Skeptics beware. If you thought Great Bear Petroleum’s plan to drill 200 wells per year in its North Slope shale acreage was unrealistic, the world’s second largest oilfield 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 be conducting a parallel “proof of concept” multi-well 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 of 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 Nov. 1. (Go online to http://bit.ly/rtkXIZ for eight slides used by Duncan in his presentation.)
A PN source at Halliburton said the giant oilfield service company is covering all of the costs of its proof of concept program, except permitting, including the cost of actually drilling wells, which will likely be outsourced to a rig contractor.
In the year since Great Bear first entered Alaska by winning approximately 500,000 acres in the state’s Oct. 27, 2010, North Slope areawide lease sale, Duncan said his company has “made a huge amount of progress” and is “working very, very closely” with its “industry partners, the service industry, the state agencies, the North Slope villages … to find good solutions to the challenges that we face in developing shale resources for the state of Alaska.”
Lots and lots of brackish waterBut none of those challenges, he said in the course of his presentation, are major impediments, including water for fracking.
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 subsurface, brackish water sources, between 2,000 and 5,000 feet deep, that are “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 in order 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 the 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 infield, custom-built, facilities as our program grows and those facilities become … necessary.”
This time next year“We have worked very, very hard in the last year to build a testing program that will allow us to have … a very technically based, hard science discussion about what this play means for Alaska,” about a year from now, he said.
Assuming the partners are successful with their proof of concept programs, this time next year Duncan hopes Great Bear will be “moving toward constructing a pilot development pad … built with a modular processing unit on it that is capable of processing the produced fluids to TAPS-spec oil.”
“We want to deliver oil to Alyeska that’s ready to go in the pipeline,” he said, explaining the pilot development oil will be trucked from the gravel pad to Pump Station 1.
Great Bear intends to produce from the development pad for one year in order to create “a collection of well production curves for North Slope shale oil development.”
Great Bear’s overhead slide titled, “Plan of Development, A Staged Development Approach,” shows the pilot gravel pad having up to 24 wells with as many as two production modules that can handle 5,000 to 10,000 barrels of liquids per day each, but he thinks six wells and one 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 provide a definitive answer after the proof of concept test wells are drilled, fracked and tested. Once Great Bear has all its permits and authorizations in place — and has secured a drilling rig — that program could get under way in November or December, state regulators said.
However, Duncan 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’s 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 infield operations. It’s our expectation that much of the gas production will be for infield 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. That’s our objective.”
Two years from now“Roughly two years from now,” Duncan 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 such as 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 under Great Bear’s belt, “allows all of us to make a very educated judgment on how aggressively we pursue full field development,” Duncan said.
Next, full field development, 200 wells per year“As that decline curve, or as that tight curve develops, we will be in constant communication with you,” he told lawmakers. “You have to be as informed as we are about what is happening because that really qualifies and allows us all to judge how aggressively we want to pursue the full field development that we all hope for, because that’s a really good thing for the state. But that’s two years out. 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.”
In talking to legislators about the eight slides that were part of his presentation, Duncan referred them to “Plan of Development, Phased Development Approach — 3 Main Phases,” which presumes success in the company’s initial testing program.
The slide “captures both the concept of a pilot pad (and) … illustrates what we see as a corridor, full field, development program,” involving eight pads and 192 wells per year, he said.
Duncan cautioned that the corridor illustration was schematic.
“It’s not necessarily going to be north-south continuous. It may have a series of east-west or northwest-southeast or northeast-southwest spurs to it. The idea is, once we hit the full field development program we’ll have a large activity set knitted together with infrastructure. Our current plan, our proposal, calls for a dedicated Great Bear pipeline system that connects all of our corridor development wells to the north, to TAPS.”
Central processing facilityAt some point Great Bear will move from modular processing units on individual pads to a central processing facility, or CPF.
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 than certainly a discussion can be had about shared facilities,” Duncan said after posing the question himself.
“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.”
Where will the workers come from?
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,” but he is hoping 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 is quick to point out, 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.
The “sheer life span” of what Great Bear is proposing, “40-years plus. It’s a generational thing. It’s not flipping a light switch to fix this. It’s starting now, staying really focused, building and having it accretive. Two hundred this year, 500 next year, a 1,000 the next year, 2,000 new staff trained the following year,” Duncan said.
Duncan is also looking at tapping people who are exiting the military.
Less than one month’s wellsSo 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.
How does 200 wells compare to the number of wells drilled in the Bakken and Eagle Ford shale plays?
According to Duncan, more than 200 wells are drilled each month in both South Texas’ Eagle Ford and North Dakota’s Bakken.