Friday, September 2, 2011

It’s going gangbusters; BP meets with initial success in tests of heavy oil production at Milne Point

Alan Bailey
Petroleum News

BP’s heavy oil test facility at Milne Point S Pad on Alaska’s North Slope has been going gangbusters since the facility started up in early May. Petroleum engineering consultant Dudley Platt has pointed out to Petroleum News that in July the facility’s single operating heavy oil test well, drawing thick, syrupy oil from sands in the shallow Ugnu formation, appeared to have achieved average daily production rates in excess of the per well average production from conventional wells in the main oil pool at Prudhoe Bay, according to data from the Alaska Oil and Gas Conservation Commission.

On Aug. 31 Eric West, manager of BP’s Alaska renewal team, told Petroleum News that it is too soon to make production comparisons with conventional North Slope oil wells but that the heavy oil test well had achieved a maximum production rate of 550 net barrels of oil per day. The well had produced a total of 45,000 barrels of heavy oil over 117 days of continuous operation since testing started in April.

“We are pleased with the well. … It’s awesome,” West said.

Major resource

There are an estimated 12 billion to 18 billion barrels of heavy oil in the Ugnu, a potential major resource even if only a relatively low percentage of that oil can ultimately be recovered.

But don’t expect the spigots to open for commercial heavy oil production from the Ugnu any time soon. BP has yet to determine whether production can be sustained at commercial levels in the long term, and has yet to test production from well configurations other than the single well that has been in operation. Unknowns include the production performance of different zones within the Ugnu reservoir — the reservoir consists of a series of discrete, differing sand bodies, rather than a single, homogeneous unit.

The idea is to avoid the results from a single well turning out to be a false positive before going to the bank on a development project — it is necessary to see repeated production from multiple wells, West explained.

Four wells

BP has in fact drilled four wells for its heavy oil testing, each in a different reservoir zone. Two of the wells, including the one that the company has tested to date, are horizontal wells, configured to access a relatively large volume of Ugnu sand. The other two wells are vertical, designed to use a technique called cold heavy oil production with sand, or CHOPS, involving the use of an augur-like downhole pump to draw a mixture of sand and oil into the well.

The horizontal wells use the same type of pump as the CHOPS wells, with the pump drawing down the reservoir pressure around the well bore, thus causing gas in the reservoir to effervesce, forming a foamy material with the oil. The effervescing gas drives the foam into the well bore, from where the foam can be pumped up the well bore to the surface.

“We know that’s working because the samples we acquire at the wellhead show evidence of that (foam),” West said.

When BP first put the test well into production the company started with a relatively modest pump rotation speed of 100 rpm, subsequently turning up the throttle to observe how the well reacts to increasing pump speeds — the higher the pump speed, the greater the oil production rate, with the proviso that a too-high speed would cause gas to separate from oil in the reservoir, thus compromising oil production.

Worn tubing

A solid rod passing down the well bore from the surface turns the pump rotor. Over time this spinning rod puts wear on the steel tubing that lines the well, thus requiring some of the tubing to be replaced. BP has recently had to stop production from the test well because the rod had worn a hole in the tubing. The company has since been profiling the thickness of the tubing down the well, to determine which sections of the tubing to replace with specially hardened pipe for continued well operation. Wear on the tubing had been anticipated, with determining the rate of wear being one of the test objectives.

“Actually we got a little more life out of it than we thought,” West said.

And closing the well for a while will provide an opportunity to determine how effectively production will restart after a shutdown, helping determine the sustainability of heavy oil production through the inevitable well workovers that would take place in a commercial production environment.

Gas flush system

One unanticipated problem in the heavy oil testing has been a failure of the system designed to scrub gas out of the produced oil. Instead of using this system, BP has obtained permission to flare the gas, while producing oil from just the one well until the gas scrubbing system is fixed, West said. The company is hesitant to bring any other wells on line until that fix has been completed, he said.

On the plus side of the testing equation, BP has been delighted with the way sand flowing into the well has flushed from the well bore without a need shut the well in for cleaning, West said.

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Republished with the permission of the Petroleum News