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.

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

http://1.bp.blogspot.com/_VyTCyizqrHs/SNCbC8Vrd0I/AAAAAAAABT4/PVWBtBVlaNk/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.

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