North Dakota's Bakken shale plays.


Petroleum News