Background

Engine oils and lubricants need to provide a good layer thickness by having sufficient viscosity, without giving significant frictional effects from the viscosity being too high. The ideal viscosity range of an engine oil is therefore quite narrow.
Temperature Dependent Viscosity
Mineral Oils

Mineral oils generally have a very temperature dependent viscosity and so need to be modified.
Viscostatic Oils

Viscostatic oils (where viscosity is entirely independent of temperature) can be created by adding polymeric compounds that open up their conformation at higher temperatures. When heated, the increase of viscosity of the polymer additive counteracts the fall in viscosity of the oil.
Effect Of Viscosity Variations

In this experiment, we can measure the viscosity of the oil at all working temperatures and determine whether it will be sufficiently ‘thin’ when cold, for say, an engine to start, or sufficiently ‘thick’ to lubricate well when hot.
Interpretation Of Viscosity Versus Temperature

The results show that Sample A’s low temperature viscosity is much higher than that of Sample B and therefore it will be much more difficult to circulate in an engine on start-up. Conversely, Sample B showed a higher viscosity than Sample A when hot, indicating that it would give more lubrication when up to temperature.

Figure 1. Variation in viscosity over a range of temperatures.
Conclusion

The temperature dependence of a lubricant is one of the most important factors in determining its efficacy. Using a Bohlin rheometer, the viscosity can be accurately measured over a wide temperature range. Results are also referenced against nationally recognised standards.
Measurement Conditions

Samples


Oils and lubricants

Geometry


Parallel Plate 40 mm with the Extended Temperature Cell

Single Shear – Shear Rate


10s-1

Gap


1 mm

Temperature Ramp


Range of interest (eg.-20ºC – 90ºC at 3º/min)





Source: Petrochemicals Application Note by Malvern Instruments.

Background

LaserNet Fines® was developed by Lockheed Martin Tactical Defense Systems in cooperation with the Naval Research Laboratory for the Office of Naval Research on its Accelerated Capabilities Initiative for Condition-Based Maintenance.

Introduction

Machine condition monitoring based on oil analysis has become an accepted practice in any well run maintenance management program. With prior knowledge of the wear metals and contaminants present in a lubricating system, it may be determined if that equipment is operating properly or if preventive maintenance is required. LaserNet Fines® combines the standard oil analysis techniques of particle counting and shape classification into a single analytical instrument. Lockheed Martin Tactical Defense Systems and Naval Research Laboratory combined space age imaging technology and neural net shape classification into the development of LaserNet Fines®. LaserNet Fines® can be used as a stand-alone analytical instrument, or in conjunction with a full service oil analysis program. Figure 1. LaserNet Fines Particle Counter LaserNet Fines® processes and stores thousands of images to obtain good counting statistics. Particles are sized directly and put into size bins of 4 - 15 µm. 15 - 25 µm. 25 - 50 µm and greater than 50 µm. The direct imaging capability of this instrument eliminates the need for calibration with a test dust, the exact particle size distribution of which itself may be questionable. Air bubbles are ignored and the laser is powerful enough to process heavily sooted (black) oils. Figure 2. Sample data output screen with particle counts and number of particles according to wear mode (cutting, sliding fatigue and oxides) Particle Shape Classifier The second capability of this instrument is shape recognition of all particles greater than 20 µm by using a neural network. An algorithm is used to sort particles into 4 categories, "cutting, fatigue, severe sliding and oxides". The shape recognition software also does a test for circularity so that bubbles and droplets are eliminated. Figure 3. Sample data particle map output screen. Particles can be selected by wear mode and highlighted for additional size and shape data Operation A powerful laser transmits a light pulse through a thin (approximately 90 µm thick) cell in which slowly flowing sample is sandwiched between two glass plates. Using magnifying optics, an image of the sample is captured by a CCD video camera and stored in computer memory. Each image is processed with a raster scan analysis to identify individual objects. The objects are then analyzed for maximum size and several shape characteristics which are used to classify particles into mechanical wear classes. Each laser pulse provides a single image frame to be analyzed, and the results of thousands of frames are combined for a complete record of the sample under study. Figure 4. Sample data output screen with capability to show trends by wear mode and/or particle size ranges Features · Small size and user friendly interface for shipboard or field deployment · Algorithms to perform shape analysis, wear particle identification and machine condition assessment. · Particles counted are greater than 5 µm · Particles greater than 20 µm are classed by neural network as "cutting, fatigue, severe sliding and oxides" · Touch screen and LCD user interface · Provides ISO 4406 cleanliness rating · Provides NAS 1638 cleanliness rating · Automatic adjustment for fluid darkness · Built-in data-base for machine condition trending Figure 5. LaserNet Fines® Military (LNF-M) version with built-in computer

Background

Hydrogenated nitrile rubber (HNBR) has an intriguing combination of properties. Like other elastomers, the material has high tensile strength, low permanent set, very good abrasion resistance and high elasticity. But in HNBR, these are complemented by good stability towards thermal ageing and better properties at low temperatures compared to other heat- and oil-resistant elastomers. This combination of properties is opening up a broad range of applications for the materials, mainly in the automotive industry.

HNBR is replacing polychloroprene in timing belts for cars, figure 1, thanks to its good static and dynamic properties at operation temperatures and good retention of properties under continuous heat exposure. In addition, new grades of material with improved low temperature flexibility are extending the HNBR service temperature range, allowing new applications in seals and mounts, for example. HNBR is also proving useful in the seals and mouldings of car engines that run on new fuels such as rapeseed oil methyl ester.

Figure 1. A HNBR timing belt.

There are several other key properties of HNBR that make it useful in automotive applications. These include good viscoelastic properties in HNBR vulcanisates, a wide service temperature range from -40°C to +150°C, resistance to fluids of various chemical compositions and excellent resistance to strongly alkaline and aggressive fluids.
What is HNBR?

The material itself is a derivative of nitrile rubber, which is hydrogenated in solution using precious metal catalysts. The nitrile groups are unaffected during the process, but the carbon-carbon double bonds in nitrile rubber are converted into more stable single bonds. Different grades can be made by precise control of the proportion of unconverted double bonds in the material - 10% is considered to be an upper limit, but grades containing 4-8% (partially hydrogenated) or virtually no double bonds (fully hydrogenated) are used in most cases. Partially hydrogenated materials can be cross-linked using both sulphur and peroxide cure systems, and the fully hydrogenated grades can be cross-linked with peroxides. This further expands the range of grades and opens up more applications for these HNBR materials.
The Market for HNBR

Although HNBR is available in a wide range of grades for a range of applications, it is a speciality engineering elastomer and so its market volume is relatively small. The overall consumption of synthetic rubber in technical rubber goods in Western Europe is about 1.5 million tonnes, compared to HNBR consumption of 1,750 tonnes in 1995. However, in-house studies at Bayer show that things are growing rapidly, and the market volume by the year 2000 could well be more than 3000 tonnes.
Applications
Timing Belts

Belts, seals and hoses are among the most important applications of HNBR, and the automotive industry is the most powerful driving force in the further expansion of these materials’ use. Automotive belts - mainly timing belts - currently account for more than 50% of HNBR use in Europe. HNBR materials allow manufacturers to produce belts with a lifetime of more than 100,000km, and could help stretch this to as much as 200,OOOkm. By 2000, it is believed that the vast majority of timing belts will be made from HNBR rather than traditional chloroprene.
Seals

Seal applications include air conditioner O-rings, shock absorber seals, power steering seals, water pump seals and in-tank seals. HNBR is particularly popular for these applications because of the materials’ resistance to fluids in general and specifically to aggressive fluids, plus their wide service temperature properties, including:

· a high standard of dynamic and mechanical properties, to ensure long term operation

· resistance to theremo-oxidative ageing, to withstand high under-bonnet temperatures

· safety, serviceability and environmental acceptability

· good cost/performance ratio.

Thanks to advances in HNBR materials, these can all be achieved.
Properties
Mechanical Properties

The mechanical properties of vulcanisates based on HNBR are extremely good. They generally have high tensile strength at room temperature and also at service temperatures of 100-140°C. In addition, suitably compounded HNBR vulcanisates are at least as resistant to crack growth as the vulcanisates based on conventional CR elastomers.
Thermo-Oxidative Properties

HNBR is commonly called the ‘150 degree elastomer’ owing to its resistance to theremo-oxidative ageing. A vulcanisate crosslinked in a standard manner with peroxides can achieve a service life corresponding to a long-term exposure of 1000 hours at 150°C. Sulphur-crosslinked vulcanisates can achieve 1000 hours at 130°C. These values are much higher than for CR, and so HNBR is more suitable for withstanding the relatively high temperatures in the engine compartment, which can reach 135-140°C in the timing belt area.
Cost Benefits of HNBR

Such performance improvements have to be paid for, and in terms of actual materials, HNBR is more expensive than conventional polychloroprene. With regard to the polymer content in a timing belt, it is assumed that direct replacement of CR with HNBR in a timing belt increases costs an estimated 5.7 times, and even tailoring the belt material for HNBR (e.g. accounting for the difference in specific gravities) and formulating with an elastomer content of about 55% gives a cost increase of around 4.2 times. However, other factors swing the equation in the favour of HNBR. For example, the relative cost of the non-elastomer materials to the elastomer content in the timing belt is reduced when CR is replaced by HNBR. So, the finished belt based on HNBR will cost only 2 to 3 times that of a CR belt. In addition, thanks to the enhanced properties of HNBR, the service life of belts at 110°C can be increased by a factor of 5.5 when standard CR is replaced by HNBR and by a factor of 2.3 in comparison with an optimised CR formulation. The advantage of using HNBR is even more marked at higher temperatures. At 130°C the service life of HNBR is about 12 times that of even the improved CR grade.

HNBR also brings greater safety. If a timing belt breaks in certain types of car engine, valve control can fail and cause engine locking. So the belt must he made of strong, reliable materials. HNBR belts give a longer service life. Belts are normally replaced in car engines before there are any signs of defects, and using HNBR belts should contribute to the general objective of extending the interval between replacements from 100,000km to 150,000km.
Industry Demands

New grades of HNBR materials are being produced to give an extended service temperature range, as the automotive industry is making ever-stricter demands to improve reliability and performance. Specifications frequently include properties that are very difficult to optimise simultaneously, such as excellent heat ageing stability, good oil resistance and good low temperature flexibility Typically, oil-resistant elastomers have relatively poor low temperature flexibility, and normal HNBR vulcanisates are no different, having a glass transition temperature of -30°C or above. This means that the materials are often unsuitable for static seals and sometimes also dynamic seals.

Bayer has managed to lower the glass transition temperature in some of its HNBR materials, sold under the Therban name, by as much as 10°C through structural modifications to the main polymer chain. HNBR grades with these properties have been on the market for some time now. As far as the he ageing stability is concerned, the improved grade Therban XN535C is comparable with standard grades, as it has a similar double bond content. However, it differs in its stress/strain characteristic. With a comparable vulcanisate composition, the modulus is lower at equal strain. The improvement in compression set is drastic. With conventional HNBR the values at -10°C are very high, but with Therban XN535C the values of around 30% are still acceptable for many purposes. The new grade al exhibits good oil resistance, comparable with NBR.
Challenges from New Fuels

Clearly, HNBR grades with a reduced glass transition temperature are suitable materials for being used in motor vehicles under the extreme climatic conditions experienced in Northern Europe, Asia and North America. At the same time, they can withstand the high operating temperatures required for economic running of an engine. The engine environment and the climate conditions are not the only challenges being faced by HNBR materials in the automotive industry. In recent years, rapeseed oil methyl ester (RME) has been introduced on to the fuel market as a supplement or alternative to diesel-powered vehicles. This fuel is a more aggressive substance in terms of corrosion, and so the fuel filters and other parts must be changed more frequently. RME also tends to leak into the lubricating oils more than traditional fuels.

Of all the elastomers available for use in seals and gaskets to withstand RME, only HNBR exhibits all the necessary properties while being cheap enough. It has good resistance to RME, has the desired mechanical properties and does not decompose at elevated temperatures. Vehicle manufacturers are already realising the benefits of using HNBR and the elastomer has been approved for use in peripheral parts of diesel / RME engines, such as tanks and piping.
The Future

Further improvements in the properties of HNBR grades will provide even more scope for the use of these materials in the automotive and other industries. Car timing belts are just one example of an application in which the materials’ excellent properties have led to their selection over established materials. Many more such examples can be expected in the future.

Background

Bodycote Materials Testing is the world’s leading supplier of independent sub-contract testing. In the environmental field, we have two established laboratories in the U.K. and are now offering commercial testing from our laboratory in Shotton, North Wales. The Shotton Laboratory currently supports Corus Colors, the UK’s largest coated steel strip processor and has the experienced staff and equipment to undertake a wide range of environmental tests.
Testing Equipment Available at the Shotton Laboratory

The equipment inventory includes: -

· ICP Optical Emission Spectrometers

· Industrial Microwave

· Photometric COD Analyser

· BOD Analyser

· Photometric Ammoniacal Nitrogen Analyser

· pH Meters

· Conductivity Meters

· Gravimetric and Titrimetric Methods

· Infra-Red Oil in Water Analyser
Testing Procedures Available at the Shotton Laboratory

This enables the Bodycote laboratory to carry out a wide range of commonly required tests including environmental effluent monitoring, groundwater and borehole analysis. The range of specific tests available includes: -

· Metals in Solution

· COD

· BOD

· Ammoniacal Nitrogen

· pH

· Conductivity

· Suspended Solids

· Moisture Content

In addition to the above, a wide range of classical wet chemistry techniques are available within the laboratory enabling the testing of, for example, Nitrates and Sulphates.
Ananlytical / Environmental Laboratories at Glasgow

The existing Bodycote Analytical (Environmental) laboratory in Glasgow offers a vast range of testing and consultancy services, and clients who may have a requirement for services not offered by the local laboratory will be contacted by an expert and guided through the testing process.
Bodycote’s Accredited Testing Facilities

Bodycote’s laboratories are accredited by the United Kingdom Accreditation Service (UKAS), which provides assurance of the quality systems in place. The assessment standard is ISO 17025, which is an internationally recognised quality assurance standard, compatible with the ISO 9000 series.
Additional Services to Customers

Bodycote management and technical staff alike pride ourselves on our customer service ethic, and our belief is that understanding and satisfying our customer’s needs is paramount. Routine samples are typically processed and reported within 48 hours of receipt. Also, our laboratory management computer system ensures standardised and efficient reporting, and allows the transmission of certificates by e-mail if required.

Background

Castor oil (or ricinus oil) is a nonvolatile fatty oil extracted from plants. It has been used for many years as a purgative, i.e. a material that induces vomiting. It has the advantage over other mineral oils that it is a renewable resource, is bio-degradable and eco-friendly.
Source

Castor oil comes from the seeds of the castor bean. It is extracted by either pressing or solvent extraction.

The beans themselves are produced primarily in India and Brazil and to a lesser extent China.
Characteristics

· Castor oil consists almost entirely of the triglycerides ricinoleic acid

· It is ranges in colour from colourless to greenish.

· It is a viscous liquid

· Non-drying

· It has a faint but characteristic odour

· It has a slightly acrid taste and leaves a nauseating after taste.

· Many derivatives can be produced which have a similar chemical composition to petroleum based oils
Derivatives
Blown Castor Oil

Blown Castor oil is a derivative that has a higher viscosity and specific gravity compared to natural castor oil. These properties are induced by bubbling air thorough it at elevated temperatures. Its main use is as a plasticiser for inks, lacquers and adhesives.
Hydrogenated Castor Oil

Hydrogenated castor oil (HCO) or castor wax is a hard, brittle wax that is insoluble. It is produced by adding hydrogen in the presence of a nickel catalyst. It is mainly used for coatings and greases where resistance to moisture, oils and other petrochemical products is required.
Applications

There are many uses for castor oil and its derivatives. Some of these include:

· Plastics

· Textiles and textile finishing materials

· Paints and varnishes

· Cosmetics and hair oils

· Inks

· Adhesives.

· Synthetic resins

· Fibres

· Drying oils

· Plasticisers

· Fungistatic (fungus-growth-inhibiting) compounds

· Embalming fluid

· Soaps

· Lubricants, greases and hydraulic fluids

· Dyeing aids

Background

Hardening of tool steel falls into various categories i.e. water hardening, oil hardening, air hardening and special interrupted quench techniques. Some examples of tool steels requiring different quenching techniques are as follows:

· Water Hardening Tool Steels

· Oil Hardening Tool Steels

· Air Hardening Tool Steels

· Air Hardening Hot Work Steels of the H13 Type
Water Hardening Tool Steels

The water hardening types of tool steel are covered by AS1239 ‘W’ grades and these are shallow hardening. These steels contain around 1% carbon and may have small additions of vanadium for grain refining and toughness. Depth of hardening is around three millimetres when quenched from the normal hardening temperature of 780°C and will increase to around six millimetres by increasing the quenching temperature to 870°C. Toughness will decrease with the higher quench temperature.
Applications

These steels have many uses particularly in wood working tools and cold heading tools where high surface hardness and high core strength is required.
Quenching Systems

Other than that the heating medium for these steels must be neutral in respect to decarburisation. The most critical part of the heat treatment cycle is the quenching system which may use cold water or 10% brine solutions to achieve maximum hardness. Vigorous agitation is necessary to ensure even and satisfactory quenching as too s3ow a rate of cooling may lead to soft spots.
Tempering

Tempering is carried out in the range 150 – 250°C to achieve the desired hardness.
Oil Hardening Tool Steels

An example of oil hardening tool steel is AS1239 grade S1A-5 which is hardened from 800 – 840°C by quenching into oil.
Applications

This steel is normally used for heavier section punches than the ‘W’ series tool steels and possesses good dimensional stability.
Heat Treatment

Preheating at 650 – 700°C is recommended to allow the tool to equalise at a subcritical temperature prior to raising to the austenitisation temperature. This procedure helps to maintain dimensional stability.
Tempering

Tempering is recommended in the range 170 – 200°C which will give hardnesses in excess of 60HRc. Tempering in the range 250 – 350°C can result in a reduction of impact strength.
Air Hardening Tool Steels

Typical examples of these types of tool steel are grades ‘W’ and 'D' of AS1239.
Heat Treatment

These steels require adequate preheat at 780°C prior to austenitising and hardening is generally affected by still air cooling. Larger sections may need to be cooled in an airblast to achieve maximum hardness.
Tempering

These steels should be tempered when cooled to a handwarm condition and multiple tempering is sometimes necessary to achieve complete transformation and maximum toughness commensurate with hardness.
Air Hardening Hot Work Steels of H13 Type

These steels may be air hardened in sections up to 60mm. Above this thickness, whilst full hardening will occur, carbide precipitation at grain boundaries wilt lead to poor tool life and low impact strength.
Heat Treatment

The preferred procedure is to quench into a fluidised bed furnace or salt bath held just above the Ms point. This allows the cooling rate to miss the critical areas of the ‘S’ curve where carbide precipitation occurs. The tool is allowed to equalise at temperature in the quenching bath and then is removed and still air cooled to handwarm (approximately 50 - 60°C) for tempering.
Tempering

These steels must be adequately preheated at 650°C and 850°C prior to austenisation and soaking at 1010°C. As these steels are subject to secondary hardening effects, the maximum hardness is not achieved until the first temper has been carried out at 550°C. Subsequent multiple tempers are necessary to complete transformation of a sluggish austenite and achieve the desired working hardness.
Air Hardening High Speed Steels as1239 Grades 'T' and 'M'

Light section tools made from high speed steel may be satisfactorily quenched by air cooling although with flat tools it may be necessary to air harden between plates to minimise distortion. HSS may be quenched in a salt bath or fluidised bed furnace at 550°C, allowed to equalise and then still air cooled to handwarm prior to tempering. HSS is a secondary hardening steel achieving maximum hardness after the first temper. A second or third temper is necessary to reduce the hardness to the desired working level.
The Importance of Austenitising Temperatures

Austenitising temperatures are critical with HSS and strict adherence to the steelmaker's recommendations must be observed. Whilst high austenitising temperatures are necessary to ensure that the maximum amount of carbide is taken into solution the recommended temperatures are not far below the point of incipient fusion. For this reason accurate temperature control of the heat treatment process is essential.
Heat Treatment

Double step preheating of HSS prior to full austenitisation is recommended to minimise thermal shock. These treatments are usually carried out in the ranges of 600 – 650°C and 840 - 880°C, depending on the grade of HSS. After preheating, the tool should be raised to the recommended austenitising temperature and held for two to five minutes only before quenching.
Lower Temperature Hardening

There is a variation in opinion between various authorities on lower temperature hardening of HSS. With lower temperature austenitisation less alloy content is dissolved in the austenite (‘underhardening’).

Some authorities claim that low temperature austenitisation helps to achieve a higher toughness for tools with hardness levels of 54 - 56 HRC required for hot punching applications. Others claim that best results are obtained by adhering to recommended austenitising temperatures and tempering to achieve the desired hardness which results in superior toughness. This is a situation where a particular heat treatment procedure suits a particular operation and needs to be proven in practice.

East Timor's ramshackle capital, Dili, is dotted with rundown buildings, old cars and squalid camps packed with thousands of people waiting to return home after months of violence. But billions of dollars in largely untapped oil and gas reserves lie just off the coast of Asia's newest and poorest nation.

East Timor is zealously guarding its nascent oil and gas industry, seen as a
potential lifeline following centuries of colonial rule and foreign occupation that crippled it politically and economically. It is determined not to follow the path of several other mineral-rich countries that failed to prosper.

The tiny country created a petroleum fund last year to protect its mineral wealth for future generations, which was lauded by the World Bank and other international institutions. The government has vowed not to spend the money, which so far pools income from two offshore fields, on golden palaces and limousines but on roads, schools, and health.

Rules that govern the fund--currently $600 million and growing -- limit how much the government can withdraw, and theoretically ensure a sustainable annual income for the nation of less than 1 million inhabitants for decades to come.

"It's the absolute best way of preserving the nation's wealth," said Roger White, a British expert advising East Timorese energy officials under an eight-year consultancy program funded by a grant from Norway.

"It is to prevent the difficulties that many oil rich nations have had--either that their money is spent badly or when the oil and gas resources are gone, there is nothing left," he said.

East Timor was plunged to the brink of civil war in May when then-prime minister Mari Alkatiri--the fund's architect--dismissed 600 soldiers, sparking clashes between rival security factions that spilled into gang warfare, looting, and arson attacks. Alkatiri was forced to resign as prime minister in July amid allegations that he helped fuel the unrest, something he denies.

At least 30 people were killed and another 150,000 fled homes in Dili, highlighting the country's continued political instability seven years after it voted for independence from Indonesia.

East Timor survived largely on international aid when it first became a new nation in 2002, following two years of U.N. administration, earning almost nothing from its nascent petroleum industry.

Australia has been drilling for oil and gas for several years in an offshore field that includes Bayo Undang, located on contested waters between the two nations. After East Timor became independent, it was able to negotiate a considerably higher share in oil and gas revenues.

Twenty million dollars in royalties from the Bayo Undang field were rolled into the petroleum fund. Today it's worth more than $600 million, thanks to production at the Bayo Undang and Elenka Katua fields, soaring oil prices and interest payments, Alkatiri said in an interview with The Associated Press.

With an estimated 12 trillion cubic feet of natural gas beneath the Timor Sea--slightly smaller than the reserves found under Brunei--the fund is expected to keep growing.

A treaty signed with Australia in January to develop the Greater Sunrise gas field--the largest in the Timor Sea--is expected to earn East Timor $4 billion over the expected 30-year life of the project.

Abraao de Vasconselos, general manager)of the Banking and Payments Authority, which manages the petroleum fund, said the money is invested in U.S. Treasuries and each government withdrawal requires parliamentary approval.

"The idea is to protect the fund for future generations," he said.

But others noted that East Timor's ability to hold on to oil and gas as a lifeline depends largely on the ability of the government--which is for the first time trying to tap into the resource fund to pay for the 2006-2007 budget--to effectively manage the revenues.

That means building an effective government and private work force by improving health and education and investing in agriculture, infrastructure and rural development, said Jose Teixeira, Minister for Natural Resources, Minerals and Energy.

"Nothing will replace prudent economic and financial management," he said.

It also means avoiding pitfalls of other oil-rich developing nations like Chad, which saw a similar petroleum fund collapse after the government eased restrictions on spending of the oil money.

The World Bank responded by suspending $124 million to the Central African country, though the two sides have since signed an interim agreement restoring the loans.

Some critics at home wonder why East Timor is not taking advantage of its oil and gas reserves more quickly to rev up its economy and get people--who earn an average of less than a dollar a month--back to their homes.

"If we have the money, let's use it and not beg" from other countries, said Mario Carrascalao, a former East Timor governor. "It's not the way, we have to be responsible."

But White noted that East Timor, which was colonized for centuries by Portugal before coming under Indonesian occupation in 1975, needs to build an efficient bureaucracy before it can exploit the economic potential of its petroleum resources.

"There are very few experienced bureaucrats," he said. The country has had to start from scratch building all apparatus of government and does not necessarily know how to spend the money wisely, he added.

"It's the birth pains of a new nation," White said.

The recent instability also highlighted the risks of doing business in East Timor.

The government was forced to postpone signing oil and gas exploration contracts in other offshore areas with Italian oil and gas giant Eni SpA and India's Reliance Petroleum Ltd., said White. Gangs barged into a building that contains the offices of several senior energy officials and looted computers and supplies, he said. Several local staffers have yet to return to work, he added.

The deals are still on, Teixeira said, and they may be signed in the next few weeks.

"We were just within three weeks of signing these big contracts and having enormous work for the good of the country and now it's just waiting," White said. "It's an absolute tragedy."

Cooper Energy Limited said that it has made a strong start to its 2006-2007 drilling program, announcing a 50% increase in its discovered oil reserves inventory following the recently announced discovery at Callawonga-1 (PEL92), the first well in its current exploration program in the South Australia's Cooper Basin.

The company estimated that the P50 discovered reserves for Callawonga are 1.6 million barrels of oil, with the well cased and suspended as a future producer in the Namur formation.

The well will either be developed as a standalone producer or tied back to the nearby Christie's oil field (in production), with the preferred development scenario to be determined by engineering studies to be completed as a near-term priority.

Mike Scott, Cooper's CEO, said the discovery of the 1.6 million barrels (0.4 million barrels Cooper Energy share) would increase the company's P50 discovered reserves position to approximately 1.2 million barrels of oil, representing an increase of 50% over the June 30, 2006, estimate of 0.8 million barrels.

The upgraded reserves portfolio comes after the recently announced oil production of 354,086 barrels of oil for 2005-2006, which exceeded the company's base case target for the year by 54,086 barrels of oil. Cooper recently announced a 4% increase in oil sales for the June Quarter to A$8.4 million, increasing its working capital to a record A$23.9 million.

"Callawonga-1 has provided a very strong start to the year, propelling Cooper Energy to its strongest 30 June P50 discovered reserves position to date," Scott said. "We are aiming to commence production from this field in the final quarter of 2006."

An open-hole production test for Callawonga-1 produced 2,400 barrels of oil per day and it is expected that the production facilities should be able to achieve similar or greater production rates.

"We believe that this discovery has the potential to open up a new oil play fairway around the Christies oil field. The Callawonga discovery will be followed up with Snowden-1, located 10km south of Christies, which we expect to spud in approximately 3 weeks," Scott continued. "Snowden-1 will then be immediately followed by Somerton-1, which lies 7km west of Christies and 7km south west of Callawonga-1"

Following the drilling of these wells, a regional 3D seismic survey in PEL92 will be acquired and interpreted so that further prospects can be high-graded for future drilling. It is expected that the acquisition and interpretation of the 3D seismic will be complete around early to mid-2007. Following the seismic, drilling of economically viable targets would be expected to commence in the second half of 2007.

Based in Perth, Western Australia, Cooper Energy's strategy is to leverage off the strong cash generation of its Cooper Basin operations to build a substantial international oil and gas portfolio that will underpin its next stage of growth. Significant acquisitions have already been announced in Morocco, Tunisia, Cambodia, and Indonesia. The company is continuing to seek new oil and gas opportunities in its two focus areas of Southeast Asia and North Africa and is working to mature its exploration portfolio in order to deliver high-quality prospects for drilling.

President Hugo Chavez is spending more than $7 billion of oil revenue this year to help Venezuela's poor, and they love him for it.

But in the downtown business district, over and over again you hear allusions to one of Aesop's fables.

"You don't want to kill the goose that lays the golden eggs," said Elio Ohep, editor of Petroleumworld.com. "If you scare away investment, what are you going to do?"


Venezuela's president is seeing how far he can push international oil companies such as ExxonMobil Corp.

In the last several months, Venezuela's government has raised royalties, taxes, and government equity in dozens of oil projects. In April, a Venezuelan congressional report urged Chavez to take similar steps with four heavy oil projects run by multinational companies in the Orinoco River belt, possibly the world's largest oil province.

The measures would put the national oil company in charge, give Venezuelan courts exclusive jurisdiction over disputes, and shift billions of dollars from the companies to Chavez's regime.

Gersan Zurita, an oil analyst with credit evaluators Fitch Ratings in New York, said the moves would essentially turn the private oil companies into silent partners in an oil business that would be run by Venezuela.

The struggle will affect future company earnings, Venezuela's economy, and future world oil supplies.

With oil prices soaring and new oil fields hard to come by, Chavez has the upper hand.

"Twenty-six companies decided to go to the new system," said Bernardo Alvarez, Venezuela's ambassador to the United States and a former deputy energy minister. "It was 100 percent legal."

When French company Total SA and the Italian firm Eni SpA balked, Chavez sent the national guard to seize their fields.

ExxonMobil sold its interest in one oil field, shut in another, reserved its right to seek arbitration over government royalty hikes, and was removed from a petrochemical venture by the Venezuelan government.

The company says it's in Venezuela for the long haul, but it could still come to blows with the government over an Exxon-managed $1.6 billion heavy oil project in the Orinoco belt.

That possibility led Fitch Ratings and Moody's to downgrade the project's debt, along with the debt of three other Orinoco projects, in May.

A hard line

ExxonMobil chairman Rex Tillerson isn't backing off. In March, he said the company would refrain from any major new investments in Venezuela. Asked in May whether the Orinoco was too big to walk away from, Tillerson told The Dallas Morning News: "Well, nothing's too big to walk away from for us."

ExxonMobil takes a hard line with any government that tries to change contract terms, whether it's Chavez or the U.S. Congress, which wants to roll back royalty relief for offshore drilling that was enacted when prices were low.

But when companies weigh political risks against the geologic risks inherent in looking for oil, many of them decide to ride out a rough political climate.

"There's a low risk in Venezuela for discovering oil, and these companies know that," said Alejandra Leon, an oil analyst in Mexico City with Cambridge Energy Research Associates. "They are able to pay higher royalties in exchange for more access because it's getting harder and harder to gain access to oil reserves."

Venezuela has the oil. Its proven reserves of 79.7 billion barrels rank seventh in the world, and Venezuela could take the top spot from Saudi Arabia if it can demonstrate that even 10 percent of the 3 trillion barrels of thick, tarry oil in the Orinoco belt is economically recoverable.

Cheap start

In the 1990s, Venezuela lured multinational companies to older fields and the difficult Orinoco belt with generous terms. As part of a strategy called the apetura, or opening, Orinoco projects faced royalties of just 1 percent.

Petroleos de Venezuela, or PDVSA, Venezuela's national oil company, took a minority stake in the projects (though its preferred shares gave it the key voice in overall strategy). Income tax on the projects was set at 34 percent, and the contracts called for disputes to go to arbitration in New York.

ExxonMobil, ConocoPhillips Co., Chevron Corp., Total SA, BP PLC, and Norway's Statoil ASA have more than $16 billion invested in the four projects, which together produce more than 600,000 barrels a day of crude oil upgraded from the thick, gunky deposits.

Higher taxes, fees

In May, the National Assembly, which is made up entirely of Chavez loyalists, enacted a new 33.33-percent extraction tax. The government raised the income tax rate to 50 percent. Royalties were raised to 16.7 percent.

The recent report by an assembly committee recommended nearly doubling the new royalty rate while giving PDVSA a 60-percent share in each project.

Fitch Ratings' Zurita then wrote a special report on the situation called "Venezuela's Heavy Oil Projects: The Beginning of the End?"

Venezuela, he warned, is scaring off foreign investors.

"Some of these companies have become less and less tolerant of fiscal instability and changes in the rules in midstream," Zurita said. "So it's not surprising to us that we see huge amounts of investment, sums like $700 million a month, going to the [Persian] Gulf, where countries like Qatar are moving very much in the opposite direction of Chavez."

Shell Canada Limited has announced earnings of $475 million or $0.58 per common share in the second quarter of 2006 compared with $526 million or $0.64 per common share for the corresponding period in 2005. High maintenance costs and lower production associated with the first major scheduled turnaround of the Athabasca Oil Sands Project offset a favorable adjustment resulting from changes to federal and Alberta corporate tax rates. Earnings for the first six months of 2006 were $922 million compared with $943 million for the same period in 2005.


Cash flow from operations was $527 million for the quarter and $1,249 million for the first six months of 2006, down $276 million and $191 million respectively from the same periods in 2005.

Excluding the acquisition of BlackRock Ventures Inc., capital and predevelopment expenditures amounted to $492 million in the second quarter and $896 million for the first six months of 2006 compared with $327 million and $596 million respectively for 2005.

“The acquisition of BlackRock in the second quarter was an important step forward in our growth strategy,” said Clive Mather, Shell Canada’s president and CEO. “The first major turnaround at the Athabasca Oil Sands Project is now behind us and we are looking for a strong second half from our Oil Sands business. Our Oil Products business achieved record results for the second consecutive quarter and the E&P business remains on track with good development prospects in both the Foothills and basin-centered gas.”

Shell Canada Limited on Wednesday provided an update of its overall in situ oil sands portfolio following the completion of the BlackRock Ventures acquisition. In addition, the company outlined its longer-term upgrading strategy.

As part of Shell Canada’s continuing review of the BlackRock assets following the acquisition, the company estimates that its total in situ oil-in-place is more than 25 billion barrels. This estimate includes the resources in the BlackRock leases of the Peace River, Cold Lake and Athabasca oil sands regions, along with approximately seven billion barrels of oil-in-place in Shell Canada’s Peace River leases.


Over the next two years, Shell Canada intends to build on the existing momentum and grow in situ production to nearly 50,000 barrels per day (bpd) predominately from the base operations at Peace River, the newly acquired Seal and Chipmunk assets, and the initial phase of the Orion SAGD project in the Cold Lake region. Additional future production growth will come from the previously announced Peace River thermal expansions, expanded cold production opportunities and other recovery projects. Shell Canada will evaluate the use of enhanced recovery techniques such as waterflood, miscible flood and steam injection to maximize recovery from the entire in situ portfolio. This will provide a longer term in situ production potential of 150,000 bpd.

“Oil sands is at the heart of Shell Canada’s growth strategy, and our new in situ portfolio significantly increases our potential,” said Clive Mather, President and CEO, Shell Canada Limited. “Our in situ oil-in-place now stands at more than 25 billion barrels of heavy oil and bitumen. And we believe there is more to come once we have completed our evaluation of the Athabasca area in situ leases acquired in 2005 by the AOSP joint venture owners. These resources will enable the company to grow production over the long term, exploiting our technical and operating expertise.”

The manufacturing of synthetic blends and finished products is integral to Shell Canada’s profitability and growth strategy. With its growing heavy oil portfolio, Shell Canada is now planning to incorporate in situ production growth into future upgrading plans which will potentially include expansions at Scotford and other locations. Beyond the currently proposed 100,000 bpd upgrader expansion at Scotford, it is Shell Canada’s intention that future upgrader developments will be dedicated to Shell Canada’s equity production from both mining and in situ growth plans. Shell Canada is also evaluating expansion of its manufacturing facilities in Eastern Canada to maximize value from increased production of synthetic crude feedstock.

Shell Canada Limited is a large integrated petroleum company in Canada with three major businesses. Exploration & Production explores for, produces, and markets natural gas and natural gas liquids. Oil Sands is responsible for an integrated bitumen mining and upgrading operation in the Athabasca area of Alberta and Shell Canada’s in situ bitumen business. Oil Products manufactures, distributes, and markets refined petroleum products across Canada.

Without innovations that can reduce gas demand from oilsands development in Canada or significant new supply from the Mackenzie Delta region, some analysts are predicting that Canadian gas exports to the United States could tumble by as much as 5.5 Bcf/d (63%) by 2020.

"When the incremental demand generated as a result of the oilsands development is factored in, the amount of Canadian gas available for export to the U.S. is likely to diminish considerably over time," said Raymond James analysts J. Marshall Adkins, Wayne Andrews and Pavel Molchanov.


They noted that Natural Resources Canada estimates non-oilsands gas demand in Canada will grow about 2.1% per year through 2020, while Canadian natural gas production is expected to rise only 0.2% per year over the same period. Canada exported 8.8 Bcf/d of gas to the United States last year, which was more than half of its production. That 8.8 Bcf/d provided about 15% of U.S. gas needs.

In 2005, about 261 MMcf/d of gas went to open pit mining of oilsands, which is restricted to deposits near the surface. According to Raymond James' estimates demand for open-pit mining will grow to 1.1 Bcf/d by 2020. In-situ mining of oilsands, in which gas or steam is injected into the ground to lower the viscosity of the oil, consumed 246 MMcf/d of gas in 2005, but the analysts project that will grow to 1.2 Bcf/d by 2020. In total, Raymond James projects that gas demand from oilsands development will grow from 0.5 Bcf/d in 2005 to 2.3 Bcf/d by 2020.

"Combined with rising non-oilsands Canadian gas demand and stagnant Canadian gas supply, this is almost certain to greatly limit the excess amount of gas available for Canada to export," the analysts said.

One factor that Raymond James did not consider, however, is the innovate fuel alternatives that oilsands development has only started to make possible. For example, two weeks ago Synenco Energy Inc. signed an agreement to provide Agrium with hydrogen, nitrogen, sulfur and carbon dioxide produced from asphaltenes in the 100,000 bbl/d Northern Lights Upgrader oilsands project proposed in Sturgeon County, AB. Agrium will use the products in its anhydrous ammonia production, resulting in a 22 Bcf/year reduction in Agrium's natural gas consumption.

The emerging next generation of Alberta oilsands projects provides an early example of how new technology will make oilsands a contributor to natural gas supplies rather than just a drain (see Daily GPI, July 21).

Royal Dutch Shell plc said that it welcomes Shell Canada’s formal proposal to expand the Athabasca Oil Sands Project.

Shell Canada Limited announced that it has issued a formal proposal to proceed with Expansion 1 to the other Athabasca Oil Sands Project (AOSP) joint venture owners. They have 90 days to respond.

"We have received our Board's support to take the next step on this important growth project," said Clive Mather, president and CEO of Shell Canada Limited. "Issuing this proposal to the other owners is a key milestone in our strategy to grow mining production from the Athabasca region to 550,000 barrels per day (bpd)." Shell’s share of this production is 330,000 bpd.

Shell Canada completed an extensive feasibility study followed by a rigorous cost estimate and assurance review process in support of this formal proposal. The heated markets for labor, materials, and equipment have impacted all facets of this 100,000-bpd expansion project. Although the capital intensity of the project, estimated at between $275 and $350 per annual flowing barrel, has increased significantly from earlier estimates, Expansion 1 remains viable under a wide range of pricing scenarios.

Expansion 1 is a fully integrated expansion of the existing AOSP facilities, with both new oil sands mining operations on Lease 13 and associated additional bitumen upgrading at Scotford. It also includes construction of common infrastructure that will be sized to support future expansions. The previously announced solvent de-asphalting plant is not included in Expansion 1 because the technology is not yet ready for integration into the upgrading process. It is expected that the Expansion 1 expenditures will be similar between the mine and the upgrader.

Shell Canada intends to make a final investment decision for this project in the fourth quarter of 2006 pending regulatory approvals. First bitumen production is expected in late 2009 followed by upgrader production in late 2010.

The Muskeg River Mine is located about 75 kilometers north of Fort McMurray, Alberta. The Scotford Upgrader is located near Fort Saskatchewan, northeast of Edmonton. Together the facilities make up the existing Athabasca Oil Sands Project, a joint venture among Shell Canada Limited (60%), Chevron Canada Limited (20%), and Western Oil Sands L.P. (20%).

Posting a big jump in second-quarter profits to $157.9 million, Enbridge Inc. said Wednesday it believes that its entire $13-billion suite of new oilsands pipelines will go ahead.

Over the past several years, Calgary-based Enbridge has unveiled an ever-increasing number of pipeline proposals, aimed at moving rapidly increasing oilsands production from northern Alberta to new markets in the U.S. and Asia.



"In total, we now have over $13 billion worth of announced projects on the go in our (oil) liquids business alone, and many are asking how many more of these Enbridge projects will actually go forward?" president and CEO Pat Daniel told analysts.

"I believe that they all are going to go forward."

Daniel said its "backbone" mainline oil system, which is one of the largest pipelines in the world, is poised for significant expansion, which can be done in a very cost effective manner.

The efficiency of the line can then be passed onto shippers through lower tolls, bringing more support for the new pipeline proposals, said Daniel.

"The addition of each new piece of this market access strategy really adds to our relative competitive advantage, as well as providing a platform to further expand and extend our mainline liquids system," he said.

Enbridge is also working on two pipeline plans which would bring diluent, or the chemicals badly needed to dilute heavy oilsands crude in order to allow it to flow through pipe.

The first one, a $1-billion line called Southern Lights, will bring up to 180,000 daily barrels of diluent from the U.S. Midwest to northern Alberta.

The second line will be a 150,000-barrel-per-day line taking imported diluent from a deepwater port at Kitimat, B.C. back to Edmonton and the oilsands region. It is part of Enbridge's $4-billion Gateway pipeline aimed at taking oilsands crude across the Rockies and onto tankers bound for the Asian and Californian markets.

"This will be enough to meet forecast diluent needs early into the next decade," said Daniel.

The company conceded Wednesday that timing for its Gateway pipeline could be pushed back slightly to potentially 2011, though specifics won't be known until commercial deals are finalized.

Last year, Enbridge announced a preliminary deal with Beijing-based PetroChina (to reserve half of Gateway's capacity. But firm deals with PetroChina and other shippers have yet to be signed.

Daniel said Wednesday that opening up a "brand new market for Canadian crude" was a slow and complicated process, that involved making contacts and getting a better sense of the business from both Asian refiners and Canadian oil producers.

"I'm convinced that this line will get built, it's just going to take some time to get the parties comfortable with doing business with one another," said Daniel.

"It is badly needed by Canadian producers in order to get the optionality that they need and, to tell you the truth, it's badly needed by Chinese refiners to get the optionality they need in terms of crude supply."

Earlier Wednesday, Enbridge released second quarter earnings of $157.9 million or 46 cents per share, a jump of 69 per cent over the year-earlier profits of $93.6 million or 27 cents per share.

The company credited a strong performance from the Enbridge crude-oil mainline system and one-time gains from the revaluation of future income tax balances due to tax rate reductions.

Warmer weather also led to a $9.3 million drop in earnings from its gas distribution business.

Excluding one-time items, Enbridge's earnings were 35 cents per share, still higher than analysts' consensus forecast was for earnings of 31 cents a share, before one-time items, according to Thomson Financial.

Cash provided by operating activities rose to $477.2 million from $351.6 million.

Enbridge stock gained 39 cents to $36.91 in afternoon trading on the Toronto stock market.

Habanero Resources Inc. said that it was pleased to learn recently that Pan Orient Energy Corp. now owns approximately 36 percent of the outstanding shares of Andora Energy Corp., a privately held company of which Habanero owns 700,000 shares.

Upon completion of the remaining transaction, currently scheduled for mid-September, Pan Orient will own a minimum 51-percent interest in Andora. Binding lock-up agreements exist between Pan Orient and certain shareholders of Andora, ensuring Pan Orient

a minimum 51 percent ownership in Andora. In addition to Pan Orient's controlling interest in Andora, under the terms of the agreements, three of the five Andora directors and the Andora chief executive officer will be nominees of Pan Orient.

Andora owns a 100-percent working interest in petroleum licenses and related assets covering 16 sections of land located immediately south of, and adjacent to, Pan Orient's Sawn Lake property. Four of the 16 Andora sections of oil sands leases have been assigned net probable and possible recoverable reserves of 98 million barrels (25.9 million probable and 72 million barrels possible) based on an independent third party National Instrument 51-101 compliant reserves report completed by DeGolyer and McNaughten (D&M) in September of 2005.

Also on July 28, 2006, Pan Orient's wholly owned subsidiary, Pan Orient Energy Ltd., transferred its 10-percent working interest in oil sands leases in the Sawn Lake area of Alberta to Andora for consideration of 10 million Andora shares. This will now give Andora an interest in 85.5 square miles of undeveloped Alberta Oil Sands.

Additionally, Pan Orient will acquire a minimum of 6,618,519 Andora shares from existing shareholders of Andora for a minimum total acquisition price of $8,935,000 (comprising of a maximum 25 percent cash, the remainder in Pan Orient shares at a deemed value of $3.75 per Pan Orient share), which, together with the shares already acquired by Pan Orient pursuant to the transactions described above, will give Pan Orient approximately 51 percent of the issued and outstanding Andora Shares.

Binding lock-up agreements exist between Pan Orient and certain supporting shareholders of Andora, ensuring Pan Orient this minimum 51 percent ownership in Andora. All shareholders of Andora will be entitled to participate in this transaction and in the event that shareholders of Andora wish to sell more than 6,618,519 Andora shares, Pan Orient will purchase additional Andora shares from such shareholders up to a maximum 67 percent ownership level, under the same maximum 25 percent cash terms.

This share acquisition will be effected through an amalgamation of Pan Orient Energy Ltd. (whose sole asset was its Sawn Lake interest) and Andora, which is scheduled to be ratified by Andora shareholders in mid-September. A notice of annual and special meeting and management information circular is currently being prepared by Andora which is expected to be mailed to Andora shareholders in mid-August.

"This is great news for Habanero shareholders as now having an interest in 85 square miles of Alberta Oil Sands land (through Andora) represents a tremendous opportunity for the company," said Jason Gigliotti, Habanero's president. "This is one of the single largest continuous land packages in the Alberta Oil Sands, and for Habanero to been involved is extremely exciting. Management feels that this prospect could be a major growth driver for Habanero in the near and long term as this massive land package gets fully developed or even possibly bought out.

"When you combine this exciting news on this land package with our other Athabasca Oil Sands leases, it is clear that Habanero intends to grow via the Oil Sands and we have shown the ability to acquire high-quality assets. Habanero is one of the smallest market capitalized companies with interests in multiple Alberta Oil Sands leases and when you add the current near all time highs on oil prices and increasing gas prices, these are extremely exciting times of expansion for Habanero."

The Canadian Environmental Assessment Agency has awarded a total of $100,000 to four applicants to support their participation in the joint environmental assessment review of the proposed Kearl Lake Oil Sands Mine Development Project in Northern Alberta.

The funds will assist the successful recipients to prepare for and participate in the joint public hearings on the environmental effects of the project. The Alberta Energy and Utilities Board (EUB) application will serve as the basis for the

joint panel's review of the project. A joint review panel comprised of members of the EUB and a member appointed by the federal Minister of the Environment will review the project starting this fall.

The recipients are: the Athabasca Chipewyan First Nation Industrial Relations Corporation; the Mikisew Cree First Nation; the Oil Sands Environmental Coalition; and the Métis Nation of Alberta - Local 1935.

A funding review committee, independent of the environmental assessment process, was established to examine all funding applications received for this project. All of the Committee's recommendations are unanimous and are contained in the report of the Funding Review Committee. The report, along with further information on the project, is available on the Canadian Environmental Assessment Agency's Web site.

Imperial Oil Resources Ventures Limited and ExxonMobil Canada Properties are proposing to construct and operate an oil sand mining and extraction facility. The project consists of four mine pits to be mined over the period 2010 to 2060. The proposed Kearl Lake Oil Sands Development Project is to be located approximately 70 kilometers north of Fort McMurray. The project is expected to produce 300,000 barrels (approximately 48,000 cubic meters) per calendar day of clean bitumen. The application seeks approval for a maximum production of approximately 345,000 barrels (55,000 cubic meters) per calendar day.

CanWest Petroleum Corporation reported Tuesday that it has completed its combination transaction (the "Combination") with its subsidiary, Oilsands Quest Inc. As a result of the Combination, which was approved by the Oilsands Quest minority shareholders earlier today, CanWest Petroleum now owns 100 percent of the common voting equity shares of Oilsands Quest.

Each common share of Oilsands Quest held by other shareholders was exchanged for 8.23 exchangeable shares of Oilsands Quest (the "Exchangeable

Shares"), resulting in the issuance of 76,504,302 Exchangeable Shares on a fully diluted basis. The rights, privileges and restrictions governing the Exchangeable Shares provide that each whole Exchangeable Share may be exchanged for one CanWest Petroleum common share.

Through a voting trust arrangement, the holders of Exchangeable Shares are entitled to vote at all meetings of holders of common stock of CanWest Petroleum. Following the Combination, CanWest Petroleum currently has approximately 179,568,196 issued and outstanding common shares (including common shares underlying 57,349,388 Exchangeable shares) and, on a fully diluted basis, 232,165,234 common shares.

As part of the Combination, the following events occurred:

* The board of directors of CanWest Petroleum was reorganized and is now comprised of T. Murray Wilson (Executive Chairman), Christopher H. Hopkins, Ronald Phillips, Thomas Milne, William Scott Thompson and Gordon Tallman. The officers of the Corporation are now T. Murray Wilson, Executive Chairman; Christopher H. Hopkins, President and Chief Executive Officer; Karim Hirji, Chief Financial Officer; and Errin Kimball, Vice-President, Exploration.
* CanWest Petroleum became a reporting issuer in Alberta as of August 11, 2006, and on August 14, 2006, filed on SEDAR (www.sedar.com) its annual filings under National Instrument 51-101 for the year-ended April 30, 2006, comprised of Form 51-101F1 (statement of bitumen exploration activities and other information) and Form 51-101F3 (report of management and directors). As CanWest Petroleum has not attributed any reserves to its properties, it has not filed a Form 51-101F2 (report of independent qualified reserves evaluator or auditor). These filings are also available on CanWest Petroleum's website (www.canwestpetroleum.com). In an earlier news release dated July 6, 2006, the company's management released its estimate of resources which are to be further reported upon by independent third-party estimate.

CanWest Petroleum has applied for a listing on a senior U.S. exchange. In addition, the company intends to seek shareholder approval to change its name to Oilsands Quest Inc. or a similar name at its upcoming annual shareholder meeting to be held this fall.

Commenting on the Combination, Executive Chairman, T. Murray Wilson, said: "This is a pivotal step in the reorganization of CanWest Petroleum. The combined team is looking forward to capitalizing on the many strengths of both companies." Christopher H. Hopkins, President & CEO, added, "We are very pleased with the Combination and welcome the opportunity to work with all stakeholders."

With respect to the Combination, TD Securities Inc. acted as financial advisor to CanWest Petroleum, and CIBC World Markets Inc. acted as financial advisor to Oilsands Quest. Genuity Capital Markets provided the independent committee of the board of directors of Oilsands Quest with its opinion that the consideration to be received by the shareholders of Oilsands Quest upon completion of the Combination was fair from a financial point of view to the shareholders of Oilsands Quest.

Surge Global Energy, Inc., a major shareholder of Signet Energy, Inc., the operator of the Sawn Lake Oil Sands Development, on Tuesday said that Signet has begun drilling its second well in the development. This is the first of three additional wells that Signet will drill over the next 90 days in the Bluesky Formation of the Sawn Lake area.

The Sawn Lake Oil Sands Development has been estimated by two respected third-party petroleum engineering firms to contain a total of 820 million to 1.2 billion barrels of oil resource in place, of which Signet Energy can earn a 40-percent working interest on all contiguous sections covering 44,480 acres in the Sawn Lake area of Alberta, Canada.

Signet has commitment to drill a total of 10 wells, each well drilled earns Signet an interest in the field; one well has been drilled and completed to date and demonstrated cold flow reservoir characteristics. To date, Signet has earned a 40-percent working interest in 6 sections. Deep Well is being carried by Signet for the first 10 wells and thereafter, Deep Well is required to pay its 40-percent share, along with each of the two other 10-percent working interest partners that pay their share of completion, production test, and operating costs.

Surge Global Energy, Inc., located in San Diego, California, is a major shareholder of Signet Energy, Inc. The company invests in assets that target Canadian oil sands and conventional oil and gas properties in North and South America. Surge also holds a working interest in the Santa Rosa Dome project in the Mendoza province of Argentina. It also has rights to earn a working interest in the Keg River Formation in the Kitty area of North Central Alberta, Canada.

Rowan and Louis Dreyfus Fairmount B.V. (managed by Fairmount Marine) signed a transportation contract for the mobilization of the Rowan jackups "Gilbert Rowe" and "Rowan Paris" from the Gulf of Mexico to the Middle East.

Superbarge Gavea Lifter, with 50,000 TDW the world's largest semisubmersible transportation barge, will be mobilized to the Gulf of Mexico immediately after completion of the current Sedco 709 dry docking operation in South Africa. Only Gavea Lifter is able to transport both rigs in one time, thus saving considerable costs and time for the owner. Business Industry Articles

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A new industry is emerging to service Canadian oil sands producers looking for more bang for the barrel.

Not only is crude from Alberta's oil sands heavy and difficult to refine, but the North American market for it is saturated. As a result, a barrel of Canadian heavy crude - also known as bitumen - typically fetches around 25% less than a barrel of light, sweet West Texas Intermediate crude used as the U.S. benchmark.

That's a discount that Canadian producers are keen to narrow. So far, some companies have turned to building their own upgraders, processing facilities that convert bitumen into a lighter synthetic crude that's easier to refine and fetches a higher price. But many are reluctant to commit to investing the billions of dollars needed for those facilities, especially in an environment of cost inflation.

Independent firms are stepping in to fill that gap in an initial sign that a merchant upgrading sector in Alberta is developing. One facility - the 260,000 barrel-a-day Heartland project - is already under construction by BA Energy, a new Calgary-based independent energy firm. In addition, last week North West Upgrading Inc., with a similar profile, hired an engineering firm to complete specifications for its proposed upgrader in Alberta.

And upgraders are beginning to look like refineries at a time when the industry is racing to keep refining capacity growth on pace with demand. Canada's refining industry - with only 2 million barrels a day of throughput capacity according to the U.S. Energy Information Administration - lags far behind that of its southern neighbor because it has historically relied on the U.S. to refine its crude output.

The first C$2.4 billion ($2.15 billion), 77,000 b/d phase of North West's facility is expected to come on stream in 2010. The company is planning two extra stages, of similar dimensions and cost, that will expand the plant's throughput capacity to around 230,000 when complete. Regulatory approval for the first phase is expected in mid-2007, with construction seen starting in 2008.

North West doesn't produce any crude itself. Instead, it expects to process bitumen from producers eager to realize better prices for their output.

"There's a very broad spectrum of potential customers," said Robert Pearce, president of North West Upgrading. "Firms need to ensure that they're not getting bad prices for their crude production."

Heavy Oil Conundrum

The notion of an independent upgrading firm came to Pearce when he was treasurer at PanCanadian Energy, which later became EnCana Corp. (ECA), Canada's largest hydrocarbons producer. PanCanadian wrestled with the problem of how to upgrade its heavy oil reserves. For now, EnCana is seeking a refining and marketing partner for its oil sands development plans.

"We looked several times at how to upgrade those barrels, and it made me think about an independent option," Pearce said. "From a producer's perspective, the best upgrader is one that's been developed by someone else and is on their balance sheet."

Canadian energy companies are penalized for their heavy crude - to the tune of the $16 a barrel less they currently get for it compared with Canadian light crude. Estimating its upgrading costs at $6 a barrel, North West wants to lock in long-term service contracts with oil producers and avoid risks associated with sharp changes in oil prices. Under these agreements, North West would charge a processing fee but never take possession of the heavy oil feedstock or the output.

Such an arrangement is rare among global refining players, who take on the commodity price risk in the hopes of reaping profits from fluctuating prices in crude and product markets.

North West has already reached a deal with Canadian Natural Resources Ltd. (CNQ), whereby the producer will supply North West with 25,000 barrels of crude a day for a five-year period. North West wouldn't give further details of how the supply arrangement is structured.

The deal, which could eventually rise to 45,000 b/d, appears slightly surprising as Canadian Natural has plans to construct an upgrader of its own. However, encouraging the development of an independent facility is a smart decision, Pearce said.

"Canadian Natural are still going to be long in heavy crude even if they build their own upgrader, so supporting another is a good move strategically," he said. "It'll help ensure there's sufficient upgrading capacity available."

Canadian Natural was unavailable for comment.

Diversifying Product Streams

Unlike other processing facilities, North West's upgrader itself won't produce a single blend of synthetic crude, but will instead process the bitumen into refineable vacuum gasoil, or VGO; natural gas condensate; and ultra-low sulfur diesel, or ULSD.

Of those products, the VGO is the only stream that would need to be refined. The condensate will likely be used by local heavy oil producers as diluent to aid in transporting their bitumen to market, while the ULSD can be taken straight to the U.S., Pearce said.

"The independent revenue streams are far more valuable," he said. "With respect to the diesel, we'll be selling refined products directly. We will actually be a refinery."

However, the market for ULSD in Alberta isn't deep, and no pipeline exists that could take the diesel to market without contaminating it. Consequently, North West will have to market the ULSD by rail, possibly to Canada's West Coast, from where it can be shipped markets such as California.

The company has so far raised C$175 million for the project, leaving it with the challenge of securing another C$2.5 billion by 2009.

The project also fits in with the Alberta government's stated objective of processing as much bitumen in the province as possible, thereby securing more of the crude value chain.

Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc., announced that construction on the Tucker Oil Sands Project is complete and that steam injection into the reservoir commenced on August 20th.

First oil is anticipated in November of this year, with peak production of more than 30,000 barrels per day expected to be achieved within two years after commencement. During the 35-year Tucker project life, Husky expects to produce approximately 350 million barrels of bitumen. The facility will employ approximately 40 full-time workers.

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Construction on the project, 30 kilometers northwest of Cold Lake, Alberta, began in the fall of 2004 and at its peak employed approximately 700 on-site workers from several contractors. Total project capital costs are below the budget of $500 million. Husky used a lump sum turnkey contract for the Central Processing Facility, which amounted to approximately 60 percent of the total project capital costs.

"Tucker is in close proximity to Husky's Cold Lake pipeline system and heavy oil upgrader in Lloydminster, Saskatchewan, making it an attractive integrated project," said Mr. Lau. "I wish to congratulate the Husky project execution team and its contractors in completing the work on time and under budget, given the cost pressures and wet weather of 2005."

Husky Energy is a Canadian-based integrated energy and energy-related company headquartered in Calgary, Alberta.