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Explorers 2011: Great Bear going for the source Approaching a year in Alaska, shale player is preparing exploration and evaluation campaign Eric Lidji For Petroleum News
If a true revolution requires a change in structure, not just a change in style, then Great Bear Petroleum LLC plans to truly revolutionize oil exploration on Alaska’s North Slope.
Although exploration companies have been refining drilling and seismic techniques for decades in the search for oil, they are mostly targeting conventional reservoirs, “pools” of oil trapped inside geologic structures. Great Bear plans to target source rock, the deep formations where the oil in those conventional reservoirs was created long, long ago.
As the local independent approaches its first anniversary in Alaska, it holds out a promise to turn around the decades-long slide in production for decades to come, but fulfilling that promise will require a lot of research, a lot of time, a lot of wells and a lot of money.
Expecting to drill from four, Great Bear is permitting six drilling sites along a 15-mile stretch of the Dalton Highway and trans-Alaska oil pipeline, a location that reduces environmental impacts by being a previously disturbed, active industrial area with existing access roads and gravel sites.
Because of that location along the haul road, Great Bear is in the enviable position of being able to drill year round, so long as it can secure the necessary permits and authorizations. The company hopes to start drilling its first wells in November; at the latest ion the spring.
Core samples first Great Bear plans to drill 9,000 to 12,000-foot vertical wells to take core samples for lab analysis, followed by a sidetrack or lateral from each wellbore to conduct hydraulic fracturing and short-term production flow tests. The company plans to rotate through the six drill sites, likely drilling no more than four vertical wells, each with one lateral well.
The six sites are the Alcor No. 1, Merak No. 1, Mizar No. 1, Megrez No. 1, Dubhe No. 1 and Alioth No. 1, named after stars in the Ursa Major constellation, or: the Great Bear.
Although it didn’t have a drilling rig contracted as of mid-October, Great Bear plans to use a 1,500 to 2,000 horsepower unit that can be broken down into pieces and moved by truck.
‘Proof of concept’ Great Bear’s goal for its upcoming program is to achieve “proof of concept,” or to demonstrate it can commercial producing the oil and natural gas liquids in its leases, a process that is fundamentally different from traditional North Slope oil exploration.
If successful, Great Bear hopes to define its drilling and completion strategy in time to begin production by 2013 and believes it can sustain production through at least 2074.
That is one of many eye-popping figures to come from Great Bear this year.
When Great Bear arrived in Alaska in October 2010, picking up some 500,000 acres in a North Slope areawide lease sale, few knew anything about the company or its motivations. Both soon became clear. COO and President Ed Duncan spent the 1980s in Alaska as a project supervisor and geologist focusing on exploration with Sohio (now BP) a position that shed insight into the convergence of technology and geology in the region, including the potential of three stacked source rocks in the central North Slope.
Great Bear believes those three plays produced the oil in Prudhoe Bay, Kuparuk and other massive fields across the North Slope, but the company also estimates 80 percent of the oil produced by those source rock is still trapped in those source rocks, and believes it can recover 5-6 percent of that using current technology, or around 2 billion barrels of oil and 12 trillion cubic feet of natural gas. As technology improves, that estimate could rise.
Not a ‘blind land grab’ While shale oil, as oil-bearing source rocks are also known, is new to Alaska, it is emerging as one of the fastest growing trends in Lower 48 oil exploration and production.
The Bakken Shale is driving production increases in North Dakota and companies are flocking to the Eagle Ford Shale in South Texas. Those young plays already have competition. Chesapeake Energy Corp. CEO Aubrey McClendon recently called the Utica shale of eastern Ohio analogous but “economically superior” to the Eagle Ford.
The three stacked source rocks on the North Slope, from deepest to shallowest, are the Shublik shale, the Kingak shale and the Hue shale (also known as the GRZ or HRZ).
While these three formations stretch across much of northern Alaska, Duncan said Great Bear did not make “a blind land grab” in the October 2010 lease sale. Alaska Division of Oil and Gas Geologist Paul Decker confirmed that assessment by telling Petroleum News that he thought Great Bear had “very carefully selected” its acreage position.
“They are pretty well positioned, I would say, to pick up the appropriate thermal mature zone for the Triassic and lower Jurassic Kingak,” Decker said in March 2011.
Conventional exploration aims to find a reservoir and simultaneously measure rock characteristics such as permeability and porosity, but source rock exploration measures factors like thermal maturity, organic chemistry, tectonic history and geomechanics.
Thermal maturity
Thermal maturity is the degree to which hydrocarbons have been “cooked” by underground temperatures and pressures. Shale plays can have an oil window, a wet gas window and a dry gas window, and explorers must delineate the bounds of each to find where to drill. While the North Slope source rocks are present under the prolific Barrow Arch, for instance, the source rocks in that region are too thermally immature to develop.
Organic chemistry measures, among other things, the amount of carbon and hydrogen and the nature of the hydrocarbon resources embedded in the rock formation. Tectonic history measures the natural fractures in the rock formation that an operator will attempt to artificially expand and prop open using hydraulic fracturing. Geomechanics measures the brittleness of the rock to determine if those rocks can be fractured effectively.
So for instance, while the North Slope source rocks do not appear to be as organically rich as the Bakken or Eagle Ford, they are thicker, Decker told the Senate Resources Committee in February. The Shublik is suitably brittle, like the Bakken and Eagle Ford, but contains heavier oil, while the Kingak and Hue are less brittle, but lighter, he said.
While Decker believes the Shublik is similar to the Eagle Ford, he added that existing information about the North Slope source rocks is still limited and will be boosted greatly by a pilot program (such as the one planned by Great Bear) and by an unconventional resource assessment of Alaska that the U.S. Geological Survey is currently undertaking.
Unique aspects of source rock
The unique attributes of source rocks influence exploration and development.
Unlike conventional reservoirs, there are no dry holes in source rock exploration because the formation is completely saturated with oil. Instead of a geologic risk, source rock poses an engineering risk as companies attempt to design a cost-effective drilling method.
Whereas engineers at fields like Prudhoe Bay used natural underground pressure during the early years of production, source rock operators must expand existing rock fractures, sometimes repeatedly, to unlock oil trapped in small pores.
How small? Whereas the permeability of conventional reservoirs is measured in millidarcys, the permeability of shale formations is measured in microdarcys, a full order of magnitude smaller.
The most widely known component of this development technique is hydraulic fracturing — where operators inject large volumes or water and sand underground to expand and prop open fractures, often using chemical additives to manage rock characteristics — but the process involves many other decisions, such as the length of horizontal laterals running through the formation, the amount of fracturing stages and the volume of water.
(While the process is criticized across the Lower 48 based on concerns about water contamination, geologists such as Decker believe good engineering can keep the fractures in the shale formations separate from the fresh water aquifers thousands of feet above.)
While a shale operator might be technically capable of producing large amounts of oil, a poorly designed program could prove to be uneconomic. Therefore source rock operators must fine-tune a development strategy that maximizes production while keeping costs down. Complicating matters is the fact the decline curve on source rocks is sometimes steeper than conventional wells (although the relatively young life of shale development means operators only have a decade of information available from actual wells).
Three phases over 45 years Great Bear acknowledges this learning curve.
The company said early work will be oriented toward research and development while it looks for technique that can bring down costs through “factory drilling,” Duncan said.
That “factory” could be huge.
Great Bear is proposing to develop its leases over three 15-year phases, using 20 rigs to drill 200 wells per year, or as many as 9,000 wells over the entire life of the project.
The first two phases would develop the Shublik formation, but it doing so would drill through the Kingak and Hue Shales and collect information on those formations.
The third phase, beginning 30 years after development begins, would focus on the other formations, although Duncan said early results could justify expedited development.
As currently imagined, Great Bear would begin by drilling from eight-well pads spaced 160 acres apart and eventually cut the distance between those pads roughly in half. The company expects to drill wells that have a 9,000 to 11,000 foot vertical section and laterals extending between 4,000 and 6,000 feet horizontally. Those specifications are roughly analogous to the development tactics currently employed in the Lower 48.
Under that plan, Great Bear believes it can produce 200,000 bpd by 2020, 350,000 bpd by 2035, 450,000 bpd by 2041 and peak at 600,000 bpd by 2056 with production continuing around 450,000 bpd through 2074. Duncan said that profile could be increased by expediting the development process, and said he believes that source rock exploration might one day justify the construction of a “sister” oil pipeline from the North Slope.
That program would cost $2 billion per year plus infrastructure, or $10 million per well.
“We’re a big company in a little company body,” Duncan said.
While he has often said he is not looking for a partner (a fact soon to be disputed by the expected announcement of a partnership of sorts with oilfield service giant Halliburton), Duncan said Great Bear would be willing to share the cost of a major seismic shoot it plans to conduct from the border of the Arctic National Wildlife Refuge to the National Petroleum Reserve-Alaska.
Uncertainties remain The newness of the program, though, means that uncertainties abound.
In addition to the technical puzzle Great Bear is currently seeking to solve, the company must consider supplies: tremendous amounts of water, drilling rigs and workers.
And the North Slope Borough is looking to adjust Great Bear’s plan of operations, as well.
The nature of source rocks, a continuous formation running uninterrupted for hundreds of miles, will prompt changes to the existing rules for unitization and correlative rights, and the increase in drilling could require the state to hire more inspectors for the field.
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