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OILSANDS REVIEW, MAY 2009

A Glimmer in the Eye: Looking into Oilsands Quest's technology toolbox in hopes to unlock Saskatchewan bitumen

(Click here to download the PDF version of this article.)

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."

NEWS RELEASE - AUGUST 7, 2008

Bakken Play Yields Second Discovery Well

VANCOUVER, BRITISH COLUMBIA — (Marketwire - Aug. 7, 2008) - Petrostar Petroleum Corporation (TSX VENTURE:PEP - News; FRANKFURT:LMQ - News) "Petrostar" or the "Company") is pleased to announce a new discovery well (A5) in an area of SE Saskatchewan currently not being drilled by other producers.

The well encountered 20+m of pay in a sand formation with excellent porosity (15-30%) and good permeability. This sand zone is in the Mississippian Group of Sands.

The Company is now preparing its next drill location and will announce details shortly. Petrostar will test the A5 and, upon successful testing, proceed with production over the next few weeks.

The A3 well logs have been further analyzed and there are now 2 significant shows of oil. There is a 14+m pay zone that corresponds to the A5 well's zone, and another shallower zone with 10+m of pay that may be lighter oil.

The Company is now evaluating the testing and production of these 2 zones in the A3 well.

The leases are located in the SE Saskatchewan extension of the prolific Bakken oil play that covers Southern Alberta, Saskatchewan, & Manitoba in Canada and Montana & North Dakota in the USA.

The Company is continuing to locate and has acquired substantial PNG rights to additional lands within the general area of the Bakken play and Petrostar's general area of interest.

On behalf of the Board of Directors,

Robert A. Sim, President and Director

ENERGY & CAPITAL - AUGUST 5, 2008

A Better Way to Invest in Saskatchewan's Oil Boom

I'll be the first to admit that whenever a reader and I used talk about Canadian energy, my first thought was about Alberta. More specifically, the Canadian oil sands.

After seeing the operations firsthand, it was too easy to get excited over the three oil sands deposits in Alberta.

Yet if we were to strike up a conversation within the last few months, I'd bet the first thing to come up wouldn't be Alberta. In fact, the last time I mentioned the oil boom in Saskatchewan, our President was in the middle of pleading with the Saudis to raise oil output.

Back then, I also pointed out that the key to lowering our dependence on Saudi oil imports isn't begging them for more. The Saudis aren't even the largest source for U.S. oil imports. That honor goes to Canada. According to Energy Information Administration, the U.S. imported over 2.4 million barrels of oil and products per day in 2007.

So how exactly have things been going for oil, lately?

After retreating from a high of $147.90 per barrel on July 11, 2008, crude prices have slipped about 20%. The latest dip is being attributed to a tropical storm that hit land without any disruptions to oil rigs or refineries, as well as a slowdown in U.S. and European economies. Furthermore, European retail sales have reached a 13-year low.

But I've told my readers many times before, don't hold your breath waiting for cheap oil.

Saskatchewan's Share in the Bakken Shale

I'd wager that the majority of my readers have become familiar with the Bakken formation. Many of those people were able to take advantage of the oil boom and make a tidy profit from several plays in the area.

On the U.S. side of the Bakken play, the real surge took place when the USGS reported the geological formation hods up to 4.3 billion barrels of recoverable oil. Remember, the USGS assessment was referring only to "undiscovered, technically recoverable" oil, which gives us a good idea of the size of this oil pool.

Over on the Canadian side of the Bakken, things are heating up just as quickly as producers rush to grab as much land as possible. Many producers have been moving operations from Alberta.

Production from the Canadian Bakken in 2007 was about 56,000 barrels per day. With the drilling frenzy happening now, I wouldn't be surprised to see that number swell within the next two years.

Interestingly, the question I've been getting from readers hasn't been whether or not to focus on one province or the other, but rather which part of the Saskatchewan oil boom to look at.

Like you, I've been inundated with emails about how the Saskatchewan oil sands are the hottest part of the Saskatchewan boom.

Canadian Oil Investing: Bakken Shale or Oil Sands?

I won't immediately dismiss the oil sands deposits in northwestern Saskatchewan, but there are certainly better opportunities. Production from Canadian oil sands stands at a little more than a million barrels per day (which is still a four-fold increase compared to a decade ago).

Some producers, like Oil Sands Quest, Inc. (AMEX: BQI) are dipping their hands in both oil sands and shale oil in Saskatchewan. Along with energy companies across the board, shares have taken a beating as energy prices slide lower.

One thing that makes the Bakken more attractive to producers is the quality of oil. Unlike the thick bitumen, crude oil from the Bakken is a higher quality than Saudi oil.

If you're looking to play the Saskatchewan side of the Bakken formation, you can't go wrong with Crescent Point energy Trust (TSX: CPG.UN). Despite the latest volatility in oil prices, Crescent Point is still up approximately 34% this year. The Trust is expecting its production to average 36,250 boe/day and generate a record cash flow during 2008. If Crescent can deliver on its forecasts, picking up shares at a discount now could turn a tidy profit.

The last time we talked about the Saskatchewan side of the Bakken formation, I mentioned two other prospective plays. TriStar Oil and Gas (TSE: TOG) and Petrostar Petroleum Corp. (CVE: PEP). Although energy companies have had a rough time lately, TriStar has managed to stay afloat. Petrostar, however, is a different story. Since the beginning of June, shares of Petrostar Petroleum have nearly doubled. The smaller company began drilling in early June. If Petrostar can come out with some positive drill results, I would expect this producer to break higher in the next few months.

On the Road to Saskatchewan

Even though the sun was setting as I raced across Saskatchewan on my whirlwind trip to Alberta, I could still make out the individual drilling rigs dotting the landscape. I can't help feeling a twinge of regret from not spending more time exploring Saskatchewan.

I can feel the same restlessness building. This time, however, I won't make the same mistake twice.

RESOURCEWORLD MAGAZINE, VOLUME 5, ISSUE 3 - OIL & GAS STOCKS TO WATCH

Petrostar Petroleum harnesses technology to create opportunity

New technologies are being deployed in the oil patch to enhance the recovery of previously unrecoverable reserves of oil and gas, thereby creating opportunities for junior companies capable of embracing and managing the new tools.

An example worth of note is Petrostar Petroleum Corp., [PEP-TSXV; PSCSF-OTC; LMQ-Frankfurt], an oil and gas operator in Saskatchewan, Canada, focused on finding and developing probable and proven heavy and medium crude oil assets using patented drilling and recovery systems and other proprietary technology to enhance oil recovery.

Petrostar pursues a strategy combining production and development of enhanced oil recovery technologies. To that end, the company has an interest in two oil and gas projects in the Maidstone Oil Field and Kew Field and in developing two enhanced oil recovery systems and technologies in the Vertizontal Recovery System (VRS) and Enhanced Recovery System (ERS - Down Hole Tool "DHT").

Petrostar is the sole operator of the 320-acre Maidstone property located in west-central Saskatchewan, near Lloydminster, controlling 100% of the property's production lease. The company's Maidstone lease is a development property with over 5 million barrels of original oil in place in the McLaren formation. Since acquiring the property in June 2005, the company has successfully increased diluent and oil production.

The Maidstone property is located in the prolific heavy/medium oil zone which contains three primary oil formations - the McLaren, Waseca and Sparky, and has a long history of oil production that is supported by a highly developed infrastructure. Nearby Petrostar's Maidstone property is the Husky Upgrader where the company ships all of its production, and adjacent to it are Shell Canada's leases which the acquired through the purchase of Blackrock Resources.

In addition to Petrostar's Maidstone leases, the company holds two leases in the Kew Field, in the historical Turner Valley in southwestern Alberta. The company holds a 26% working interest in the first lease which is operated by Odin Capital (formerly operated by Win Energy Inc.) and a 7% working interest in the second lease that had as its original venture partner and operator, Purcell Energy, which had a 50% interest in the prospect. Purcell Energy transferred its interest to Prairie Schooner, which subsequently has amalgamated and is now operating as True Energy.

Petrostar owns a 20.5% royalty of the patented VRS, Vertizontal Recovery System and a 75% royalty of the patent pending DHT, Down Hole Tool. The balance of the royalty rights are held by Vertizontal Energy Resources Inc. Field testing on these two enhanced oil recovery technologies will be completed by the first quarter in 2007. In fact, the third phase of the five-phase testing of the VRS was complete mid-November 2006.

The opportunity for commercializing the enhanced oil recovery technologies is vast, as over the last 25 years oil and gas companies have abandoned tens of thousands of heavy/medium crude oil wells in North America due to low bottom hole pressure and uneconomical daily production. Through testing and commercializing the EOR technologies, Petrostar has the opportunity to be engaged in resurrecting some of these abandoned, low bottom hole pressure oil wells.

Presently Petrostar is conducting the $4 million Five-Phase VRS work-over program on its Maidstone property, of which the first three phases are near completion. They have:

• Upgraded all existing surface equipment, drilled one 578-metre dual producing Vertical Stratigraphic well (D16-6) into both the McLaren and Waseca oil formations.
• Drilled a 1,200-metre Horizontal (HRZ) production well from the hell of the new Vertical Stratigraphic well (D16-6) at a total depth (TD) of 575 metres to the western border of the property. They are:
• Drilling a second 1,200-metre HRZ production well into the McLaren formation from its existing A16-6 vertical well to the western border of the property.
• Converting the second HRZ Production well to a Water Injection well, once license is granted from Saskatchewan Industry and Resources (SIR).
• Drilling one 800-metre HRZ collection well from the company's A9-6 to A12-6 vertical wells. The five-phase work-over program is designed to increase daily oil production as each phase is completed.

James West is an independent investor and writer whose extensive work in the mining industry has given him an insider's access to emerging public companies in the resource sector. Visit him online at http://www.devilsadvocatereport.com.