North Slope oil development has come a long way

I’ve been quite bullish about all the new oil being found on the North Slope. Things are certainly looking good — intrepid explorers like Bill Armstrong at Armstrong Oil and Gas, and people at ConocoPhillips, have been finding petroleum all over the place.

A lot of this has long been known to explorers. People have been drilling for decades in areas where big discoveries are now being made. Those early drillers saw oil but they didn’t think they could economically produce it.

What’s changed is an amazing revolution in technology that allows this to now be produced. Among other things, drillers can now drill horizontal wells laterally three to four miles from the surface location of a rig, and next year when a new super-rig owned by Doyon Drilling begins operating they’ll be able to drill seven miles out.

This lowers costs and it means a lot of smaller and more complicated oil deposits can be tapped that had to be bypassed before.

The pace of this is picking up, too. We now see improvements in hardware matched with the electronics and information technology.

How about robot drillers? It’s coming. Drilling companies have experimented with remotely-controlled robot underground drilling units. The geologists tell it where to go underground and it goes there, like an intelligent worm or snake. A prototype of this unit was named Anaconda, after the big snake in the Amazon.

Envision an oil field of the future where underground reservoirs are drained by clusters of horizontal wells drilled underground with one surface production site and pipeline draining oil from tens of square miles underground — soon a hundred or more square miles.

A person might stand right above a working North Slope oil field and not see anything on the horizon except maybe caribou.

Environmental advantages are easy to visualize: No disturbance to land, no oil spills from well pad clusters or oil field flow lines, no oilfield roads and truck traffic. No noise. There are limits to this, of course. There has to be a surface facility somewhere, and a pipeline. But there will be a lot fewer of these.

Futuristic? We’re closer than you think to this.

Doyon’s super-rig is being trucked to the slope right now by ConocoPhillips to develop Fiord West, a deposit in the Alpine field that is cut off by a river channel. Building a bridge and a pipeline, and roads, would be complicated and costly, so ConocoPhillips will drill and produce Fiord West with horizontal wells that Doyon will drill from an existing production pad several miles away.

The company will use a similar strategy to develop Narwhal, a new find in the southern part of the Alpine field, thus avoiding the cost — and surface disturbance — of building surface facilities, although eventually a new production pad may be needed for a part of Narwhal that can’t yet be reached with horizontal wells.

ConocoPhillips isn’t the only company pursuing this. Eni Oil and Gas, which now operates the small Oooguruk and Nikaitchuq fields in shallow Beaufort Sea offshore waters, has been drilling a very long horizontal — “extended-reach in industry jargon” — exploration well to test potential oil deposits several miles offshore in federal Outer Continental Shelf waters. Eni hopes to do production tests next year.

All this sounds really cool, but remember that progress happens in fits and starts. Sometimes things just don’t work. But we learn from that.

An example is BP’s effort to drill and produce Liberty, an undeveloped offshore deposit that has long been known. BP wanted to produce Liberty with very long extended-reach wells drilled from shore. Some of those wells would have been eight to nine miles long, record-breaking distances.

But it didn’t work. BP built a super-rig to do the job — it takes very powerful machinery — but there were just too many technical obstacles. Now Hilcorp Energy, the new operator at Liberty, plans to develop the field with an offshore island and subsea pipeline.

Meanwhile, we benefit from mistakes. The drilling industry is now applying lessons learned as it develops those new onshore discoveries by ConocoPhillips and others.

A big payoff of the rapidly advancing technology, besides the environmental advantages of disturbing less land, is a sharp reduction of costs. If production pads, roads, utilities and pipelines on the surface can be avoided by producing with wells from nearby existing infrastructure it lowers the cost of finding and producing the new oil.

This is another piece of good news about these recent discoveries: they are costing less. Even with lower oil prices, many can be developed.

All this sounds good, but let’s not get all starry-eyed. There could be hiccups. Some of the new wells might not produce as expected. We’ve seen entire fields on the Slope where performance was well below the original expectations, an example being the small Badami field east of Prudhoe Bay. This is called “technical risk” in the industry, the chance that things may not go as planned.

Companies now engaged with these discoveries are trying to minimize technical risk with extensive flow-testing of the reservoir. So far, things seem to be going OK.

But there is always political risk, too, the chance that taxes could be raised. Companies are now very worried, for example, about a possible citizen ballot measure that would impose an estimated $1 billion to $1.5 billion in new state taxes. This isn’t chump change: Estimates are that $24 billion will be needed for these new projects over the next 10 years, and at current oil priced it’s tough enough to raise this.

Meanwhile, when I see people gathering signatures for the tax initiative outside retail stores, I like to ask what the money will be used for. Almost all reply, “Well, it’s to increase the Permanent Fund dividends!”

Tim Bradner is co-publisher of the Alaska Legislative Digest and Alaska Economic Report. From 1970 to 1985 he was employed by BP Alaska.

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