A Glimmer In The Eye:
Looking into Oilsands Quest's technology toolbox in hopes to unlock Saskatchewan bitumen
by Paul Stastny
Oilsands Review, May 2009
Saskatchewan has some of the oiliest oilsands in the world—in the order of 14 per cent bitumen content, which is even better than Alberta's Athabasca deposit at an average of 12 percent. The problem is Saskatchewan's oilsands deposit lacks cap rock like what covers Alberta's side of the Athabasca deposit. That eliminates the potential of high-pressure and high-temperature extraction methods because without cap rock, the heat would dissipate out of the formation too quickly. That means proven processes such as steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are out of the picture. And, at 200 metres below the surface, the deposit is too deep to mine.
Which is why Oilsands Quest's company name is so appropriate. Its business has turned from an exploration quest to one for a solution to this technical conundrum. Oilsands Quest holds the largest contiguous land position of possibly the highest-grade oilsands in the world. Most of it is in Saskatchewan. Some of it straddles the border into Alberta. None of it, as of yet, has given itself up for production.
"Production is still just a glimmer in our eye," says Claes Palmgren, Oilsands Quest's vice-president of reservoir engineering. Palmgren joined the company in 2008. His past experience with North American Oil Sands Corporation, Petro-Canada, and PanCanadian Resources in thermal solvent in situ bitumen recovery—some of the work even in Saskatchewan—makes him an ideal research lead.
Over the last four years, Oilsands Quest has drilled some 380 exploration holes on its Axe Lake, Saskatchewan, leases. This work has provided a lot of knowledge about where the formation lies and what it consists of. To tackle the greater challenge of identifying a viable process of bringing the bitumen to surface, Oilsands Quest has built three operational test sites on the property, each examining a different extraction process.
Test Site 1 looks at using a steam and hot water approach with an unconventional configuration of SAGD well pairs. Instead of running the steam injection well above a production well, the steam and production wells are run parallel to each other at the same depth. "We're trying to generate mobility at the bottom of the formation," Palmgren explains.
Test Site 2 examines propane injection. Solvent vapour assisted petroleum extraction (VAPEX) is being studied by a number of companies as a heavy oil enhanced recovery process, but Oilsands Quest believes a variation of this method has potential in the oilsands to reduce viscosity. It's one of the tools in the toolbox.
At Test Site 3, Oilsands Quest is working on a process also derived from the SAGD world; however, instead of using horizontal well pairs it uses two vertical wells. A further departure from its SAGD roots is how head is being generated in the formation to establish communication between the wells. Instead of pumping down steam, it's using a downhole heater developed by Petrostar Petroleum Corporation.
Petrostar and Oilsands Quest announced their cooperation around downhole tool (DHT) technology in September 2008 as a way to produce controlled underground heat, steam, and pressure without the typical heat and pressure loss of traditional surface steam generation equipment.
Wade Tokarek, Petrostar's area production superintendent, says the ability to control how much heat is produced downhole sets DHT technology apart from other downhole heaters. It also makes it particularly suitable for Oilsand Quest's application. Apart from the heat rising out of the formation too quickly if it is overheated, the fractured overburden on the lease has water moving through it, Tokarek says.
"If the zone is overheated, there's a risk that the overburden might collapse into that water zone," he says. "So they're being very smart about the way they're going about this."
Of course, another important advantage is cost. DHT technology is less expensive than building a steam facility. What is needed is just an electricity generator at surface (natural gas if available, diesel in Oilsands Quest's case), the heater and a special cable to lower it downhole and connect it to the electricity source.
Currently Test Site 3 is building heat. Both two vertical wells are closed off. Each vertical well has five wireless temperature and pressure monitoring stations along its length and the progress of the temperature rise is being closely tracked.
"We need to know more about this reservoir because of its unique reservoir geometry as compared to other Athabasca reservoirs," Palmgren says. "The bitumen saturation is higher and the sediment grain size is larger, and the permeability/porosity relationship is different than in other Athabasca reservoirs."
Palmgren notes this is just a portion of the research leading towards bitumen production in this formation. It's a building block to see if the notion works.
"I don't believe [DHT] could be used in a stand-alone application to produce bitumen in this reservoir," he says. "I don't see it working on its own in other Athebasca reservoirs either because bitumen in those reservoirs is so viscous. If you look at conventional heavy oils though, you might be able to use this tool as a stand-alone to improve production."
So the step is to generate heat in order to understand how heat moves through the reservoir. Once a certain amount of heat is established, the second step is to study the mobility of the fluids between the vertical wells. The next step, if the tool works as expected, is to consider how DHT technology could be effectively used to generate communication in a horizontal well pair.
DHT technology is a cost-effective alternative for the type of testing Oilsands Quest is currently doing, but in a larger multiple-well tests or manufacturing line production the cost advantages may disappear.
One issue in particular, according to Bill Hopkins (no relation to CEO Christopher Hopkins), Oilsands Quest's operations manager for Axe lake, is the high cost of the cable. "It's a water-saturated and oil-saturated environment, so Petrostar uses a very expensive cable that's steel braided and rated for hazardous environments," Hopkins says. "It's about $100,000 a reel. That's $27 a foot, and we're going down 200 metres." Oilsands Quest is currently trying to bring down that cost by going to a less-expensive cable.
When Palmgren says production is still just a glimmer in the eye for Oilsands Quest, here's what he means. The company started using DHT technology on Oct. 24, 2008. It ran a test for three weeks that yielded important learnings about how the heater works, how to lower it into the well, and the type of liquid it needs.
"At Test Site 3. we are conducting low-energy tests using the DHT electrical heater. After Christmas, we pulled the DHT out of the wellbore in order to modify the well completion and improve the tool itself. We completed that work and started again on Jan. 18, 2009," Palmgren says.
The current plan calls for continued heating until June 2009, at which time the cold well will be perforated and the natural movement of bitumen into both the perforated well and the hot well will be monitored.
Petrostar's Tokarek explains that currently DHT heating requires a cold producer well because the hot well can't be produced while heating. (The other alternative is to retract the heater and produce the hot well.) "The bitumen has sands suspended in it. When you heat it up, the heavy oil gets lighter and the sand falls out. Of course, that happens instantly so your well packs in around the heater and blocks the well," he explains.
With the heating phase at Test Site 3 complete, Oilsands Quest can also start moving water between the wells, although it doesn't yet have regulatory approval for doing that.
After studying the water flow characteristics between the well pair, Oilsands Quest should have a good handle on the mobility in this portion of the reservoir under low pressure and low temperature conditions. That information will then be fed into a simulator and the company can start considering how to best run the next stage of operations testing.
Everything Oilsands Quest learns at Test Site 3 will then be transferred to Test Site 1, where the company already drilled six vertical wells of 18-metre spacing and three 300-metre-horizontal wells of 50-metre spacing. Once underway, Test Site 1 will run 3 to 6 months of vertical well tests followed by another 6 to 12 months of horizontal well tests.
Then everything Oilsands Quest has gleaned should add up to a viable bitumen extraction process at Axe Lake. "It is extremely important for us to have a technology in place that makes both technical and economic sense," Palmgren says emphatically.
Asked by when, he answers it is difficult to dictate a timeline for this kind of work, but the company is committed to the process.
But, hopefully any new questions will find quick answers, because Oilsands Quest doesn't have the luxury of production cash flow to fund its research. The collapse in the equity markets has more or less closed the door for raising additional capital, and the banks aren't exactly open for business to small producers. Perhaps even less to small non-producers.
At the same lime, the company has scaled back its field activity in Saskatchewan to preserve capital. At the peak, its camp had around 400 people working. Currently, it has about 100 to 120 people, which has an inevitable effect on the pace of research. Beneath this ticking clock, Palmgren says, "We have many moving parts, but these parts are part of our overall plan as we try to determine the optimal methodology to exploit our assets."
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