THAI CAPRI Results

The progress reported on the development of THAI/CAPRI continues to be outstanding and apparently living up to hype. Whether it is living up to economic modeling remains a mystery. The fact is that they are recovering oil that is usable from the greatest oil reserves extant. As pointed out in the report, the Tarsands are not the only such reserves. They just happen to be the biggest. They are starting to use the trillion word a little more freely. This technology is able to make those resources, long known into commercial reserves.

So though we are now preparing to exit the oil energy business, it will be on our terms and a protracted dénouement has become possible.

I jumped on this two years ago and so far it has not disappointed. This technology remains the one option that can permit North America to become independent on an oil energy regime if it so chooses. I expect that we will reduce consumption swiftly by exiting the automotive fuel business and then chip at the rest. With global oil production slated to decline from a present 80m + bpd to a 40m - bpd this is a prudent move. That the vast reserves of the Tarsands promise to actually step in and absorb market share is a bit of a misnomer. On paper it could. In reality it is costly oil with a huge overhead that will keep energy costs high and at a level that clearly makes alternatives quite competitive.

It is best used as a backup fuel source while the subsidy system is transitioned over to supporting alternatives that are renewable. Its real promise is to provide a price lid on supply to prevent disruption.

Note that the CAPRI part of the process is producing significant light fraction that runs at 36 API while the process oil is coming in at 12 to 15 API from an original feedstock that runs 8 API. This all helps in getting the oil to surface and into an upgrader to make synthetic crude or to then dilute with more light crude to make shippable.

Key to all this is that it all comes directly out of a well head just like any other crude and this was practically impossible without a huge external energy source until now. Thus this technology makes the one trillion barrel tarsand fully exploitable.


August 20, 2009

Petrobank and Tristar become PetroBakken

On August 4, 2009, Petrobank and TriStar agreed to a strategic combination of TriStar and Petrobank's CBU. The combination will create a new publicly listed company, PetroBakken, that will be a premier, Bakken-focused, light oil exploration and production company.

http://nextbigfuture.com/2009/08/petrobank-and-tristar-become.html

Petrobank pioneered the horizontal fracture stimulation techniques that opened up the true potential of this substantial resource, and we continue to find new ways to improve well performance and expected ultimate recoveries from the Bakken. This zone is a marginal reservoir that has been tested and analyzed for more than 50 years, yet only recently have advances in technology created the opportunity to produce significant oil from the Bakken. Recent, repeated testing has allowed us to conclude that every time we increase the number of fracture stimulations in a given section of land, we increase productivity and expected ultimate recoveries from the zone.

Our efforts through early 2009 to further improve Bakken production have focused on increasing the intensity of fracture stimulation completions (fracs) by 38% in our long (1,400 metre) horizontals, by 200% in our short (700 metre) horizontals, and then by 400% in our short bilateral (two 700 metre horizontal legs from a single vertical well bore) horizontal wells. Recently, Petrobank also completed the first 20-stage fracture stimulation in Canada using Packers Plus technology. Our first two 20-stage frac wells have materially improved production performance compared to offset competitor wells and were initially free-flowing at rates in excess of 400 bopd. [This is double the flow rates of earlier Petrobanks Bakken oil wells in Saskatchewan] These results further demonstrate the potential of our strategy to cost-effectively increase fracture stimulation intensity and ultimate recoveries from the Bakken. We continue to build on our innovative approach to maximizing value from the Bakken resource.

We are now implementing our new drilling and completion strategy which is to drill long bilateral horizontal wells (two 1,400 metre horizontal legs from a single vertical well bore) with a total of 30 fracture stimulations (15 fracture stimulations in each horizontal leg). These are the first wells to be drilled this way, and Petrobank has successfully executed all the unique elements of this approach in other wells. By combining our two most highly effective solutions for maximizing productivity and expected ultimate recoveries, we have developed the most capital efficient oil recovery method for the Bakken, to-date.

We are also applying this approach to our large inventory of existing well bores. We have started to re-enter these horizontal wells and drill second parallel horizontal legs from the same vertical well, and complete them with higher intensity multi-stage fracs. Initial re-entry results have resulted in production increases of 80 to 150 bopd from previous well production rates prior to the re-entries.

Ongoing field efficiencies have resulted in a reduction of our Bakken production costs to $5.75/boe. This brings the average second quarter production costs for all of our CBU operations down to $6.52/boe, a 4% decrease from the $6.81/boe recorded in the first quarter of 2009 and a remarkable 27% reduction from the second quarter of 2008.

Including the TriStar assets, PetroBakken will have 330 net undeveloped Bakken sections with a drilling inventory of over 1,300 bilateral wells, only 407 of which have been assigned 2P reserves. This substantial drilling inventory combined with our innovative approach to drilling and completing Bakken wells are expected to contribute to a multi-year growth profile for PetroBakken.

Petrobank is developing the revolutionary THAI/Capri and other new oil recovery technoloyg.

Whitesands Project Update

They are showing that they can upgrade thick heavy oil (8-12 API) to light crude quality (36 API) using underground THAI/CAPRI technology. (Underground upgrading of oil). If successful and scaled up THAI/CAPRI could revolutionize the recovery and economics of heavy oil and oilsands reserves. The Canadian oilsands which is an amount of oil several times Saudi Arabian oil reserves could become cheaper and cleaner to develop and basically push off peak oil for a decade or two.

If they prove the superior economics of their process and higher recovery rates then all the other oil firms would license the technology and then you have ten of thousands projects (because the alberta oilsands are the size of Florida.) increasing the amount of oil recovered per day in Alberta and other places. Plus the THAI/CAPRI techniques are applicable to heavy oil in Saskatchewan, South America and other places. The CAPRI process is converting the heavy oil to about the API quality of Saudi light oil. This upgrading is happening underground and does not require waiting for more refineries. There is information below about the increased price of oil based on API.

Oilweek article on THAI/CAPRI

A main point about the [THAI/CAPRI] technology is that it´s not just an oilsands technology. "It addresses a lot of the issues with in situ oilsands development. It is a global heavy oil technology. It can be applied around the world in all kinds of reservoirs. Colombia, Venezuela, the United States, Saskatchewan, Russia, offshore Brazil. And we own the rights to it."

Energy investment strategies on Petrobank and the economics of their new oil recovery technology

https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEhcs1E_kuOTy-I5r6vFU658jngCfls8BJqVCt7tHiOFlSn0jej_OnZbghHqRQTBFIRmcYLVpMkPktenqOH7lw_GK660nghtONym2pRsP6ABofj_qJkDeIXccl9Qt05Gh2nS_6N6gMxuE67e/s1600-h/petrobankwhitesandsthai.jpg



During the second quarter production averaged 205 bopd, down 43 barrels per day compared to the previous quarter as operations were ramped down and stabilized in preparation for drilling the P1B and P2B wells. As previously reported, P1 was shut-in on March 31, 2009 and P2 was subsequently shut-in on July 24, 2009 to facilitate the drilling of the replacement wells for P1 and P2. Concurrent with the preparation for drilling the new wells, P3B air injection was reduced and production was stabilized at 100 bopd per day prior to and during the drilling and completion operations.

We commenced drilling P1B on July 5, 2009 and we completed drilling on July 16, 2009. This well is completed as a THAI well with a FacsRiteTM liner utilizing cartridge screens designed for superior downhole sand control, liner integrity and increased flow area. The FacsRite liner is manufactured by Absolute Completion Technologies in Alberta and internationally distributed by Schlumberger. This liner configuration has been used in projects worldwide but P1B is the first well in North America to be completed with the FacsRite design.

P2B is our second THAI/CAPRI well and drilling was completed on August 7, 2009. P2B has the same liner design as our successful P3B well. Both wells are expected to be completed, tied in and operational by the end of August, with production expected near the end of the third quarter.

P3B wellbore temperatures have been operating between 400 and 500 degrees Celsius, well within the CAPRI catalyst range. Produced light hydrocarbons from the P3B secondary separator averaged 36 degrees API and the combined P3B THAI/CAPRI production from the primary and secondary separators ranged from 12 to 15 degrees API, compared to a reservoir quality of 8 degrees API. The CAPRI upgrading effect has been measured at as much as 3 degrees API higher than THAI production, confirming a direct in-situ upgrading effect of the catalyst.

In the second quarter, we commenced a routine regulatory inspection of the surface facilities starting with the P1 production train. During the current drilling and completion operations, we will be able to complete the majority of the inspections prior to resuming full operations on all three wells. To-date, the facilities inspections have shown no evidence of any corrosion in the vessels and associated equipment.

Whitesands is now configured as a modified three well THAI/CAPRI demonstration site, which will allow us to continue to test new technology enhancements, such as oxygen enrichment, CO2 co-injection, and partial surface upgrading

. May River Project

The May River Project is our first large-scale commercial THAI application on Petrobank's oil sands leases west of Conklin, Alberta. The May River design builds on the experience gained from Whitesands. The project will be built in phases, with initial production capacity of 10,000 barrels of THAI oil per day, and an ultimate capacity of up to 100,000 bopd. We expect to receive approval for the project near the end of the year

Kerrobert Project

Drilling has started. This two well project applies the THAI technology in a conventional heavy oil reservoir at Kerrobert and is a 50/50 joint venture with Baytex Energy Trust, who purchased True Energy Trust's Saskatchewan assets. This joint project will highlight the applicability of the THAI technology in Saskatchewan's conventional heavy oil resource base. We consider that a significant portion of the estimated 20 billion of barrels of unrecovered conventional heavy oil resources in Saskatchewan can be commercialized using THAI

API and Price

Generally speaking, oil with an API gravity between 40 and 45 commands the highest prices. Above 45 degrees the molecular chains become shorter and less valuable to refineries.

Light crude oil is defined as having an API gravity higher than 31.1 °API
Medium oil is defined as having an API gravity between 22.3 °API and 31.1 °API
Heavy oil is defined as having an API gravity below 22.3 °API.
Bitumen sinks in fresh water, while oil floats.

Crude oil with API gravity less than 10 °API is referred to as extra heavy oil or bitumen. Bitumen derived from the oil sands deposits in the Alberta, Canada area has an API gravity of around 8 °API. It is 'upgraded' to an API gravity of 31 °API to 33 °API and the upgraded oil is known as synthetic crude.

THAI Process Benefits

• Minimal natural gas and water use
• Higher recovery rates - 70-80% of oil in place
• Improved economics
• Lower capital cost – 1 horizontal well, no steam & water handling facilities
• Lower operating cost – negligible natural gas & minimal water handling
• Higher netbacks for partially upgraded product
• Faster project execution time
• Lower environmental impact
• 50% less greenhouse gas emissions
• Net useable water production
• Partial upgraded oil requires less refining
• Smaller surface footprint
• THAI /CAPRI - step change heavy oil technologies
• Up to 804 mmbbls recoverable (based on SAGD) in Petrobanks Whitesand block

Petrobank is also big in Saskatchewans part of the Bakken Oil Formation

FURTHER READING

A coker or coker unit is an oil refinery processing unit that converts the residual oil from the vacuum distillation column or the atmospheric distillation column into low molecular weight hydrocarbon gases, naphtha, light and heavy gas oils, and petroleum coke. The process thermally cracks the long chain hydrocarbon molecules in the residual oil feed into shorter chain molecules.

Fluid catalytic cracking (FCC) is the most important conversion process used in petroleum refineries. It is widely used to convert the high-boiling hydrocarbon fractions of petroleum crude oils to more valuable gasoline, olefinic gases and other products. Cracking of petroleum hydrocarbons was originally done by thermal cracking which has been almost completely replaced by catalytic cracking because it produces more gasoline with a higher octane rating. It also produces byproduct gases that are more olefinic, and hence more valuable, than those produced by thermal cracking.

THAI Commences Engineering of First Commercial Unit

This is a timely reminder that THAI technology is continuing to advance. Petrobank Energy is currently building out a CAPRI/THAI pilot well series to complete the technology validation stage.

This is the first commercial field rollout of the technology that is scaled to be replicated throughout the existing Tarsands.

The Tarsands of course are the world’s largest single resource of oil. It represents thirty to fifty percent of known reserves and likely over fifty percent of unexploited reserves. Present day mining methods can only hope to tap a very small fraction of that resource and may already be approaching optimization.

This is the technology that will release the remaining resource on a scale comparable and even surpassing conventional production recoveries.

This first rollout is permitted for 100,000 barrels per day and can be easily replicated to achieve production levels approaching ten and fifteen million barrels per day and I anticipate supplying a third of final global oil demand that will slacken back to under fifty millions of barrels per day.

Simply put, air is driven down an injection well to ignite a combustion front that expands and follows a horizontally laid recovery well. The combustion operates at high temperature and pressure causing oil reforming and slow reservoir stripping. The process fluid already partially reformed passes through a catalytic sleeve in the production well that gives it another reforming boost. This results in two thousand barrels of fluid production with a fifty percent oil cut. The oil has been upgraded from a source gravity of as low as 8 to hot production oil whose gravity is at around 12 for THAI and perhaps 15 to 17 with CAPRI. It will often be pumpable as is and will require markedly less thinning additions.

Combustion byproducts mainly stay in the reservoir and assist in the process itself. Thus the environmental footprint is a small fraction of any other recovery method. It is almost too good to be true, but it has actually worked very well every step to date.

This project can be expected to be complete over the next four years and while it is been implemented the several pilot wells already been operated will help perfect the technology. This should allow another tenfold jump in production to be planned and financed within a couple of years.

I suspect that the only bottleneck facing this company will be the availability of tradesmen. Time to get your welding ticket.



Vista Projects Wins Contract for Major Petrobank Project
http://www.streetinsider.com/Press+Releases/Vista+Projects+Wins+Contract+for+Major+Petrobank+Project/4426248.html
February 23, 2009 9:01 AM EST

CALGARY, ALBERTA--(Marketwire - Feb. 23, 2009) - Calgary-based engineering firm, Vista Projects Limited, announced today that it has been awarded the contract to provide Front End Engineering Design (FEED) services to Petrobank Energy and Resources Ltd. ("Petrobank") for the well pad and pipeline package of Petrobank's May River project. The northern Alberta venture will be a commercial application of Petrobank's patented THAI(TM) (toe to heel air injection) technology, aiming to produce 10,000 barrels of oil per day with no net water use.

"We are delighted to be working with Petrobank for the May River Whitesand project," said Alex Campbell, founder and principal of Vista Projects. "Vista's long history in heavy oil and bitumen processing and its expertise in providing innovative solutions is a good fit for Petrobank's flagship technology and development."

"Vista Projects was selected because we value their track record for solving complex problems in a cost-efficient manner," said Greg Deuchar, Whitesands Project Manager for Petrobank.

Petrobank's THAI(TM) technology is an innovative process in the extraction of bitumen and production of heavy oil. It utilizes an in-situ combustion technique that injects high-pressure air into the structure that ignites the bitumen causing the air to pressure the thermally cracked oil towards the producing well. Water usage is minimal. The revolutionary system offers substantial environmental and operational cost benefits as compared to competing in-situ SAGD or CSS processes due to the minimal usage of energy and water. The process also requires lower capital investment than steam assisted production of bitumen and produces higher quality produced oil.

The Vista Projects well pad design will be the first of its kind to utilize the THAI(TM) technology on a commercial scale. The project will be constructed in three phases and is scheduled for completion in 2010.

About Vista Projects Limited

Vista Projects Limited is a multi-discipline, technical engineering firm providing solutions to energy firms in Western Canada. While Vista has been active in all aspects of the oil and gas market, it has grown to become a leading engineering firm for thermal energy projects, working on some of the most successful SAGD projects in the Alberta Oil Sands.

THAI(TM) is a registered trademark of Archon Technologies Ltd., a wholly owned subsidiary of Petrobank.FOR FURTHER INFORMATION PLEASE CONTACT: Brookline Public Relations, Inc. Rebecca Eras Media Contact (403) 538-5641 x 108 Fax: (403) 466-4523 (FAX) Email: reras@brooklinepr.com Source: Petrobank Energy and Resources Ltd.

1.7 Trillin Barrels of Oil

This is an excellent article on the Alberta Tar Sands that is also complete in describing the state of the art and includes THAI.

This also states a reserve picture of 1.7 trillion barrels which is likely accurate, particularly with the advent of THAI. That it represents two thirds of the global reserve is daunting and we can expect that to stand up even with fresh discoveries in the deep sea and elsewhere.

THAI appears to produce crude at around $35 per barrel. How that will stand up as experience is gained is today anyone’s guess. I note that SAGD comes in at $60 per barrel in costs and that is naturally more expensive by far since it must produce steam with natural gas at some serious expense. At least the initial running costs are based on supplying compressed air to the toe. I expect to see THAI to swiftly replace SAGD particularly if the ultimate recovery hugely surpasses that of SAGD which is much lower than originally anticipated.

I believe that the method lends itself to significant optimization and that cost of $35 is likely to get a lot lower but not in the initial stage while the fire front is been fully established.

http://www.theengineer.co.uk/Articles/309275/Black+gold+mine.htm

Black gold mine

Published: 08 December 2008 12:20 PM
Source: The Engineer

To its champions it represents a plentiful, secure source of fuel that could wean the West off its addiction to Middle East oil. To its detractors it is an environmental catastrophe in the making.

Despite the strong feelings on both sides, most agree that the oil-sand beneath the soil of Alberta, Canada represents the largest petroleum resource on the planet.

Canada's oil-sand reserve covers an area about twice the size of Wales and already hosts most of the world's oil majors plus a smattering of home-grown specialists. Between them they produce about 1.3 million barrels of crude oil a day from this unpleasant mixture of clay, sand, water and bitumen.

But there is much, much more — an estimated 1.7 trillion barrels more, or two thirds of the world's remaining petroleum reserves. Despite a recent slowdown triggered by the falling price of crude, there are plans to scale up production to 3.5 million barrels a day over the next decade.

Now for the bad news. To get the oil-sand out of the ground and turn it into useful fuel, huge amounts of energy are required and the process pumps vast quantities of CO2 into the air, creating giant lakes of toxic sludge. In comparison, conventional oil production looks like an environmental blessing.

While campaigners would like to see the industry shut down overnight many others, including Geoffrey Maitland, professor of energy at Imperial College London, believe the size and location of the resource makes exploitation inevitable. 'There's three or four times more of this stuff than there is conventional oil,' Maitland told The Engineer. 'If you could extract it today economically then it would transform overnight the balance of power in terms of where the hydrocarbon is.'

Against a backdrop of growing political pressure and falling crude prices (oil-sand is considered uneconomical when crude drops below $70 a barrel) the industry has no choice but to clean up its act. The question is, what can technology do to improve the economic and environmental profile of the dirtiest end of the oil business?

About three quarters of oil-sand activity is concentrated on the reserves that lie closest to the surface, which can be extracted using traditional open-pit mining techniques.The biggest producer, Syncrude Canada (a joint venture between firms including Imperial Oil and ConocoPhillips), generates about 350,000 barrels of oil a day.

At Syncrude's colossal facilities, dubbed Mordor by local activists, the biggest trucks and shovels in the world dig out the oil-sand and place it in enormous crushers before it is sent on huge conveyer belts to gargantuan separation vessels.

As the oil-sand at these facilities is so close to the surface, the mining costs are not high. It is at the separation and refining stage that the big inefficiencies begin to emerge.

To separate the bitumen from the ore huge amounts of water — about three barrels for every barrel of oil produced — are used to float the oil from the tar sand within the separation vessels. Unfortunately, this water also dissolves the clay that forms about 20 per cent of the oil-sand.

The resulting noxious sludge, or tailings, ends up in giant reservoirs where the water and clay can take up to 30 years to separate.

The size of these ponds — Syncrude's 540 million m3 Fort McMurray pond is the second largest dam in the world — is regarded by some as the industry's greatest problem.

A number of groups, including French fuel giant Total, are developing and testing expensive filtration systems that speed up the de-watering process.

However Dr Murray Gray, scientific director of Alberta University's Centre for Oil Sands Innovation, is carrying out fundamental scientific research into extraction methods that dispense with the need for water. The group's work is being funded by Imperial Oil.

'We would like to keep the clay with the sand. Current technology beautifully disperses this material in the water and that creates the tailing problem,' he said.

'We have a project looking at clay minerals in the oil sand and how they are distributed within the ore. We have made progress here and started to visualise ways of getting oil out without moving clays about.
'Another project, which should be ready for pilot testing in a year, involves adding special catalyst materials to crack the bitumen in order to avoid having to use water.'

There are even greater reserves to be found underground. About 80 per cent of Alberta's oil-sand is buried too deep for open mining and to get at these a different process is required.

Current approaches tend to mirror conventional oil extraction techniques by displacing the bitumen to the surface. However, bitumen does not flow like conventional oil. It is up to 10 million times more viscous and to reduce the viscosity to the point where it begins to flow requires the application of a lot of heat.

One method that appears to be gaining in popularity is a so-called in-situ technique known as steam assisted gravity drainage (SAGD). This technique, used by Shell, BP and others, pumps steam down a line at high pressure into the reservoir. After a number of weeks of continuous heating, the bitumen begins to separate from the oil-sand and drips down into a drainage line from where it can be extracted.

It is a novel process and, because some upgrading occurs in-situ, it is a more economical way of getting at oil-sand than surface extraction. But Imperial's Maitland says it is still relatively energy-inefficient and only recovers 10 per cent to 15 per cent of the resource.

'You need to generate a lot of steam at the surface and in generating this steam you generate a lot of C02,' he said. Also, the fraction of heat that goes into heating the oil as opposed to heating the rock is a relatively small percentage (20 per cent) so there's a tremendous loss in efficiency. The overall energy and C02 carbon footprint sums are very poor.'

An alternative to steam is the use of hydrocarbon solvents that require far lower injection volumes than steam and are therefore more energy efficient. One such process, vapour assisted petroleum extraction, is being used at Imperial Oil's Cold Lake oil-sand facility in Alberta.

Another alternative is electrical heating. Dr Bruce McGee, chief executive of E-T Energy, is a pioneer in this area and has developed an electro-thermal heating technique that he claims is the only one that can make oil-sand economical at current crude oil prices.

E-T Energy's electro-thermal dynamic stripping process is deployed by drilling a number of well bores next to the oil reservoir.

Electrodes of varying voltages are put down the bores and the voltage difference causes electricity to flow through the oil-sand and melt the bitumen. The firm is using the technology on its own reserves to produce 1,000 barrels a day and plans to increase production to 10,000 barrels a day by 2010.

McGee claims a number of advantages for his technology. It boasts big thermal efficiencies over SAGD, he said, and claimed that while SAGD only becomes economical when crude oil is $60 or above, his process remains competitive at $22 a barrel.

He added that while a steam plant can take months to set up, his technology takes just two weeks to install and will be producing oil within the year.

Another technical advantage, he claimed, is that the electrodes can be configured to provide feedback on the geometry and suitability of the reservoirs in which they are positioned. While SAGD plants can sometimes work for months before operators discover they are poorly positioned, this technique can respond far more rapidly.

In a similar initiative at an earlier stage of development, a group at Siemens is working on an electromagnetic induction-based system that it believes could be used to complement and, ultimately, replace steam.

Dr Bernd Wacker, the engineer behind the concept, said the idea is to embed a copper cable in the ground then pass a current through it, creating an alternating magnetic field that generates eddy currents, heats the surrounding sand and rapidly reduces the viscosity of the bitumen.

Wacker's team has tested the concept in a sand box at its lab in Erlangen, Germany, and is preparing for a second set of trials in a larger experimental facility. He hopes to begin field trials in Alberta by 2010.
Wacker's vision is that initially the system will be used to complement steam extraction methods, with the inductor running parallel to the steam pipe to provide an additional heating effect.

According to early calculations the process could, he claimed, lead to a 20 per cent improvement in the efficiency of extraction. In the longer term, if the coils were used to replace steam, he believes a 50 per cent improvement could be achieved.

While such techniques could go a long way to achieving the desired economic and environmental goals, Imperial's Maitland believes the oil-sand industry may be barking up the wrong tree.

'It strikes me that there's a greater analogy between tar sands and coal than there is with conventional oil,' he said.

The research carried out into the underground gasification or in-situ processing of coal may be more pertinent to the oil-sand industry.

One promising technique is the toe to heel air injection (THAI) process pioneered by Prof Malcolm Greaves at Bath University.

The key idea of the technique that has already undergone commercial trials with both Orion Oil and Petrobank is that rather than having to use additional energy at the surface to create vapour or steam, some of the in-situ heavy oil is used as a sacrificial fuel.

Air is injected into the reservoir, an underground combustion front is created and the high temperatures, of up to 400ºC, reduce the viscosity of the bitumen.

Because the temperatures are so much higher than those achieved using SAGD, the process also leads to some in-situ cracking and pyrolysis of the bitumen, creating other usable products including methane, CO and, if there is some steam, hydrogen.

A process such as THAI, claimed Maitland, begins to address some of the problems of oil-sand production. 'You use some of the in-situ material as your energy source. You're starting to produce some CO2 in-site, so you could capture some of it and use it to enhance recovery and sequester it within this heavy oil reservoir,' he said.

'It's also doing some in-situ processing so that you're starting to produce at the surface more of what you want.

'We're a million miles away from being very selective and optimised in all of this but I do believe that the road ahead with these heavier hydrocarbon materials is not to produce them the way we've produced conventional oil.'

But in-situ combustion raises big problems of its own. Maitland said there is a pressing need for simulation technology able to accurately predict the effect of lighting huge underground fires.

'You need really good models — you're not just modelling fluid flow but heat and mass transfer over a kilometre-length scale in geological environments that aren't well characterised.'

For instance, because the bitumen is effectively the glue that binds the tar sand together, its removal from deep underground could have serious consequences.

'If you combust this material and flow it, what are you doing to the mechanical properties of a formation?' asked Maitland.

'Can you maintain stable wells? Are you going to get subsidence or major changes to the subsurface?'
With crude prices hovering around $50 a barrel, these are questions to which the industry is going to have to find answers fast.

According to the Canadian Association of Petroleum Producers, investment in oil-sand expected for 2009 had fallen by 20 per cent. Recent decisions by both Shell and Petro-Canada to put planned expansion on hold are just recent examples of how investment is dropping off.

But despite the jitters Maitland, in common with many others, believes the oil-sand industry is here to stay.

'The fact that oil's gone down now is only a temporary thing,' he said. 'I think we will continue to see high oil and gas costs in the future and that the long-term investment in these things will be high.'

'There's been a lot of immediate reaction to the current economic situation and we will see some pulling back but I think in terms of long-term strategy the majors like Shell and BP are committed to seeing the heavier hydrocarbons as strategically very important.

'However, they realise that they've got to produce them in a much cleaner way in the future.'

Maitland added that with Barack Obama due to be sworn in as US president in January, there is also now an added political imperative.

'In order to use these reserves — which are absolutely crucial to the future of the provision of the amount of energy the world needs and security of supply — it must inevitably be done in a cleaner way because it's a matter of when, not if, legislation gets put in place.

'There will not be a window of opportunity to operate in a way where you can be profligate with energy consumption.'

THAI Expansion Approved

This newspaper story is much more revealing than normal corporate pronouncements and is very encouraging. In fact, the technology is advancing rapidly and needs to be sped down the road in view of pending supply difficulties. It is business as usual with the regulators, though.

He is talking about a eighty percent recovery of oil. That is utterly amazing in terms of oil industry practice and experience. All conventional fields with extremely light oil are lucky to approach fifty percent after decades of drainage and stimulation.

I suspect that when the Saudi’s bounced their reserves from 110 billion barrels to 260 billion barrels, it was done by the expedient of merely adding in the total resource including the unrecoverable 60%.

In other words our boy is been very bullish. However, read my lips. This is all done with wells on the world’s single largest oil resource. The initial pilot was three wells. This phase is another three wells to fold in the CAPRI protocol.

They have not given us bench marks but I suspect that the wells will ultimately produce nearly 1,000 barrels per day of 15 to 18 gravity oil from the 8 gravity bitumen. Now you too know what to watch for.

The next phase now entering permitting is for production levels of 100,000 barrels, if I recall correctly. That can be replicated a hundred times without putting a dent in the ultimate resource, particularly if recovery approaches eighty percent.

You do get a sense of the slowness of regulatory process in these matters. If we do have a supply emergency, then fast tracking this all is a matter of putting a thousand drills to work tomorrow morning. It would still take time to ramp up even then but it would be predictable also.

The second article is now giving us numbers. A barrel of production is capitalizing at $10,000. In other words, if the operating net is a mere $10.00 per barrel, then it is paid of in three years, which is very good by industry standards particularly when you do not have to find the oil. Even at $50.00 per barrel, I suspect we have a $15.00 net. You can do the rest of the math.

Petrobank wins approval for heavy-oil project expansion

ERCB rejects objections from two local groups

Dave Cooper, The Edmonton Journal

Published: 2:34 am

An Alberta petroleum company using a revolutionary process to extract underground bitumen has finally won ERCB approval for an expansion to its heavy oil pilot project south of Fort McMurray.

Petrobank Energy's Whitesands site had three insitu wells demonstrating the THAI (toe-to-heel air injection) process, and wanted to add an additional three to further study the CAPRI process which uses a catalyst between the inner and outer liners of the slotted horizontal production well.

"We would have liked to have those three wells on stream so we could have more information for our next application" for a nearby 10,000-barrel-a-day project, said Chris Bloomer, a vice-president of Petrobank.

The Energy Resources Conservation Board rejected the "broad letters of objection" from two local groups, said Petrobank.

In a release, the firm said "the delay in receiving the decision was not related to the technical merits of the application. Petrobank views this decision as a validation of our values and strategy to consult, rather than compromise the process by making extraordinary financial payments to intervening parties to facilitate the withdrawal of objections and thereby shortening the regulatory process."

The ERCB dismissed objections by the Beaver Lake Cree Nation and the Métis Nation of Alberta - Local 1935.

Bloomer would not comment further on the release, but "you could say it has added a year to what is really a development project."

He said THAI could replace the current SAGD (steam assisted gravity drainage) and CSS (cyclic steam stimulation) systems used to extract bitumen that is too deep to mine. But some in the oil industry say THAI won't be a significant technology for another 20 years.

"I think that's unfair. If you take a look at the state of the technology today, being able to do simulations and monitoring, and knowing what we know about the reservoirs, the tools we can use are light-years away from what was available in the past," said Bloomer. "I think they are taking a very parochial view, that it took SAGD 20 years so it's going to take any other technology 20 years. We think this is a technology that has to proceed."

Earlier this month, Petrobank signed a royalty and joint venture deal with True Energy Trust to apply THAI technology to two test wells at a heavy oil property in Saskatchewan.

Bloomer said THAI is applicable to many heavy oil fields around the world. The process offers high recovery rates -- up to 80 per cent of the oil in place compared with 20 to 50 per cent for SAGD. It also uses little natural gas and water. In THAI, air is pumped under pressure into the toe of the reservoir, creating natural combustion to heat the cold heavy oil, which flows into horizontal slotted pipes.

dcooper@thejournal.canwest.com

Oilsands regulatory delay frustrates Petrobank boss

Holdup leaves CEO fuming

Dan Healing, Calgary Herald

Published: Saturday, November 29, 2008

The head of a Calgary company with a promising technology to recover bitumen from the oilsands says he is regretting choosing to build in Alberta after an 18-month wait to obtain regulatory approval for a three-well expansion.

"It's cost us time. It's cost us a world of opportunity," said John Wright, president and chief executive of Petrobank Energy and Resources Ltd.,which owns the toe-to-heel air injection or THAI technology that uses in-situ combustion to enhance recovery of bitumen and heavy oil.

"We think our technology is going to change the way heavy oil is extracted by reducing the amount of fresh water that's used, eliminating the need for gas and cutting the greenhouse gas emissions in half, so why would we ever want to see that delayed?

"If we'd known it was going to be this long an approval process in Alberta, we would have thought twice about doing our first project here."

Petrobank announced late Thursday it had received copies of letters from the regulator, the Alberta Energy Resources Conservation Board, to the Beaver Lake Cree Nation and Metis Nation of Alberta--Local 1935 indicating that their objections to Petrobank's project had been dismissed.

Both parties indicated they traditionally used the area 120 kilo-metres south of Fort McMurray for hunting, trapping and fishing, but the ERCB wrote that neither had proven those claims and therefore would not be granted standing at a hearing.

opportunity.See of expansion plans has "cost us a world of "

The decisions clear the way for approval of the project.

ERCB spokesman Bob Curran defended the process, noting the public often loudly accuses the regulator of rubber-stamping every oil project and the companies complain more quietly that the process takes too long.

"We hear it from both sides all the time," he said. "It just goes to show we have a thorough process and we make no apologies for that."

Curran added that although the objectors can appeal the ERCB decision within 30 days, the licensing of the project will not face further delays.

Drew Mildon, a Victoria lawyer who represents the Beaver Lake band, said it hasn't been decided if the decision will be appealed.

"It's not unexpected," he said. "I've seen the approach the ERCB has taken to First Nations complaints in the past."

He criticized the ERCB for not considering cumulative effects and for its insistence that complaints are"very site specific,"noting that development affects the forest and therefore the natives' treaty rights.
The process left Wright vexed and vowing to put all of the correspondence related to the application on the Petrobank website.

"If you read those letters," he said, "they have actually stated the parties that have written these general objections . . . don't have standing. (They're saying) you can't make a general claim that anything happening anywhere within 100 miles of you is going to affect your future enjoyment and your ancestral use rights."

He added the dissenting par-ties had offered to drop their objections in return for compensation from Petrobank.

"That's not the way we do business,"said Wright. "We're not going to buy someone's approval.

Curran said companies are allowed to compensate parties affected by their development plans and those arrangements are not part of the ERCB's mandate.

Gary Leach, executive director of the Small Explorers & Producers Association of Canada, said 18 months is too long to wait for approval of a straightforward project.

"That's the kind of delay you'd expect with a very complicated, significant project with scores of people with interests, and lots of studies and environmental assessments. For a relatively modest project to drill a couple of wells, I'm surprised it would take that long. It's probably excessive."

Leach added there is growing concern among oil and gas developers about interveners in regulatory matters who object (and have their expenses covered by the company if they are granted standing) for the sole purpose of delaying development.

"We're not looking for a relaxation of standards, but there are points in the process where there is potential for abuse by people who aren't legitimately affected and use the rules as they stand to stop resource development."

David Pryce, vice-president of western Canadian operations for the Canadian Association of Petroleum Producers, said slower regulatory processes create uncertainty and delays that result in additional cost for businesses.

"I think it is a concern," he said. "We've seen the approval process kind of stretch out around these sorts of things."

Both CAPP and SEPAC are working with the government on regulatory reform.

Wright said Petrobank had wanted to wait until it drilled the three wells before seeking approval for its planned 100,000-barrel-per-day May River commercial project, but it has moved that forward while waiting and now expects to file its application within days or weeks.

The project is to be centred within two kilometres of the demonstration site and built in phases, at a cost of about $150 million for each 10,000 to 15,000 bpd phase.

He said May River will reach 100,000 bpd by drilling 100 to 150 wells within three to four years. The resource is big enough to produce for 25 to 30 years.

Petrobank has drilled three wells at Whitesands to demonstrate its THAI technology. The new wells are intended to further demonstrate its CAPRI technology--which employs chemical catalysts to further improve the quality of the oil --as well as a revised down-hole completion design and longer well lengths.

The company recently licensed its technology to True Energy Trust in return for an initial 50 per cent interest in a portion of its Kerrobert, Sask., heavy oil pool.

In addition, Petrobank will earn a 10 per cent share of all production on the True lands following a threshold reserve recovery.

Late last year, Petrobank licensed the technology to Duvernay Oil Corp., which was then sold to Shell Canada.

True THAI

This is an important milestone in the emergence of THAI technology. It is been applied to an ordinary heavy oil field with a fairly typical thickness. The results here should go a long way in the development of similar fields elsewhere. The tarsands have unique features that need to be clarified when applied to more conventional heavy oil fields.

You can bet that the gravity will be quite high for this field and that THAI will be sufficient in itself to free the oil and upgrade it enough to pump.

The sooner we know how to apply this technology the better. We still need to find several millions of barrels of oil production ASAP.


CALGARY _ Petrobank Energy and Resources Ltd. (TSX:PBG) and True Energy Trust (TSX:TUI.UN) say they plan to develop a heavy oil resource in Saskatchewan together using Petrobank´s patented oil extraction technology.

Under an agreement announced Friday, Calgary-based Petrobank will hold a 50 per cent interest in three sections of True´s Kerrobert Mannville oil pool.

Petrobank d an oil recovery method called Toe to Heel Air Injection, or THAI, in which air is pumped into hard-to-access reservoirs. The process uses the air and the bitumen itself to heat the thick, tarry substance and make it thin enough to flow to the surface.Unlike other oil extraction technology, the THAI process does not require water or large quantities of natural gas to keep the operations going.

Petrobank and True aim to developed a two-well project to demonstrate the THAI technology in the more than 10-metre thick conventional oil reservoir.

Petrobank will also earn a 10 per cent technology royalty on True´s share of THAI production following a threshold reserve recovery.

"Petrobank is excited about the opportunity to partner with True and bring the THAI technology to the conventional heavy oil resource base in Saskatchewan" the company said in a statement.

"This is indeed a welcome announcement, particularly in these uncertain economic times, and a vote of confidence in the future of Saskatchewan´s energy sector," Saskatchewan Premier Brad Wall stated.

Malcolm Greave’s THAI toe and heel air injection heats up

It is rare to see a professor come out and cheerlead a new technology, even if he is the father of the process. In this case it seems a well earned right. THAI or toe and heel air injection is proving to be far better than anticipated and making the projected improvements much more probable.

This article was published a couple of months ago and this last week we have also seen the THAI story been told on the national news. I have been keeping a watchful brief on the pilot test from before it got funded. This is actually a remarkable discovery, and its real success infield is wonderful. Personal experience kept me cautious until I saw the early production results. We all can now throw that caution to the wind.

I believe that this will also access huge reserves of conventional oil that is now classified as dead oil. Of course a lot of those fields will have to be dried out. However, any sandstone based reservoir that is reasonably thick should be exploitable. You will notice particularly that they are quoting an amazing 70% to 80% recovery and in well catalytic upgrading to as high as 26 api. Of course, they are now getting a bit over the top. However, I certainly can anticipate resources for which these levels may be possible.

In fact, I suspect that a lot of oil companies will be rather sorry that they ever used water floods at all. For the layman, natural flow will deliver up to perhaps 40% of in place oil. The truth is that this is more like 30 to 35%. Water floods will sweep out maybe another 15%. This means that generally, half of the original oil remains behind. And it is rather unlikely that a wet formation can be made to work with this method, although I reserve the right to be surprised.

The power of this method comes from the fact that the air is under pressure permitting the development of a 600 degree burn zone. This is hot enough to encourage reforming of the oil, to say nothing about its liquefaction. On top of that the combustion product is CO2, CO and steam (H2O) as well as entrained nitrogen. All these gases except H2O dissolve into the oil itself helping to improve its viscosity. These gases also dissolve into the water helping to break the oil free of the sand itself.

The only escape for all this heat is with the production fluid itself or through a very slow leaking into the surrounding non porous sediments. This is also true of the production gases which will tend to penetrate the formation ahead of the burn front speeding the process up.

I expect that it will be possible to set up a 100 well burn front within the formation that will obviate any need for pillars or untreated zones between burns. It also seems that as the burn front gets a fair distance down the formation, it will be good practice to place additional injection wells at the burn front and seal the older wells.

In fact there is little reason not attempt to treat one hundred percent of the formation with a closely managed burn front that is moved slowly along with additional production and injection wells placed as needed.

I am particularly encouraged with the experiments starting with using 3d seismic mapping to follow the location of the burn front. If this works, then it will be possible to almost micro manage the system.

The real payoff with this system is that it uses drilling industry resources which are sufficient and fully in place in Alberta to swiftly add a million new barrels of production every year. Each well pair will pump out 1000 barrels per day. With air injection and a full sand handling system, they are not cheap, but they are not unusual and will certainly meet the industry standard of a three year payback with absolutely no discovery risk.

Since this all works best on oil that is likely below the mining zone, we have likely added all of Canada’s oil sands to the world’s oil inventory. I believe that this will easily exceed one trillion barrels, though up to now measurement has never been much of a priority. I also remember seeing a map once in which the tar sands were shown to extend far north along the McKenzie Valley. I think every one just gave up once they found a trillion. I suspect accurate measurement just became important again.

Toe-to-Heel Air Injection (THAI™) System

Published Thu, 2007-11-29 16:08 Energy

A new method developed in Britain over the past 17 years for extracting oil is now at the forefront of plans to exploit a massive heavy oilfield in Canada.

Duvernay Petroleum is to use the revolutionary Toe-to-Heel Air Injection (THAI™) system developed at the University of Bath at its site at Peace River in Alberta, Canada.

Unlike conventional light oil, heavy oil is very viscous, like syrup, or even solid in its natural state underground, making it very difficult to extract. But heavy oil reserves that could keep the planet’s oil-dependent economy going for a hundred years lie beneath the surface in many countries, especially in Canada.

Although heavy oil extraction has steadily increased over the last ten years, the processes used are very energy intensive, especially of natural gas and water. But the THAI™ system is more efficient, and this, and the increasing cost of conventional light oil, could lead to the widespread exploitation of heavy oil.

“The world needs to switch to cleaner ways of using energy such as fuel cells,” said Professor Malcolm Greaves, who developed the THAI™ process.

“But we are decades away from creating a full-blown hydrogen economy, and until then we need oil and gas to run our economies.

“Conventional light oil such as that in the North Sea or Saudi Arabia is running out and getting more expensive to extract.

“That’s why the pressure is on to find an efficient way of extracting heavy oil.”

THAI™ uses a system where air is injected into the oil deposit down a vertical well and is ignited. The heat generated in the reservoir reduces the viscosity of the heavy oil, allowing it to drain into a second, horizontal well from where it rises to the surface.

THAI™ is very efficient, recovering about 70 to 80 per cent of the oil, compared to only 10 to 40 per cent using other technologies.

Duvernay Petroleum’s heavy oil field in Peace River contains 100 million barrels and this will be a first test of THAI™ on heavy oil, for which THAI™ was originally developed. Duvernay Petroleum has signed a contract with the Canadian firm Petrobank, which owns THAI™, to use the process.

The THAI™ process was first used by Petrobank at its Christina Lake site in the Athabasca Oil Sands, Canada, in June 2006 in a pilot operation which is currently producing 3,000 barrels of oil a day. This was on deposits of bitumen - similar to the surface coating of roads - rather than heavy oil.

Petrobank is applying for permission to expand this to 10,000 barrels a day though there is a potential for this to rise to 100,000.

The 50,000 acre site owned by Petrobank contains an estimated 2.6 billion barrels of bitumen. The Athabasca Oil Sands region is the single largest petroleum deposit on earth, bigger than that of Saudi Arabia.

Professor Greaves, of the University’s Department of Chemical Engineering, said: “When the Canadian engineers at the Christina Lake site turned on the new system, in three separate sections, it worked amazingly well and oil is being produced at twice the amount that they thought could be extracted.

“It’s been quite a struggle to get the invention from an idea to a prototype and into use, over the last 17 years. For most of the time people weren’t very interested because heavy oil was so much more difficult and expensive to produce than conventional light oil.

“But with light oil now hitting around 100 dollars a barrel, it’s economic to think of using heavy oil, especially since THAI™ can produce oil for less than 10 dollars a barrel.

“We’ve seen this project go from something that many people said would not work into something we can have confidence in, all in the space of the last 18 months.”

Professor Greaves, who was previously Assistant Professor at the University of Saskatchewan in Canada, and who also worked with Shell and ICI in the UK, is looking at making THAI™ even more efficient using a catalyst add-on process called CAPRI™.

This process was also developed by Professor Greaves’ team at Bath and is intended to turn heavy oil into light while still in the reservoir underground. The CAPRI™ research has recently been awarded funding of £800,000 from Engineering and Physical Sciences Research Council, including £60,000 from Petrobank. The project collaborators are Dr Sean Rigby, from the Department of Chemical Engineering at Bath, and Dr Joe Wood of the University of Birmingham.

Source: University of Bath

Major THAI Expansion

Today, I am going to share with you an extract just published by PetroBank Energy (PBG.TO). The reason is that this company who is pioneering THAI production has just decided to really reach in terms of their expansion. Obviously they are very happy with results to the present and production bottlenecks have been eliminated.

The most important thing that this all tells us is that they can go to 100,000 barrels per day very easily. This means that the step to 1 million barrels per day is just as easy and the next several million barrels per day is very feasible. This implies that Canada' s two trillion barrels of heavy oil reserves will soon become measured reserves.

More importantly, the oil resource requires a negligible amount of input energy unlike the mined surface deposits. In fact the technique will likely find its way into conventional oil fields because of its ability to reform oil in place and thus mobilize it. I am still a little amazed that this is possible.

There are huge amounts of conventional oil in place that was unrecoverable equal to all the oil ever recovered. This may access a lot of it.

So while we are surely sweating the developing production shortfall faced globally, this is a true light at the end of the tunnel for the long interim we need to bring alternative sources on line.

Heavy Oil Business Unit

Whitesands

Recent operations at the Whitesands site have focused on the installation of the new sand-handling system which became operational for all three wells late in December 2007. This system has increased on-stream time and enhanced our ability to manage produced sand and ultimately flow the wells to their target capacity. In conjunction with the new sand-handling system, upgrade modifications to other plant operations were made to facilitate the addition of the planned three well expansion. Another key upgrade was further enhancement to our H2S treating facilities, which are installed and ready to operate, however regulatory approval to operate this system has been delayed and is now not expected until early February. This delay has limited our ability to increase air injection and therefore increase production levels in the short term.

As previously discussed, our three well expansion project is also waiting on regulatory approval which is delaying the drilling of the next three THAI(TM)/CAPRI(TM) wells. Because of this, we have decided to drill at least one additional well on the current plant footprint which will be our first THAI(TM)/CAPRI(TM) well. As this well is located on the existing plant footprint, the regulatory process is more streamlined. This will also enable us to advance the testing of our CAPRI(TM) completion design and our revised slotted liner designed for improved downhole sand control. In addition, we can start producing from this well sooner, using the existing combustion zone, which should allow us to avoid the pre-ignition-heating cycle. Advancing this well provides an opportunity for continued optimization of our project design and reduction of execution times for future projects.

In December 2007, we also completed a 4D-seismic survey over the current project site, which we believe will provide valuable information on the morphology of the combustion zone. We have also completed five additional stratigraphic evaluation wells, the results of which will be included in the updated resource evaluation being conducted by our independent reserve auditors. We plan to drill up to an additional 23 oil sands exploration wells during our 2008 drilling program.

May River

Our earlier plan at the Whitesands site was to have filed a 10,000 barrel per day project application by the end of 2007. This plan has been modified as we have enhanced our process design to allow for a larger central facility with ultimate capacity for 100,000 barrels per day, as well as other facilities improvements based on data from our current operations. This new project will be known as May River. The central facility design will lower the overall environmental footprint of the project and requires a different surface location than previously planned. We now expect to file the first phase application for the initial ten to fifteen thousand barrel per day stage of the project by mid-2008, which will include pre-development for the larger overall development. This approval will require additional environmental fieldwork to accommodate the larger initial scope of May River.

To facilitate the application process for the overall project design, we have released our public disclosure document ("PDD") for the May River project describing our 100,000 barrel per day THAI(TM) development plans for the Whitesands leases. The PDD is the first step in the public consultation process and is a key aspect of the overall project approval process. The PDD will allow us to consult on our full development plan, thereby potentially shortening the overall approval process, rather than undertaking a detailed public consultation for each separate phase. The rationale for initiating this full-scale development plan with a ten to fifteen thousand barrel per day initial stage, is that while the overall project will require a comprehensive environmental impact assessment ("EIA"), the first phase will only require a localized environmental assessment that we can commence immediately. We will also initiate the full scale EIA in the first quarter of 2008.