Heavy Oil – The Future of Crude Oil is Syrup

As world production of light sweet crude oil declines, everyone is looking at “unconventional” oil sources to take up the slack.  “Unconventional” includes sources like heavy oil (warm thick goop), cold oil (cold thick goop), oil sands (thick goop mixed with dirt), and oil shale (solid goop).  Their common characteristic is that, compared to light sweet crude (think motor oil), they are harder (and more expensive) to produce.  Think of the difference between pumping motor oil compared to pumping asphalt.

Alaska’s North Slope is no different.  ANS blended crude, the stuff that gets pumped down the Trans-Alaska Pipeline and loaded onto oil tankers in Valdez, is currently a blend of light to medium crudes that flows pretty well.  But the future of the North Slope will increasingly be made up of shallow cold oil and deeper heavy oil.

BP is currently exploring the Ugnu formation, 4,200 down, drilling from S-Pad at Milne Point.  The plan is to use a down-hole pump to produce the oil, which has been described as having the consistency of chocolate syrup.

From Petroleum News:

An initial test should take about three weeks, with a phase one testing project continuing into 2009 and involving the drilling of three more wells by the end of 2008, Eric West, BP’s heavy oil project manager, told a media tour of the Milne Point test facility Aug. 18.

If the phase one testing demonstrates the technical feasibility of heavy oil production, the project will move into a second phase of testing, to evaluate whether heavy oil production at Milne Point will prove economically viable, said Max Easley, Alaska Consolidated Team business unit leader.

The Ugnu formation is estimated to contain roughly 20 billion barrels of heavy oil, so there is a lot of interest in the test.

The oil in the Prudhoe Bay region has migrated into various reservoirs at different depths. But bacteria that become particularly active in the temperature conditions at depths of around 4,000 feet eat out the lighter hydrocarbons, West said. That results in a residue of heavy oil in relatively shallow reservoirs far above the conventional light oil reservoirs of the North Slope oil fields.

Methane waste from the bacterial action bubbles towards the surface and becomes trapped around the base of the permafrost as gas hydrate, West said.

About three years ago BP decided to embark on a project to try to develop the heavy oil while there is still significant production of light oil from the North Slope. The light oil is needed to thin the heavy oil so that the resultant fluid can flow down the trans-Alaska pipeline, West explained

“We need the light oil to blend it with, so it’s the perfect time in the North Slope’s life,” Easley said.

Were BP to stick to the conventional concept of waiting for depletion of the North Slope light oil before producing the heavy oil, the company would have to resort to an expensive technique such as hydrogen cracking to create a light enough fluid for export by pipeline, West said.

Of course the big unanswered question is how to get the oil to the surface.  There are several options.

The most widely publicized methods consist of either the surface mining of oil sands or the application of heat to the underground reservoirs, West said. However, in Canada, the epicenter of heavy oil development, techniques for cold heavy oil extraction have also been developed, he said.

BP has a policy of not mining for heavy oil, West said. But the choice between hot and cold in-situ production depends on the nature of the oil reservoir and the characteristics of the oil, he said. On the North Slope much of the Kuparuk unit area heavy oil appears most suitable for hot extraction, while in the Prudhoe Bay and Milne Point units cold techniques seem more appropriated.

West also said that cold techniques create a smaller carbon footprint than hot techniques.

The particular technique that BP has chosen to try at Milne Point is called cold heavy oil production with sand, or CHOPS, a technique that has seen several commercial developments in Alberta.

In this technique, which depends on an unconsolidated sand reservoir, the production well has large perforations and no screen for keeping the sand out of the well. Sand is produced along with the oil and is subsequently separated from the oil at the surface by heating the oil/sand mixture in a tank.

“You’re actually producing a bit of the reservoir into the wellbore,” West said. “That is totally contrary to light oil reservoirs where you always want to keep the sand out.”

So if the oil you’re planning to pump flows like wet cement, and has grit, sand, and gravel in it like wet cement, how do you pump it?  With a cement pump (aka progressive cavity pump) of course, just like a cement truck does.

A key part of the well technology is the downhole pump, known as a progressive cavity pump, consisting of a long augur-like rotor that spins at high speed inside an enveloping tube. The rotating augur screw will draw material up the well, while being less susceptible to wear than a piston-based pump design.

Because the sand in the well would tend to cause a downhole electric motor to overheat, the pump’s motor drive is placed at the surface and is connected to the pump rotor by means of a long rotating rod that extends through the well inner casing. A huge spool called a mobile gripper unit feeds the drive rod down into the well casing.

The pump should cause a pressure drawdown or drop of around 1,000 pounds per square inch or more at the bottom of the well.

“We’re going to put really significant drawdown against these open perfs,” West said. “And that’s going to induce the formation to produce into the well.”

Once a well goes into operation, initial sand production should be high, perhaps 40 percent of the total production volume, said Grant Encelewski, operations lead tech for the BP heavy oil team. Then, after a system of fissures and wormholes in the reservoir has opened up and somewhat stabilized, sand production will drop to 10 percent or less, with a corresponding increase in oil production.

Since this is the first application of the technology in Alaska, there are a few hurdles to overcome.

Assuming that the initial well configuration works successfully, the team will try to improve flow rates — higher than normal cold heavy oil production rates will be needed to offset high Alaska well costs. The technique of choice for flow rate optimization is the use of multilateral horizontal wells but no one knows whether the sand production will work through horizontal well bores.

“No one has yet determined how you can pull sand along a horizontal well,” West said. “That’s our technology challenge.”

And one key factor will be the use of good reservoir imaging from seismic data to enable precise well placement.

“In Alberta they have a 40 percent (CHOPS) well failure rate,” West said.

The project team will try to apply innovative technologies to reduce costs. And, finally, the team will need to ensure that the footprint of the required surface equipment is acceptable.

By crossing these various hurdles, BP expects to overcome the two major challenges of heavy oil production: high production costs resulting from the high oil viscosity and the relatively low value of the product. Because the heavy oil contains a smaller proportion of high value products such as gasoline than light oil, BP expects the North Slope heavy oil to sell at about $9 per barrel below the regular price for Alaska North Slope crude. But at current oil prices, the economics look good, West said.

The bottom line:

“Without the heavy oil the future of Alaska is very much one of diminishing light oil, but then gas coming on big,” West said. “But with heavy oil you … have a rejuvenation of the fluids business for Alaska, and it becomes as much a fluids future as a gas future.”

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