Following a lengthy delay after the completion of a $100 million heavy oil test facility on Alaska’s North Slope, BP has now put a heavy oil test well into operation — at 6 a.m. on April 22 a change in torque in the well’s down-hole pump finally signaled the flow of oil through the well, something of an historic event for the North Slope oil industry, Eric West, manager of BP’s Alaska renewal team, told Petroleum News April 27. For a couple of days the well had been producing brine, injected into the oil reservoir during the drilling of the well, but the torque change indicated that oil had finally reached the well bore, West said.
West said that since the morning of April 22 the well has been producing oil at a rate of 350 barrels per day and that the test facility had delivered more than 1,000 barrels of heavy oil to the Milne Point processing facility since the oil started flowing.
“But what pleases us so much is that there has been no upset to the well,” West said. “It has produced steadily at that rate.”
And the well is only producing small amounts of sand, with sand coming up the well in quantities ranging from trace amounts to about 2 percent by volume, he said.
BP is carrying out its testing of heavy oil production from the relatively shallow sands of the Ugnu formation, to ferret out the production characteristics of the resource, with an objective of determining whether commercial-scale heavy oil production on the North Slope will be feasible both from a technical and from an economic perspective, Erik Hulm, heavy oil appraisal team leader for BP Alaska, explained to the Alaska Geological Society on April 22. Companies have been producing heavy oil elsewhere, in Canada and Venezuela for example, but no one knows whether production will prove practical in the challenging Alaska Arctic environment, Hulm said.
But the potential prize is huge, he said.
Billions of barrelsOf the 70 billion or so barrels of oil so far discovered in the central North Slope, only about 40 billion barrels consist of conventional light oil that readily flows up a well bore and through a pipeline. The remaining 30 billion barrels are relatively viscous, thus requiring specialized production techniques, Hulm said.
Within the thicker grades of oil, BP distinguishes between what it calls viscous oil, with a consistency of syrup, and heavy oil, with a consistency of honey or molasses. On the North Slope, BP and ConocoPhillips have in recent years started to produce viscous oil from the sands of the Schrader Bluff/West Sak formation, using horizontal wells and waterflood techniques. But no one has yet attempted to tap into the estimated 12 billion to 18 billion barrels of heavy oil in the shallower Ugnu formation — heavy oil is generally too viscous to flow unaided through a pipe.
Being quite depleted in hydrogen relative to light oil and also being difficult to flow, heavy oil is less valuable than light oil. On the other hand, with high oil prices and with North Slope light oil production declining, companies are moving across the oil viscosity spectrum, seeking new commercial opportunities with more difficult resources. And, with BP hoping to use North Slope light oil to dilute the heavy oil for pipeline transportation, the company wants to see if it can achieve success in heavy oil production before light oil production rates decline to a point where it becomes impractical to ship the heavy oil to market — refining the heavy oil into a less viscous fluid on the North Slope for export by pipeline would be prohibitively expensive, Hulm said.
Two methodsFor its test production, located on S pad in the Milne Point field, BP is using two techniques, both involving the pumping of oil into a heated tank at the surface, where sand is separated from the oil for disposal through the Prudhoe Bay grind-and-inject facility. The Ugnu sands, rather than being a conventional solid rock, are unconsolidated.
The first technique, called cold heavy oil production with sand, or CHOPS, involves drilling a vertical well through the Ugnu reservoir and then using what is called a progressive cavity pump, a down-hole pump with an augur-like rotor spinning at high speed, to draw the sand-oil mixture into the well and up the well bore. Small holes, known as wormholes, propagate from the well, out through the reservoir sand, increasing the exposed surface area of sand from which oil can be sucked and providing channels for the oil to flow into the well.
A rod passing down the well bore from the surface turns the pump’s rotor.
In 2008 BP successfully demonstrated the extraction of some oil from the Ugnu using a single CHOPS well, as a precursor to investing in the heavy oil test facility that it has since built.
The second technique involves the drilling of a horizontal well through the reservoir, with slots in the steel well liner creating a large area of contact with the reservoir, allowing oil to enter the well, as in a conventional oil field. A progressive cavity pump located downhole, in the area where the well bore steepens from the horizontal en route to the surface, will push the thick oil up the well. The pump will also draw down the pressure in the horizontal section of the well thus reducing the reservoir pressure — the drop in reservoir pressure should cause gas to effervesce from the oil and drive the oil towards the well, West explained.
Geologic investigationHulm explained that BP had arrived at the location and design of its heavy oil test after an exhaustive investigation of the geology of the Ugnu and an evaluation of various heavy oil production techniques.
Quite a lot of information about the Ugnu can be gleaned from the various wells that have passed through this formation en route to drilling targets in the established oil reservoirs deeper below the North Slope, Hulm said. Rock cores pulled from some of these wells provide evidence about the detailed nature of the Ugnu deposits, while well log data enable the extrapolation of rock information to wells from which well cores were not obtained. And seismic data provides a regional picture of the geometry and extent of the Ugnu formation.
Piecing together data from these various sources, geologists have determined that the Ugnu sands commonly fill what must have been meandering river channels within ancient river delta systems during the late Cretaceous and early Tertiary. The most promising looking oil reservoir units consist of multiple sand-filled river channels, stacked together to form large sand bodies in the subsurface.
The entire formation slopes west to east, lying about 2,000 feet below the surface on the western side of the central North Slope and being 5,000 feet deep to the east. Many geologic faults cut through the strata, breaking the reservoir into a multiplicity of compartments but also trapping oil in the sand bodies by juxtaposing the sand against more impervious rocks.
The heavy oil in the Ugnu has formed as a result of bacteria eating the originally formed light oil. And, with the bacteria becoming increasingly active at lower temperatures, the oil at the relatively cold, shallow western end of the Ugnu is heavier and thicker than the oil at the deeper and less cold eastern end, Hulm said.
Choice of techniqueThat variation in depth and oil type from one part of the Ugnu to another has a critical impact on the choice of technique used to extract oil from the Ugnu sands.
Hulm described a hierarchy of heavy oil extraction techniques, some of which have a multiyear track record of successful use and some of which are more hypothetical in nature. Methods that have seen success in some parts of the world can be broadly categorized as mining, hot extraction and cold extraction.
The direct mining of heavy oil deposits can be eliminated as a possibility for heavy oil production on the North Slope, in part because of the depth of the Ugnu sands and in part because of unacceptable environmental impacts, Hulm said. Hot extraction, typically involving the injection of steam into the underground sand to reduce the oil viscosity, has been used with success in Canada and is a possible candidate for North Slope use. Both CHOPS and the use of horizontal wells are examples of cold oil extraction techniques and both have track records of success in some places.
But the best technique to use in a particular situation depends on the particular combination of oil and rock properties that a would-be heavy oil producer is dealing with, Hulm said.
“It’s actually the rock and fluid properties that dictate which of these methods is going to work,” he said.
For its North Slope heavy oil production test, BP determined that cold techniques — CHOPS and horizontal wells — would be most appropriate. These techniques seemed suitable for the reservoir depths, sand qualities and oil viscosities within the North Slope units where BP is operator, Hulm explained. And the use of cold techniques would avoid some engineering challenges potentially associated with pumping hot steam through well pipes in the North Slope permafrost, he said.
However, it is likely that a hot, steam-driven technique would be more appropriate in the shallower and heavier oil deposits, more toward the western end of the Ugnu, he said.
Risk assessmentUsing the results of its geologic analysis, BP developed a set of maps depicting the relative risks to successful cold heavy oil production at different places, using parameters such as the rock porosity, sand thickness and oil quality. The maps led BP to the selection of the Milne Point S-pad as a suitable test location. The location sits over stacked, Ugnu channel sands and is within reaching distance of several reservoir zones and a couple of faulted reservoir compartments, Hulm said.
And BP sees the possibility of 7 billion barrels of oil in place in reservoir areas earmarked as candidates for cold production. If cold extraction works the recovery factor would likely be around 10 percent, but could approach 20 percent, Hulm said.
As a proof of concept exercise, BP is trying out two horizontal wells and two CHOPS wells in an initial test phase, West said. It will take about a week to draw down the pressure in the horizontal well that has gone into production, after which the heavy oil team will monitor the well for a week before starting up the first CHOPS well, he said.
But extracting heavy oil from a reservoir below 2,000 feet of permafrost in the Arctic represents a move outside the envelope of industry experience of using cold heavy oil extraction techniques, Hulm said. And the production characteristics of the Ugnu reservoir and oil are unknown. Moreover, the use of surface-driven rods to spin the progressive cavity pumps at the bottoms of wells necessarily deviated far from the vertical in the North Slope’s drilling-footprint-conscious environment will present some particular technical challenges.
Depending on the test results, BP could determine that some other production technique is required, Hulm said. However, at some time in the future heavy oil production will hopefully deliver a substantial new resource to market and bring a new source of revenue to Alaska, he said.