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Petrobank Ready to Fire Up its THAI Oil-Sands Process

The THAI process. Not to scale. Click to enlarge.

Petrobank, a Calgary, Canada-based oil and natural gas exploration and production company, is commissioning its WHITESANDS oil-sands pilot project using the proprietary in-situ THAI combustion process. Pre-ignition warming is scheduled to begin in February, with combustion initiating by May 2006.

The THAI (Toe-to-Heel Air Injection) process combines a vertical air injection well with a horizontal production well.

During the process a combustion front is created where part of the oil in the reservoir is burned, generating heat, thereby reducing the viscosity of the remaining oil. Gravity pulls the oil to the horizontal production well.

The combustion front sweeps the oil from the toe of the horizontal production well (the underground termination of the horizontal portion) to its heel (the transition of the production well from horizontal to vertical).

THAI promises recovery of an estimated 80% of the original-oil-in-place while partially upgrading the crude oil in-situ. Petrobank also holds the rights to a well-bore integrated catalyst (CAPRI), the use of which could further upgrade the syncrude in-situ.

3D rendering of project site, with aerial surface photo of project site inset.

WHITESANDS is a C$30-million (US$26-million) pilot project that consists of three horizontal wells (500 metres long and 100 metres apart), three vertical air injection wells and 19 vertical observation wells (17 for temperature and two for pressure observations).

Peak production from the three wells is estimated at 1,800 barrels per day or 600 barrels of oil per day per horizontal well (1.8 kbpd total).

Pre-ignition warming consists of heating the oil sands formation—which is about 370 meters (1,200 feet) below the surface— by injecting steam through the air injection and production wells for a period of two to three months.

After the pre-heating period, air is then injected into the oil sands through the air injection wells. As the air reaches the heated oil sands, combustion begins. A 2m-thick vertical combustion front will form that will move forward along the horizontal well at about 25 cm (10 inches) per day.

Combustion here refers to the flameless, high-temperature oxidation of the heavier part of the bitumen (called coke) left behind as the process proceeds.

Hot combustion gases that are depleted of oxygen contact the oil ahead of the combustion zone and heat the oil to above 400ºC. The high temperatures in the presence of formation clays cause thermal cracking and upgrading of the oil by 7–8º degrees API gravity in laboratory physical models.

The hot, lighter cracked oil, reservoir water and combustion gases (primarily nitrogen and carbon dioxide) drain downward into the horizontal well for transmission directly to the surface for processing by produced gas lift.

Some virgin oil warmed by conductive heating ahead of and behind the combustion front also drains into the horizontal well. Up to ten percent of the original oil, the heavier, higher-boiling fraction, is left behind on the rock formation and becomes the combustion fuel as the burning front advances. THAI consumes only air as an injected raw material.

A water supply well will provide the water source for WHITESANDS. A second well may be installed to serve as a backup, and for monitoring water levels and the chemical quality of the groundwater. Petrobank estimates maximum groundwater production rates for Year 1 and Years 2 to 5 are currently estimated to be approximately 725 m3/day and 575 m3/day, respectively.

Assuming full 1,800 bpd production (286 m3) and the lower water rate for years 2 through 5, that works out to a project water-to-oil ratio of 2:1. In other words, two barrels of project water for every barrel of oil.

WHITESANDS will also generate a number of waste streams requiring disposal. CO2 emissions will be a projected 30,600 m3 per day (based on a 12% component of daily produced gas waste of 255,000 m3).

WHITESANDS Project Waste Streams
Waste Stream Flow rate Storage/Disposal Characterization
Sand Net solids: 1 m3/day Enclosed tank with vapor recovery. Trucked out. Sand with a hydrocarbon residue.
Water softener 7 m3/day Disposal well High mineralized water. (During startup only.)
Steam generator blowdown water 20 m3/day Disposal well Highly mineralized water. (During startup only.)
Tank blanket gas 400 m3/day (dry) Flared (incinerated) Methane, CO2 with an H2S component.
Combustion gas 255,000 m3/day Vented to atmosphere Nitrogen (82%), CO2 (12%), with sulfur components.
Produced water 120 m3/day Disposal well Water created by THAI process and produced water.

According to Petrobank, THAI offers a number of potential benefits over other in-situ recovery methods, such as SAGD (Steam Assisted Gravity Drainage), including higher resource recovery; lower production and capital costs; reduced usage of natural gas and fresh water; a partially-upgraded crude oil product; reduced diluent requirements for transportation; and lower greenhouse gas emissions.

Petrobank will begin the pre-ignition-warming-cycle on the first horizontal production/vertical air injection well pair in early February. All three well pairs are expected to be on production by the end of 2006.




How does the CO2 biproduct compare to other oil/gas production methods? How many tonnes of CO2 are there in 30,600 M3?


Some quick envelope math here...

Depending upon temperature, pressure (we'll assume 1 atmosphere), 30.6 m3 gas works out to about 60 metric tons of CO2.

Divide 60 metric tons CO2 by 1,800 barrels per day, and you get a CO2 intensity factor of 0.033 tonnes/barrel.

Let's pick Suncor's oil sands operation for comparison.
In 2004, according to the sustainability report, the greenhouse gas intensity for the oil sands operation was 0.62 tonnes CO2E/m3 of production. (The company produced about 226,500 barrels per day.)

There are about 6.3 barrels per cubic meter, so the Suncor oil sands GHG intensity then works out to 0.099--call it 0.10 tonnes CO2E/barrel.

It's not apples to apples. Suncor's oil sands operation is mainly surface; in-situ represents a small percentage. Furthermore, Suncor is looking at its entire GHG load, and we just picked on CO2 for Petrobank. But the quick math does seem to indicate that the Petrobank process (as modelled and reported by the company) is less GHG intense than Suncor's processes.

Exact data from other oil sands companies is not as easy to the report for 2003 from the Alberta government, the specific GHG oil sands project figures for all the providers--with the exception of Suncor--are labelled "confidential".

Harvey D

Tar sands activities produce huge amount of GHG. For example, in 2003, the GHG per capita for major provinces in Canada was:

1) Alberta = 72.3 Tonnes (Tar sands + cpp)
2) Ontario = 17.1 Tonnes (cpp)
3) B. C. = 15.2 Tonnes
4) Quebec = 12.2 Tonnes (hydro-electricity)
5) Canada = 23.4 Tonnes (thanks to Alta)

1) Alberta, with 9.9% of Canada's population produced 30.1% of the GHGs.
2) Ontario, with 38.1% of Canada's poulation produced 27.8% of the GHGs.
3) B.C. with 13.1% of Canada's population produced only 6.6% of the GHGs.
4) Quebec, with 24.1% of Canada's population produced only 12.6% of the GHGs.

From 1990 to 2003 GHGs increased by 24% in Canada and by 42% in the Oil & Gas production activities, mainly in Alberta.

Since tar sands activities increased in 2004 and 2005, the Alberta per capita GHG has certainly increased another 5% to 15%.

Let's hope that 'In Situ' and/or 'THAI' processes will eventually reduce the GHG per barrel, otherwise the GHG per capita per year will quick rise above 100 Tonnes in Alberta. Howerever, even if the GHG per barrel is reduced by 50% but the production is tripled, the total GHG will keep going up to during the next 5 to 10 years. No matter how well the other provinces will do, Alberta (with the tar sands) will drag Canada down for many years to come.


Where are they getting all that water from, how do they clean it before contaminating groundwater, and what suffers from water lost downstream? Though tecnically facinating (if it works), it still sounds like an ecological nightmare.


Says the heavier, higher boiling point fraction stays in the ground, to combust at the advancing air front.

From my understanding, this is the opposite of the Suncor process, which uses the natural gas from the oil sand to boil the sands and separate the oil. It would appear that methane and other hydrogenates will have greater value to exploit than long aliphatic chained heavy distillates (heating and boiler fuel), or for that matter, the sulphides. Hence the "partial upgrade" of the oil to what I presume is light crude, kerosene, and other vehicle-grade fractions, which can incorporate some of the hydrogen lost to natural gas.

Do I presume correctly that, all other things being equal, including GHG emissions, this is a better bang-for-the-buck for the fuel market as a whole (chief concern being vehicles, rather than electricity or home heat) than the Suncor-type process we saw on "60 Minutes" yesterday? Does the 0.033 tons/barrel GHG figure above cover emissions up to and including the final refinery processing of the oil into gasoline etc.?


The 0.03 figure is for the in-situ process, not for the final upgrading and refining. 'Course, the Suncor figures (0.1) don't include final upgrading and refining either.

What Petrobank can deliver re: partial upgrading and as final GHG totals (sands-to-finished product) will be interesting to see.


What is the expected overall energy efficiency of THAI? How many overall Barrels of oil energy equivalents does it take to produce one barrel of oil? Or, what is the expected extraction cost per barrel of oil? Thanks!

william millar

I own shares in pbg, very interested, would appreciate
more info


Wonder where in the production process the 2 barrels of water per barrel of produced bitumen is used? Injected with the air? Unable to find anything on PBG's website. Doesn't make sense to me. Isn't water the continuous phases in the virgin tarsands? I would think the production process would be a net producer (vs consumer) of water......anyone have any thoughts?

Steven Rogers

Thanks for the info. My brother had to get a new furnace. He was in Calgary so without it, it's freezing. Luckily, he found this really awesome company that helped him so that he didn't freeze until they were able to replace it.

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