Oil & Gas Network - August 2009

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Publication Mail Agreement No.: 40039458

August 2009 Volume 10, Number 4

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August 2009 Publication Mail Agreement No. : 40039458

Volume 10, Number 4

Contents 5 Full Circle, Full Speed Ahead 7 Preserving the Alberta Promise

Return Undeliverable Canadian Addressed to: OIL & GAS NETWORK MAIL

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7 Crude oil and natural gas prices will have the most significant impact on the energy business in the next three years 8 & 9 Peak Water Theory in the Athabasca and the non renewable planet 10 Remote site surveillance system to assist oil sands companies in reducing operational risk 11 Report Foresees Bitumen Production Surge

EDITORIAL ASSOCIATES

David Coll

14 & 15 Petrobank moving THAI into conventional oil 16 - 22 Industry still growing, but more

Seema D Dhawan Joni Evans Joe Perraton

24 The Eco Environmental Solution for Expedient Construction of Helicopter Landing Pads 25 Go Expo - Heavy Oil the Future of Alberta?

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25 Go Expo - Our Planet: Small, Flat, Smart 26 Go Expo - SAGD Goes Green 25 Oil and Gas Price Forecaster Cautions Against False Hope

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27 - 29 ‘Canadian Gas at a Cross Roads’ Options for Producers to Preserve Value! 30 R&M Energy Systems’ SENTRY® Closure Features Innovative One-Piece Sea

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Cover Image: Long Lake integrated oilsands facility. Photos courtesy of Nexen / Dave Olecko

Oil & Gas Network, August 2009 3

Full Circle, Full Speed Ahead After all the good efforts to Communicate the oilsands story of late, to opponents it’s still just a street fight, still just ‘spin’ t was at the height of the nefarious (some might say ingenious) “Dirty Oil” campaign a while back.Ads were appearing in major U.S. magazines in newspapers with our beloved Maple Leaf dripping oil. Knowing the value of a soundbyte, a clever environmentalist referred to the oilsands as the mythical land of Mordor from Lord of the Rings.And in a shockingly one-sided rant (known as a “drive-by” in the media community) the National Geographic gave many their first high-definition glimpse of this supposedly notorious land of shadow where the evil Sauron rules. Coupled with the deepening recession, the Syncrude duck story that just doesn’t want to die, Fort Chipewyan water concerns made worse by a poor government response, and continued uncertainty on future greenhouse gas emission regulations, 2008-2009 has surely been the worst of times for the Canadian oilsands. And while economic recovery is definitely on the horizon, perhaps as early as late this year, few will dispute the game has changed forever. A while back, Suncor President & CEO Rick George was quoted as saying that the industry has not done a good job of communicating with respect to its environmental progress and overall performance as well as some of the technological innovations that offer hope for positive change. This “failure to communicate” view appears to be widely held in the oilpatch executive suite – I agree wholeheartedly but I think we need to make clear that the failure is not for a lack of trying. Just the opposite may be closer to the truth. We all know there’s a determined and increasingly desperate opposition out there who just do not – and will not listen. Like a partisan politician that’s been pounding the backbenches for years, these folks earn their livelihood from their very opposition. The research they conduct or promote is inevitably biased in favour of a certain presupposed view — not at all a dispassionate, scholarly, middle-ground discussion.You can tell just from some of their B-movie-like titles — Death By A Thousand Cuts, Danger in the Nursery — what these reports are going to conclude before even reading them. Without shareholders to answer to or a stultifying corporate hierarchy to navigate through, those who oppose the industry can act fast in taking the offensive. They have time to plan and set course, cultivate, inculcate. Industry is thus forced into a defensive shell and is often slow to respond. If an individual company responds aggressively, they risk distraction and getting pulled into an unwinnable debate that can erode shareholder value in a heartbeat. When the industry responds collectively, it does so through an association or a spokesperson and the response is often lacking immediacy and is just too complicated for television. The media thrives on this conflict — as a colleague of mine once put it so indelicately, “they lap it up like pigs to swill.” In my mind, the other reason for industry’s supposed “communication breakdown” is the fact that the environmental lobbyists don’t want communication anyway, damn it – they want action. Witness the following, from the introduction to the Pembina Institute’s lastest antiindustry salvo entitled Oilsands Myths: Clearing the Air:“Focusing on public relations instead of public policy is a strategy that backfires. Observers scrutinizing the oil sands see through the spin and shallow promises made by government and industry, which further diminishes Canada’s reputation.” With the release of this report in June, the industry and its opposition have now come full circle. Now, ironically, you have both sides taking the same approach: 1. take a commonly used statement from opposition 2. Call it a “myth” 3. Present your facts here and debunk the myth 4. Call it “reality.” 5. Provide bibliography of sources. 6. Issue press release. So after all of the communication to date – the recently added Canadian Association of Petroleum Producers oilsands website, A Different Conversation, complete with blog; the hiring of a communications professional to lead CAPP for, I believe, the first time in its history; the cross-country and cross-border efforts of the Oilsands Developers Group to debunk oilsands myths; all of the individual company efforts to produce various materials – and what do you have? As the Pembina report illustrates, it’s still just a vicious street fight, still just spin according to opponents.The battle for the hearts and minds of the public continues – trust remains in tatters and the government is drifting with the tides. Despite all the negativity out there, I think the industry’s earnest efforts to better listen and better communicate are starting to pay off. We are starting to get to that “glass half full” attitude Suncor President and CEO Rick George has been talking about. My suggestion: don’t get dragged back into the morass of debate and dissent, continue the good things we’re doing as an industry and as companies, knowing that it just takes time and understanding some minds will never be changed.

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Coll’s

Oil & Gas Network, August 2009 5

Preserving the Alberta Promise Rob Gray, Manager, Communications & Member Relations lberta has long been known for its promise of opportunity and prosperity, but that promise is on the line. Alberta, while traditionally recognized as a place to thrive, is now seeing jobs and investment flee, perpetuating a dramatic decline in industry activity (to the tune of a 50 per cent decrease over last year) and a massive spike in unemployment where Alberta is setting new records nation-wide. Oil and gas makes up roughly half of Alberta’s economy, so it’s fair to say that the industry is an intrinsic part of the Alberta promise.And, while all industries and all provinces are struggling with the effects of the current global recession, the downturn in Alberta’s petroleum industry began long before the current recession, and has been more severe than in neighboring provinces. The sector that has been hardest hit is the petroleum service sector – the sector which completes work on behalf of oil and gas companies at well sites across the province, and which is responsible for the majority of rural oil and gas activity, employing over 100,000 Albertans. As a result of the devastating declines in activity, layoffs and wage-rollbacks have been widespread in the sector, the effects of which are being felt in hotels, restaurants, and other businesses across the province, especially in rural areas. At the same time, while the leading indicators of future activity in Alberta are forecasted to continue declining, new records to the positive are being set in Saskatchewan and BC, where both governments are working very proactively to attract business and investment. Clearly, the province of Alberta needs to become more competitive in order to preserve the Alberta promise. A more competitive operating environment is essential in maintaining a thriving province and economy, within which Albertans have the freedom to create and the spirit to achieve. The Stelmach government should be commended for its decision to pursue a competitiveness review. This review is the key to Alberta’s future and the province’s ability to rebound from the current recession.We encourage the government to move quickly on this review and to do so in a manner that is open and transparent, includes input from economic stakeholders and contributors, and includes a review of fiscal regimes including royalties to ensure that Alberta is a competitive place to do business, relative to competing jurisdictions. By taking appropriate, proactive measures now, the future for Alberta can be bright. Alberta has the potential to enjoy continued prosperity and maintain its reputation as a place of opportunity where western values continue to drive achievement. We are counting on the government to get this right. On behalf of our 270 member companies and their 60,000 employees, we urge the Stelmach government to deliver a competitive framework that ensures a bright future for Albertans by stimulating opportunity to fulfill the Alberta Promise.

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Crude oil and natural gas prices will have the most significant impact on the energy business in the next three years hile 2008 was a year of two extremes, with oil and gas producers experiencing boom and bust all within 12 months and many responding by cutting their capital spending plans for 2009 anywhere from 25% - 35%, they still continue to plan for the future according to the Canadian Energy Survey released today by PricewaterhouseCoopers (PwC) and JuneWarren-Nickle’s Energy Group. - 70% of respondents expect prices to increase somewhat over the next year and 11% believe prices will increase substantially. Approximately 16% said crude oil prices will stay about the same in the year ahead. - The majority of respondents said oil prices will have to increase to at least US$70-$80 before they would consider increasing conventional drilling programs, although an almost equal number said prices will have to head north of US$80 before spending more on conventional drilling. - Close to 57% of respondents said the ability to adapt to change is a critical requirement for their long-term sustainability; while 68% of respondents said attracting and retaining top talent was viewed as critical for their long-term growth.Technological innovation was seen by 40% of respondents as critical for ensuring sustainable growth. - Respondents also said they expect to increase their investment into research and development (R&D) over the next two years, with 23% indicating they plan to boost R&D spending in 2011 versus only 4% this year and 22% in 2010. - 72% of gas producers believe prices should recover within the next two years to a level that will lead them to increase their drilling programs whereas 28% believed it might take three years or longer for natural gas prices to recover to levels that will result in more wells being spudded. “The turbulent swing in energy prices from all-time highs in the summer of 2008 to four-year lows in December is a powerful reminder that the booms in commodities can quickly evaporate,” says John Williamson, Partner and Canadian Energy Leader at PwC. “At the mid-way mark of 2009, while gas prices continue to languish, many believe natural gas fundamentals point to a recovery in 2010,

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which will lead to improved drilling activity levels. Crude oil prices have already rebounded from year-end 2008 levels.” Companies across the oilpatch are adopting a number of measures to remain profitable, including capital budget cutbacks, moving operations to other jurisdictions with lower royalties, as well as salary freezes or rollbacks, and layoffs. While industry has cut staff, many energy companies prefer not to lay off employees because so much time has been spent training them. In the survey, attracting and retaining top talent was viewed by 68% of respondents as critical for their long-term growth. This driver was seen by respondents as the most critical factor that will influence future growth.

Financing The financial crisis has reduced access to both debt and equity. As a result, 39% of survey respondents expect to rely on cash flow to support their business over the next year, while 26% identified debt and 14% equity as their primary sources of financing. Two-thirds of respondents said access to capital and credit is critical to sustain their growth over the long-term. But respondents also feel that debt will likely be the most difficult source of financing to obtain in the short-term (over the next three years), with 63% saying it will be somewhat challenging and 26% believing it will be very challenging. Close to 54% of respondents also believe it will be somewhat challenging to secure equity financing in the next three years, with 33% saying it will be very challenging.

Operating Costs Fully 57% of survey respondents said they anticipate their overall operating costs to decrease over the next year, with declining labour and material costs helping the bottom line. Some oil producers now say that labour and material costs have lowered so much that projects may be economical at lower prices. In addition, 76% of respondents said their land acquisition costs would stay the same or decrease over the coming year. In the first

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Oil & Gas Network, August 2009 7

Peak Water Theory in the Athabasca and the non renewable planet By Patrick Brennan he acute demand for resources renewable and non renewable will be the driver of extreme volatility in financial markets until passive alternatives are found. Humanity has evolved and existed for thousands of years using renewable sources of energy as the cornerstone of consumption. Non-renewable resource dependence is a modern day preoccupation in most

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8 Oil & Gas Network, August 2009

sectors of our daily commerce and a source of political, social, and economic addiction around the globe. The peak oil debate boils down to the timing of an economic limit in delivering a finite resource to the energy consumer. Despite the short term volatility in oil markets and the suggestion that demand destruction will play prominently in energy con-

sumption throughout North America, it is abundantly clear the contango seen in the oil futures market since the financial debacle is applying continued upward pressure on hydrocarbon products. This means continued pressure on all resources. Pondering this struggle between the bears and the bulls in the energy markets leads one to speculate on constraint of both finite and unlimited resources. What if the demand for resources, once considered unlimited, reach a bottleneck in the systems natural capacity to deliver? Specifically what if the demand for clean drinking water or fresh air became so intense capacity peaked? For almost two billion inhabitants on the planet access to clean drinking water is a daily struggle, and for most large city dwellers air borne particulates linked to adverse health effects are a concern. Suddenly renewable resources appear finite. It is not a stretch to contemplate a Peak Water Theory. The well documented case of the Colorado River supported by the Ogallala Aquifer spanning from Texas to South Dakota frequently running dry is a case in point. The aquifer has encountered a capacity limit in the natural earth systems ability to recharge given the agricultural, residential, and industrial uses within the rivers drainage area. At the 6th Biennial Rosenberg International Forum on Water Policy after determining the effects of more than 70 river basins globally being closed to new water licenses...the idea of “rethinking water supply and maximizing the benefits that water provides” are likely to be profound metrics of economic wealth in the near future. Closer to home in the Athabasca abundance in every capacity is striking. The vast river systems, riparian areas, boreal forest and supporting waterscapes, and of course the oil are seemingly endless.The reserve life for heavy oil and oil sands production is projected to last over fifty years with anticipated production rates of 2.5 – 3.5 million barrels of oil per day by 2020. The looming national debate over system capacities has found opinion in almost every household and town hall in North America. Consumers understand the need to extract the primary resource, but most have grown impatient and suspicious of the methods. The concern largely rests in measuring and putting limits on resources that were once considered unlimited, or at the very least renewable. Carbon Capture and an associated tax or scheme of trade, seem to present a palatable option for ‘the greening’ of clean air needs. Maybe solutions to this problem are manageable because the resource cannot be seen. Exporting carbon offsets around the globe as easily as a stock broker executes a trade for any of the thousands of public stocks, if nothing else offers an image of doing something. Water on the other hand is inherently more complex. Offsetting water from a natural water course requires infrastructure as intricate as the network to deliver crude oil or natural gas. In addition the right of access to clean air is not in question. The right of access to clean drinking water has been threatened by physical limits in numerous communities in every country around the globe. In the Athabasca region every barrel of synthetic crude oil produced requires a minimum of three barrels of fresh water drawn either from ground water or surface withdrawals from the Athabasca River drainage area. (This metric is published in the business plans of both mining and SAGD operations. Recycling through closed loop systems means the actual water requirement per barrel is three to four times the above number). Three million barrels per day of sco will require nine million barrels of permitted fresh water withdrawal every day to engage in the cumulative business plans of the Athabasca Oil Sands Operations. A detailed review of the Alberta Government’s Water for Life Strategy and supporting documents such as the

Photo courtesy of 2pointphotography

Draft Directive for Thermal Insitu Recovery Schemes show where the holes are in the systems natural capacity to supply fresh water and maintain a standard and right of access to clean drinking water for every Albertan. Legislation in the proposed directive based on various guidelines for water conservation in the province of Alberta state that; fresh water is defined as having less than 4,000 milligrams of Total Dissolved Solids (TDS) per litre of water, brackish water is defined as having greater than 4,000 milligrams of TDS/litre of water. Recent academic forums, with representatives from both industry and government have discussed the need to increase the definition of fresh water up to 10,000 milligrams TDS per litre of water. This is required due to anticipated demand for this essential resource. The Pembina Institute advocates a charge for industrial water use. The ERCB has officially stated that companies will have to compete for water and disposal space in the future. On Januar y 21, 2009, using data from Alberta Environment’s Water Management Framework CNRL, Suncor, Syncrude, and Shell’s Albian Sands projects were asked to reduce the amount of water taken from the lower Athabasca downstream of Fort McMurray. A low river advisory, likely induced by ice jams, was a possible explanation for this reduced withdrawal. Subsequent data published by Alberta Environment showed several weeks of low river flows. The spring of 2009 will be remembered in Alberta for the drought conditions affecting agriculture, forestry, and oil production. I will reword the question postulated above, is it a stretch to consider a Peak Water Theory in the Athabasca? A true definition of a ‘draconian measure’ is to simply evaluate water needs by a yard stick stuffed in the river bank.The parade of elementary students at the June 2009 Calgary’s Major’s day Expo featuring the City’s water infrastructure could tell you ‘groundwater systems are the life blood of a river and our communities.’ A sophisticated investor perusing the business pages of any Wall Street or Bay Street publication would be familiar with the financial metrics advising on the best energy companies to own stock in.An index on oil sands operations may weigh investment choices based on production performance, P/E ratios, chart patterns, forecasts, and guidance. None have considered the outcome if there was simply not enough water to execute the cumulative business plans of these operations. Market speculation might lead one to hypothesize the best investments are based on the most sustainable processes.

There are numerous companies using technologies to mitigate this risk in limited water supply. The simple suggestion that a Peak Water Theory in the Athabasca is a possibility, far exceeds the view of a thirsty post mortem inquiry on how Alberta failed to measure its most precious ‘renewable resource.’ Without any further delay these investments include production systems that significantly reduce or eliminate water use. Such as in situ air injection/combustion technologies, and heavy to light oil upgrading at the well head offers hope. Absorption technologies for tailings pond clean up and management. Electrically induce heat radiation technologies used in shale oils also appear to be likely candidates for sustainable investment in this field. Biomass gasification processes that produce clean high energy sources are the likely choices for short and medium run success, both satisfying investor returns and generating capital

for solutions to this obvious need. Over the long run Albertans’ will have to ask is the investment in nuclear technology justified to ensure long term viability of oil sands production or is the investment a clean energy source for every day access to power that is potentially fatal if mismanaged? Nuclear power posses its own threat to a manageable fresh water supply if any of the above arguments hold true. Alberta’s future is anything but green and likely brackish if peak water theor y in the Athabasca becomes a reality. Responsible consumption of both renewable and non-renewable resources is essential. Investment in sustainable processes are a likely modern day financial metric that could become vogue, and heavy oil and mining processes that mitigate peak water risk deserve attention for both access to capital and future access to clean drinking water.

Oil & Gas Network, August 2009 9

Remote site surveillance system to assist oil sands companies in reducing operational risk By Shelly Brimble Calgary-based company has created a unique technology solution to help firms manage the operational risks associated with bitumen resources located in remote areas. “Oil sands producers face many safety, security, environmental and operational risks every day. Our solution mitigates these risks through the application of our video analytics and real-time event notification,” says Dr.Wael Badawy, president and CEO of Intelliview Technologies. Throughout the last decade, activity in the oil sands has risen dramatically and even with the lull brought on by the recent economic downturn, it continues to be Canada’s capital of oil production.

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The oil sands contain 173 billion barrels of recoverable reserves of the nation’s total 179 billion barrels of oil. Producers are only starting to scratch the surface of this vast bitumen resource, but as oil sands development increases so also do the operational complexities associated with accessing these reserves in remote areas that are subject to some of the harshest of environmental conditions. Petroleum companies continue to seek new solutions to keep pace with rising operational concerns and increasing regulatory compliance requirements. Regulatory guidelines were recently launched by the Energy Resources Conservation Board (ERCB) to manage the lifecycle of

tailings ponds.Tailings ponds are created through surface mining operations. Bitumen is removed from the oil sands through the addition of hot water.What is left after that process is put into a separator allowing the water to rise to the top where it is skimmed off and the sand to drop to the bottom to be taken out. The sludge clay material that is left behind is put into tailings ponds to settle and dry for reclamation. There are currently 13,000 ha of land under wetable surface as a result of the tailings ponds.“This is growing each year, and unless industry changes the way it manages and reclaims tailings it will continue to grow,” says Stephen Smith, previous ERCB Fort McMurray executive manager and current ERCB executive manager, Application. Smith added that Directive 74: Tailings Performance Criteria and Requirements for OilSands Mining Schemes deals with existing mining operations, but the ERCB has already given industry the heads up that once it is established, the Directive may well be grandfathered to older tailings ponds as well. The regulations focus on finding measurable and accountable solutions. Smith noted that the ERCB does not prescribe any one technology solution, but rather sets the end results and leaves it up to industry to select the solutions.

“Directive74 reflects the growing concern for the safety and monitoring of tailings ponds. The recent duck deaths at Syncrude have spurred industry to review new technologies. Our video analytics technology can be an important part of the solution for oil sands operators, especially for the surveillance of tailings ponds, and for remote sites in general,” says Badawy. Intellivew provides a digital video recorder (DVR), with a suite of analytics on- board, to deliver local processing of video images. In effect, the system converts passive cameras into intelligent video sensors. The system can be programmed to send an alarm only when prescribed incidents occur. Within three seconds of an event or condition, an alarm and jpeg image is sent through the company’s LAN,WAN or web server.This incident-only communication significantly reduces operating costs since it minimizes the demands on bandwidth. Since the entire surveillance system is manufactured and programmed locally, it can be tailored to meet each operator’s unique specifications.“We are one of a select few analytics firms (less than 10 in the world) that has our own sourcecode, and this gives us the capability to modify the system to meet a customer’s specific needs,” says David Ruhlen, Intelliview’s business development manager.

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Report Foresees Bitumen Production Surge lberta remains on pace to significantly increase bitumen production over the next 10 years, the Energy Resources Conservation Board (ERCB) reports. In its recently released report, Alberta’s Energy Reserves 2008 and Supply/Demand Outlook 2009-2018, the ERCB forecasts that Alberta raw bitumen production will rise to 470,000 cubic metres (m3) or 3 million barrels per day by 2018, based on announced expansions of existing projects and commencement of new projects. In 2008, bitumen production averaged 208,220 m3 (1.31 million barrels) per day.

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Based on newly available geological data and analysis, the ERCB increased its estimate of the remaining established reserves under active mineable development from 2.91 billion m3 (18.3 billion barrels) to 3.74 billion m3 (23.4 billion barrels). The annual report draws from the ERCB’s own geological and technical analysis and is a source of information on the state of reserves and the supply and demand for Alberta’s diverse energy resources: bitumen, crude oil, natural gas, natural gas liquids, coal, and sulphur. It includes estimates of

reserves at Dec. 31, 2008, and a 10-year supply/demand forecast for each resource. A supply/demand forecast of electricity in Alberta is also provided. The report includes historical data for energy resources production. Alberta’s remaining established reserves of conventional oil are estimated to be 233 million m3 (1.5 billion barrels), a 3 per cent decrease from 2007. This decline is consistent with the trend over previous years. In 2008, companies added 20.6 million m3 (130 million barrels) of conventional oil reserves through drilling, replacing 77 per cent of production for 2008. The ERCB estimates the remaining ultimate potential of conventional oil at 590 million m3 (3.7 billion barrels). Last year, Alberta produced 79,900 m3 (502,800 barrels) per day of conventional oil. The report also reveals that Alberta’s remaining established reserves of natural gas stood at 1,098 billion m3 (39 trillion cubic feet) at the field gate as of Dec. 31, 2008. Reserves from new drilling replaced 81 per cent of production in 2008, compared to 78 per cent replacement in 2007. Several major factors have an impact on natural gas production, including natural gas prices, drilling activity, the accessibility of Alberta’s remaining reserves, and the performance characteristics of wells. Alberta produced 364 million m3 (12.9 billion cubic feet) per day of marketable natural gas in 2008, of which 22 million m3 (767 million cubic feet) per day was coalbed methane. Meanwhile, Alberta’s remaining established coal reserves are estimated at about 34 billion tonnes (37 billion tons), while 2008 production totalled 38 million tonnes (42 million tons).

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Continued from page 10 The number of analytics algorithms in the IntelliView solution suite is substantial, and the ease of programming the policy rules is impressive. Companies can receive notification if a person has crossed a virtual boundary, or fence-line, if an individual is loitering or has left an object behind, or even if a person has fallen and remains immobile.The analytics suite can also be used as an operational aid to monitor valves and other production equipment, and is currently being field tested to facilitate and verify remote equipment start ups. To further enhance its analytics solution, Intelliview has also created a technology to compensate for environmental conditions that are often responsible for false alarms. Other analytics solutions can be fooled by environmental conditions such as shadow, snow and glare, but IntelliView’s patented Environmental Filter will reduce such false alarms by up to 96 per cent. The company confirmed this vastly improved

performance through an independent study using City of Calgary traffic cameras. “IntelliView has a decided edge in the remote monitoring of oil and gas sites because operators will quickly come to ignore any analytics solution that produces a high rate of false alarms. Our solution delivers the real value of a video system, which is the accurate assessment of a site condition and the real-time notification of the event,” adds Ruhlen. Till now, the harsh environmental conditions associated with remote sites, along with the lack of power and communications infrastructure, have precluded the widespread use of video surveillance as a monitoring option. IntelliView’s unique system architecture is particularly amenable toremote-site deployment. Cameras of virtually any type (analogue, IP, fixed, PTZ, thermal or infrared) connect to the locally housed DVR, and the supporting power infrastructure

can include solar panels, battery and fuel cell arrays, wind turbines and generator systems. The communications options are equally diverse, including radio, cellular and satellite connectivity. The IntelliView system has recently been field-tested by a major producer at a site near a rural community that has been frequently vandalized. Local teenagers used the location as a gathering spot, and vandalism to the facility (including axe marks to a sour gas pipeline) became a regular occurrence.The producer needed know when the facility had been compromised, and it needed to know in real-time. IntelliView’s system was easily deployed to the site on a mobile platform, complete with self contained power and communications infrastructure.The producer soon had the site back under its control, and the facility was returned to a normal operating status. Another IntelliView surveillance innovation includes a speed bump camera that records every vehicle coming into a remote location. Traditionally license plates are difficult to record so they are legible. Being in the speed bump enables it to capture a close shot and the camera operates in extreme conditions, including snow.

Knowing when an unauthorized vehicle has entered a remote site can provide operators with the information and the ability to react quickly to avert site damage or safety issues for their field staff. This can also help operators prove they have protected worker safety when dealing with Bill C-45 concerns. “With increasing incidents in eco-terrorism in the industry, this system can become a valuable tool to help petroleum companies in combating this type of risk,” adds Ruhlen. 12 Oil & Gas Network, August 2009

Petrobank moving THAI into conventional oil By Shelly Brimble aving proven that THAI technology is working well in a pilot test facility near Fort McMurray, Calgary-based Petrobank Energy and Resources Ltd.is ready to deploy the innovation into conventional oil as well.The success of this technology has also captured the attention of international community and negotiations are underway to deploy it overseas. Traditionally, new technology takes about five years to be integrated into the oil and gas industry. Petrobank Energy launched the technology in the Whitesands pilot facility in 2006.Despite some initial sands issues that were easily overcome, the company reports that THAI is working as anticipated in the project models. “We don’t need any more proof...it is working in the field and we are going to take this technology around the world,” says,Chris Bloomer, Petrobank Energy senior vice president and chief operating officer, Heavy Oil. The THAI process injects air into horizontal wells instead of steam into the oil sands to release the bitumen. The air combusts in the sands causing an ignition front that sweeps the hot bitumen towards the production zone. Since this process uses air it requires less energy and no water when compared to traditional SAGD operations.

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These operational benefits have put Petrobank Energy’s THAI technology in the spotlight game changer in bitumen production. A vast majority of bitumen will be obtained using in situ technology since only 15 per cent can be reached by surface mining. Bloomer says that the proof of the THAI success in the Whitesands pilot facility is very evident in the overall well performance. “We can start up these wells in challenging reservoirs. We have been producing upgraded oil since day one.

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We know the coke is dropping out of the produced bitumen so it is coking in situ.The produced water separates easily from the oil. We are seeing a tremendous upgrade in the oil with THAI at 12-14 degrees API,” he says.The pilot is currently producing about 250 barrels per day. The in situ upgrading benefits of the THAI process provides many environmental and operational benefits. THAI is more viscous pouring like a glass of orange juice as compared to bitumen that is like sluggish molasses in the fridge. Bitumen viscosity usually causes additional transportation costs since operators need to add diluent to enable it to flow through pipelines. The produced oil is also a higher quality which Bloomer believes refiners will eventually pay a higher price for once higher production capacity has been established.“This is a huge difference in costs because we only need to take a THAI barrel from 13 degrees to 22 degrees API gravity. The difference is $5to $10 per barrel in operating costs,” adds Bloomer. Petrobank also did a first in the world application at Whitesands by inserting a catalyst directly into a THAI well. Known as CAPRI, this catalysts is expected to provide even greater upgrading results.The CAPRI well isstill being observed so the final results are not available yet, butPetrobank has reported some changes.“In our CAPRI well (PB3) the oilis lighter and it smells different. Petrobank has simplified THAI production design creating

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Compressors used to inject air into the THAI process. a cookie cutter off the shelf solution so that every component can be easily sourced by third party suppliers.This simplicity as well as the upgrading associated with the THAI process also enables Petrobank Energy to reduce operating costs. As a result, they have become one of the lowest cost operators (about CDN$10per barrel). Although Petrobank has clutched back on some of their rollout plans due to the economic condition and low commodity prices, they are still planning to move ahead with multiple deploymentplans for THAI technology. Two kilometers from the pilot project willbe the location of the first large scale commercial THAI project thatwill evolve into a 100,000 barrel per day operation. The May River project is expected to start soon since with the initial phasefor 10,000 - 15,000 barrels per day is already

under regulatory review. This next phase THAI project has been designed with self-sufficientpower generation, sulphur recovery, is CO2 capture ready and will alsobe a net water producer. Bloomer expects it will take 18-24 months to complete the project once it begins. Once regular production is established on from Whitesands and May River, Bloomer is confident that the company will gain more financial benefits. He expects the THAI produced oil will fetch Petrobank more (about $2 to $3 per barrel) thentheir competitors in the future because it will be a better quality ofoil for the refiners. Near Conklin Alberta, Petrobank Energy isalso rolling out another THAI project known as the Dawson Project. This project is being deployed with a new partner, Shell Canada Limited, whobought the previous partner (Duvernay Oil Corp.) in August 2008.Regulatory applications are already underway and the company expects to begin construction soon to gain access to significant 11 degree American Petroleum Institute (API) gravity oil in place. There are cold production projects operating in the area but, these are only recovering about 10 per cent compared to the THAI outlook for 80 percent recovery. Early exploration has also begun in the 23,000 acre oil sands license at Sutton, Saskatchewan. Already 35 kilometers of 2D seismic has been acquired over key target areas and initial results are showing strong potential for THAI potential. Petrobank has also targeted other heavy oil reserves for THAI technology and plans tofield test it in a heavy oil project at Kerrobert, Saskatchewan in athird party THAI license project. Saskatchewan, like Alberta has a vastamount of its oil resources found in heavy oil reserves. It is estimated that THAI would hit a bulls eye in Saskatchewan by unlocking another

20 billion barrels of conventional heavy oil resources. “Conventional heavy oil is a new market for THAI and this could have a big impact inSaskatchewan where there is lot of heavy oil. Once we have established this, we can then go after the same type of oil with low recovery and no other technology solutions internationally,” he adds. Already international interest in the THAI technology is rising with many third part opportunities emerging. The THAI technology has been developed through Archon Technologies Ltd., a wholly owned subsidiary. Plans are underway to market this Canada-made heavy oil solution to the rest ofthe world. “International deals are taking more time to solidify due tothe economy, but they are still progressing and there are new players coming to the table,” he says. An aerial view of Whitesands

Oil & Gas Network, August 2009 15

Industry still growing, but more slowly he downturn in the oilsands industry was rather sharp and rather sudden, but the climb back out will take longer, industry experts and analysts agree. This decline is different from any other in Alberta’s history, says Jacques Marcil, senior economist for the Canada West Foundation. Marcil is the author of a

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recently released report entitled A Rough Patch: Alberta Economic Profile and Forecast. “In the past, the price of oil has gone down, but the rest of the economy in Alberta just kept chugging along,” Marcil says. “Or the energy industry kept growing while the national economy was struggling.“ But this time, they both went on a downward spiral at the same time. And the price of a barrel of oil increasing is only part of what’s necessary to return to calm waters. In July 2008, the price of U.S. crude hit a high of $147 and one year later closes around $60. Yet that is almost double from the low of $32.70 in January.

16 Oil & Gas Network, August 2009

Marcil says to watch the economy of the United States to get a picture of how soon the economy here will rebound. “It really depends on how fast the U.S. gets out of their recession,” he states, adding that the energy policy the U.S. is set to release will also have an impact on Alberta’s oilsands industry. The Canada West Foundation is forecasting that Alberta’s real GDP will decline by 2.4 per cent in 2009 and grow by 1.9 per cent in 2010. It will take the oilsands industry some time to climb out of this downturn in part simply because the projects are on a such a large scale. “It takes awhile after they say ‘go’, so there’s a delay,” There Marcil is already some says. good news on the oilsands horizon. Don Thompson, president of the Oilsands Developers Group, says that the group’s members are spending $18-billion in operating expenses this year and planning to go forward with about $8-billion in capital investment this year. “The oilsands is not dead,”Thompson says. “It isn’t as if investment has gone to nothing. For any other industry, this would be boom time. The oilsands is still a huge contributor to the Alberta economy.” But it is a far cry from what oilsands developers originally had planned for 2009. “I think nobody in the world predicted the depth and extent of the global economic meltdown. The price of crude oil very quickly went down lower than anyone ever predicted,” says Thompson. The Oilsands Developers Group usually releases a forecast annually, but this year plans to release two. The first one came out in March with an update is planned for September. “Things are very fluid right now, so we will try to do a sixmonth update,”Thompson says.“I would hate to say the worst is behind us. I don’t think I have ever experienced something so broad across all industries.” Meanwhile, the Canadian Association of Petroleum Producers (CAPP) released its 2009 crude oil production forecast and markets outlook in June.

“CAPP’s production forecast indicates that even with delays due to current economic circumstances, oilsands production is expected to grow, although the pace of development has slowed,” says Greg Stringham, CAPP’s vice-president, markets and oilsands. For the oilsands component of Canada’s oil supply, the share of supply coming from in-situ projects increases slightly over the forecast period and the proportion of total oilsands that is upgraded remains relatively unchanged over the forecast period of 2009-2025. Bob Dunbar, president of Strategy West, a Calgarybased consulting firm that focuses on the oilsands, echoes others remarks that while the oilsands will see growth over the long term, but that’s there’s still uncertainty about how long that will take. “It does look a little more promising now because it looks as if we have seen the bottom, but there is some uncertainty as to how long the bottom will last,“ Dunbar says. Provincial budget forecasts for 2009-2010 show that oilsands revenue is expected to drop to about $1 billion this year because of the global recession. The economic downturn is allowing the oilsands the luxury of some breathing room that it simply didn’t have a couple of years ago. “The recent credit crisis and collapse in energy prices can be seen as a chance for the industry to step back and focus on the next moves in the development of the oilsands,” says

CERI senior economist David McColl in a report called The Eye of the Beholder: Oilsands Calamity or Golden Opportunity? “Herein lie opportunities: to secure high-quality labour being let go by organizations, to secure components and products at costs that have not been seen in almost a decade, and to prepare for the

Photos courtesy of Nexen / Dave Olecko.

eventual return of higher oil prices and economic activity while your competitors scramble to catch-up.” The catch is, the companies have to be rich enough to take the risk, he says. The Canadian Energy Research Institute’s 2009 Economic Slowdown Projection indicates that $218 billion will be invested in the oilsands for new production. That figure is $97 billion less than previously projected by the Institute last year. The study assumes that oil stays below US$60 a barrel for most of 2009 and credit markets still lack liquidity. Under this projection, economic recovery begins in early 2010, and oilsands development stalls until 2013, with no major growth until 2015. “We assume this resumption to be limited to established oilsands projects and others with adequate financing in place prior to the credit collapse of 2008. It takes at least two years for most mining and in situ projects to start production after construction begins,” states McColl’s report. “However, many projects will not start construction in

2010, but will begin a reassessment and refinancing period that could take several years. Some projects are likely to be deferred until 2015, which will create a further backlog in projects, pushing those with 2015 plans (as announced in 2006 to early 2008) beyond 2020.”

Encouraging Signs After a series of announcements in the last quarter

of 2008 about project delays, recent news has been more positive. The Rough Patch report by the Canada West Foundation highlights the March acquisition by Suncor of Petro-Canada as creating a new, healthy $43 billion giant.The deal will allow the two companies to cut $1.3 billion in annual costs, said the presidents of Suncor and Petro-Canada. And while some projects remain on the back burner, Imperial Oil’s announcement in May to invest more than $8 billion in its previously stalled Kearl oilsands project is another positive step for the industry. Production is estimated at 110,000 barrels per day and is scheduled to start in 2012. Fluor Corp. was awarded the contract to build infrastructure and facilities for the first phase of

the Kearl project located 70 kilometres northeast of Fort McMurray. Imperial Oil has captured what CERI senior economist David McColl calls a “golden opportunity. They basically saved 25 to 30 per cent off their capital costs relative to if they did it in the latter half of 2008. They are probably going to get the best deal on labour and materials because they are the first out of the gate,” he says. Imperial Oil spokesman Pius Rolheiser says Imperial Oil is not “overly bothered” by the current lower price of oil. “In this case, the change in the economic condition has seemed to work in our favour,” he says. “Certainly costs of labour and commodities are lower now, but what they will be a year from now I wouldn’t venture a guess.” The major construction period at Kearl will be 2010-2011 with a workforce of between 2,000 and 3,000. Currently an estimated 1,000 personnel are working on the project. Another project considered by analysts to mark renewed investor confidence is privately-owned oilsands player MEG Energy Corp.’s application in June for the third phase of its Christina Lake in-situ project. And Connacher Oil and Gas Limited announced in early July that

construction activities were restarted at its second 10,000 barrel per day SAGD facility in northeastern Alberta. The company said it anticipates construction activities at Algar and the drilling of 15 SAGD well pairs will take about 275 days to complete. The fact that so many companies deferred projects or expansions is of benefit to those who have now decided to go ahead, says Strategy West’s Dunbar. “Construction costs have been going down. Labour availability is going to be easier, especially finding fully skilled workers,” he says. “Engineering costs have come down because engineering firms are hungrier for work.” On the plant operations front, Nexen has already found that finding skilled labour is somewhat easier now than it was in the past few years. Recruitment personnel from the operator of the Long Lake integrated oilsands facility, headed to British Columbia, Nova Scotia and Newfoundland in June to fill a number of long-term positions.

Continues on page 19 Oil & Gas Network, August 2009 17

Continued from page 17 no tailings ponds. Environmental groups have pushed for more protection of the Athabasca River, but Thompson said that the oilsands withdraw just one per cent of the mean annual flow from the river. “People have to have the true facts placed before them. Give the full story and let people decide,” he says. The Oilsands Developers Group has tried to do that by giving media tours of the oilsands, yet National Geographic showed photos of the mined land, but chose not to include photos of the reclaimed land,Thompson said.The group is continuing it public education campaign. The Pembina Institute is also focusing on public education about the oilsands, but with a different spin. In June the Pembina Institute distributed copies of Clearing the Air on Oil Sands Myths to Canadian and U.S. decision makers. “Government and industry brochures and presentations that defend status quo oilsands development are littered with misleading statements,” says lead report author Jennifer Grant.“We wanted to make sure that decision makers, the public and the media had access to the full story when considering and discussing oilsands development.” The environmental organizations, such as the Pembina Institute, the Sierra Club and Greenpeace, which had activists enter Syncrude’s Aurora site without permission last summer, seem to be winning the public relations battle, said Bob Dunbar, president of Strategy West. “Environmental issues are very important for the industry, but the public image is not good,” he says.

Government Directives They were seeking to fill positions in the areas of technical, engineering, health and safety, power engineering, shift supervision and maintenance positions including millwrights, pipefitters, instrumentation and welders. “I think people are more open to relocating to Fort McMurray than they have been in the past,” says Kirk White, Senior Recruiter for the Long Lake oilsands facility.“The quality of resumes was pretty good and people came out with a good expectation of living in Fort McMurray. We certainly promoted the philosophy of Nexen wanting a local workforce and having employees who live in and volunteer in the local community.” The Long Lake facility is located 40 kilometres southeast of Fort McMurray. In stark contrast to a year ago, the situation for oilsands employers has shifted to a buyer’s market.“There are now more people than jobs, which is a lot different than a year ago when there were more jobs than people,”White concludes.“And that’s good for Long Lake.”

Tracking Perceptions The Canada West Foundation has begun keeping track of oilsands stories published in the media and already has a better sense of public perception about the industry, said researcher Dan Gibbons.The findings show that there are concerns about the impact the oilsands is having on the environment. “We put out monthly reports and we’ve been tracking Canadian coverage, international coverage and internet coverage,” he said. “The greatest source of negative criticism comes from environmental websites.” In May, “environmental impact is still the largest issue and largest source of criticism and most passionate source of criticism. Carbon emissions tend to drive it,” Gibbons said. Many stories tracked in May related to the ecumenical delegation organized by KAIROS, which toured the oilsands in the latter part of the month and then released its conclusions. The group said it believes “the tar sands pose serious, complex questions for Alberta, for Canada and beyond. We agree with the Indigenous peoples’ and environmentalists’ calls for independent studies on the cumulative impacts of the tar sands development, especially concerning water and ecosystems.”

Getting the Word Out Oilsands companies such as Syncrude and Suncor Energy

have stepped up their environmental endeavors after a spate of negative publicity that has reached around the globe. Suncor has set company-wide environmental performance goals to reduce water intake by 12 per cent by 2015, to increase land area reclaimed by 100 per cent by 2015, to improve energy efficiency by 10 per cent by 2015 and reduce current air emissions by 10 percent by 2015. Suncor pled guilty in April to three environmental charges stemming from two separate incidents. Two Firebag charges related to failure to construct vapour recovery facilities and failure to provide information required under the legislation. The other charge related to exceeding regulatory limits for total suspended solids from the wastewater treatment and disposal plant at Millennium Lodge, near the base plant. “These incidents should not have happened,” says Kirk Bailey, executive vice-president of oilsands.“While there was no harm done to the environment or to human health, we fell short of the expectations of regulators, and Albertans – and ourselves.” Syncrude was charged by the federal government over the deaths of about 1,600 ducks in a northern Alberta tailings pond in April 2008. Syncrude faces one count under the federal Migratory Birds Convention Act and is expected to be back in court to enter a plea in September. The company offered what it called “a heartfelt and sincere apology for the incident” in an open letter that is posted on its website. President Tom Katinas said the company will “learn from what happened” and improve its practices. The oilsands companies, as well as oilsands organizations, are talking about their environmental practices more than ever because of more intense media coverage on those issues. Meanwhile, the Oilsands Developers Group, which has a mission to address the need for accurate, credible information about activity in the Athabasca oilsands deposit region, is hoping people will take the time to get all the “facts.” “A lot of environmental concerns come as a result of what I consider to be half-truths,” says Don Thompson. He has heard concerns about the boreal forest being destroyed through oilsands mining, but says the reality is that only 0.1 per cent of the boreal forest is able to be mined. In the last 40 years of oilsands development, 530 square kilometres of land has been disturbed and 65 square kilometres has been reclaimed. The rest of the oilsands in that area is too deep to be mined, so in-situ methods must be used, which means no mines and

The Government of Alberta has released a comprehensive 20-year strategic plan for Alberta’s oilsands that aims to reduce the environmental footprint, optimize economic growth, and increase the quality of life in Alberta’s oilsands regions. Responsible Actions: A Plan for Alberta’s Oilsands outlines long-term strategies and immediate actions that address economic, social and environmental challenges and opportunities in the oilsands regions. The plan showcases current efforts such as carbon capture and storage, and strengthens the approach for land reclamation, cumulative effects management and environmental conservation.

Continued on page 21

Oil & Gas Network, August 2009 19

The Alberta government announced a $2-billion carbon capture and storage fund last summer and has now announced that the money will be divided among seven companies. The companies selected include Epcor, Enbridge, Chevron Canada, Shell Canada, Enhance Energy, Marathon Oil Sands and Northwest Upgrading. Other government involvement includes the Energy Resources Conservation Board’s directive to develop new industry-wide criteria for managing oilsands tailings and specific enforcement actions if tailings performance targets are not met. Oilsands mines must now prepare tailings plans and report on tailings ponds annually, reduce the accumulation of fluid tailings and specify dates for construction, use and closure of fluid tailings ponds deposits and file that information with the ERCB by Sept. 30, 2009. “There has been a complete overhaul of the regulatory landscape for oilsands from what it was five years ago,” says Davis Sheremata, ERCB spokesman. In addition to creating some new environmental directives, this year the ERCB also expanded the boundaries of the surface mineable area for oilsands. The current area encompassed 37 townships and the expansion will add 14.5 townships.

The Role of Technology Oilsands companies can no longer rely on high oil prices to increase the profit margin, says Soheil Asgarpour, president of the Petroleum Technology Alliance Canada (PTAC). Instead, technology and knowing where it’s best to use each application will help give the industry the boost it needs, he continued. PTAC, along with the Alberta Energy Research Institute (AERI), ConocoPhillips, EnCana and StatoilHydro had scheduled a July 15 information session on the development of the Clean Bitumen Technology Action Plan, where collaboration will be a focus. “It is a technology road map; a very proactive approach,” Asgarpour says of the technology action plan. “We are looking at oilsands development from four perspectives. One is making sure to reduce the environmental footprint, secondly to make sure it is profitable, thirdly security of supply and fourthly minimizing social impacts.”

The industry seems to have been put in the penalty box for its impact on the environment, he said, adding that can change with more public education and new technological advances. A steering committee will be formed to identify the gaps in terms in oilsands technology. Over the next 12 months a schedule of workshops will result in a document that will serve as an action plan for technology development and foundation for future policy, strategy and investment decisions. PTAC is hopeful that many oilsands companies and levels of government will come the table to share expertise and funding. “This is an area where collaboration makes the most sense. You really want to make sure your costs are down significantly,” Asgarpour says. Two years ago, such an initiative may not have worked, but

the atmosphere is now perfect for additional collaboration, he adds. “We now have more of people’s time available. Before they were too busy and this is about participation of the experts.” Eddy Isaacs, executive director of the AERI, agrees that the in-kind contribution of people’s time has increased lately, providing more brain power. In the past, oilsands companies tended to direct research on how to increase production, but now research on how to reduce emissions and use less water is significant. “These things go in phases. We had just come through a phase where companies wanted to increase production,” says Isaacs. But now that the industry is in a downturn, the focus has shifted.

Oil & Gas Network, August 2009 21

“When the price of oil was very, very high, they may not have time to look at efficiencies,” he says. “I see a fusion between energy and the environment now. There is a much greater integration.” Isaacs points to research projects currently taking place that are looking to help oilsands have less impact on the environment while saving money and using less energy to harvest bitumen. The University of Alberta’s Centre for Oilsands Innovation is doing a great deal of research on non-aqueous extraction, to reduce the amount of water used in oilsands extraction. EnCana Corp. committed $1 million to the University of Calgary to research Canadian Plains mitigation and reclamation. The aim of the research is to increase understanding of the direct and indirect effects of oil and gas activity on the environment.

The Future In the immediate future, oilsands companies will continue to experience uncertainty with investors, as will other sectors, says David McColl, a senior economist with CERI. That uncertainty has loosened slightly in the past few months. “Things are still in a bit of a holding pattern, but there is some light at the end of the tunnel,” says McColl. Companies are continuing to evaluate this year if expansion projects that were deferred will be feasible to move forward. Bob Dunbar, president of consulting firm Strategy West, believes the next big announcement will come from Suncor. “My guess is one of the most likely ones would be Suncor resuming Firebag 3 construction,” he says. Suncor made a decision in January to halt the Firebag construction, along with its Voyageur upgrader. A Suncor spokesman says no decision on Voyageur will be made until the Suncor Petro-Can merger is finalized, which is expected to take place in the third quarter of 2009. If the deal goes ahead, the newly merged companies will become the fifth largest energy company in North America overall.

ERCB Oilsands used to be all about surface mining, but the future focus is in-situ extraction and bitumen upgrading, says the Energy Resources Conservation Board (ERCB) annual report Alberta Reserves 2008 and Supply/Demand Outlook 2009-2018. Investment in much-needed pipeline infrastructure to move the product to new and existing markets is also anticipated. The report shows that in 2008, bitumen production decreased by one per cent from 2007. Bitumen production last year averaged 1.31 million barrels per day. The ERCB expects annual bitumen production to increase

22 Oil & Gas Network, August 2009

to one billion barrels, or three million barrels per day, by 2018. It is basing its analysis on the expectation that crude oil prices in North America will continue to be volatile, averaging US$55 per barrel in 2009 and rising steadily to an average of US$120 per barrel by 2018. The U.S. economy is going to continue to heavily influence activity in Alberta’s energy sector since it is the largest importer of Alberta’s fossil fuels, states the Supply/Demand Outlook report. Alberta’s economy is expected to contract in 2009 but to

continue to be among the nation’s best performers from 2010 onward. The positive economic outlook will continue to contribute to excellent job prospects, low levels of unemployment, real increases in average employment earnings, and growth in personal disposable income. The ERCB expects the high costs related to construction investment, such as material, labour, and transportation, to decrease in 2009. The recent cancellation and deferral of projects should keep costs lower than what Alberta has experienced in the past few years.

The Eco Environmental Solution for Expedient Construction of Helicopter Landing Pads Article by Daniel Senf, PE, CPESC and Patricia Stelter, Presto Geosystems Environmental and Other Challenges As oil exploration efforts expand around the world, balancing the need to access land while adhering to environmental regulations and maintaining a minimal footprint can be a challenge. Access and transportation of materials into oil, gas, and mineral exploration sites create logistical challenges

that significantly impact overall project costs. This is especially true in remote sites, where transportation of materials is most commonly done via helicopter.The requirements and costs associated with transportation of the helipad materials are many times the single greatest cost item in developing the site. Therefore, the number of trips the helicopter must make to deliver all materials and labor crew into the site is directly related to the weight of the helipad materials. One trip with all materials and the installation crew is most costeffective. In addition, environmental regulations may restrict or limit materials deemed suitable for use in certain environments, climates or geographical areas. In many areas, helipads are developed in environmentally-sensitive or protected areas where minimal negative environmental impact is required. Materials that are brought in must be completely removable when the site is closed and may also need to meet other requirements: 1) must be chemical and weather-resistant, and able to withstand the effects of harsh climatic conditions (i.e. tropical, arid, arctic, high elevation), 2) be effective with varying and often unstable soils, 3) be removable and reusable (if required) and 4) require minimum maintenance.

The GeoTerra Mat Solution A proven system for constructing helipads that complies with all of the above requirements has been successfully employed for not only constructing helipads, but also for oil drilling platforms, construction access roads and equipment storage. The Presto GeoTerra® system is a highly cost-effective structural mat structure that exhibits the following characteristics: Exceptional material performance and adaptability:The GeoTerra system is manufactured from high strength, durable polyethylene resistant to industrial chemicals and inert to natural elements. The structural units are designed to support loads over very poor soil surfaces and can be assembled to meet all project size requirements. The system’s PadLocTM connection device allows for assembly of the units to the required mat size, and disconnection of the mats for removal and reuse. Low material weight and delivery costs: GeoTerra units are lightweight and can be preassembled into larger mats off-site and transported to the installation site with minimal cost.

24 Oil & Gas Network, August 2009

Ease of installation, removal and recovery: Once on site, the mat system can be installed quickly using any available unskilled labor with minimal training. Once no longer needed, the system can be quickly disassembled and readied for extraction from the site, reused on the same site or stored and used on future sites. Environmentally-friendly: The GeoTerra system can structurally stabilize surface soils making development of vegetated surfaces possible as it does not impede surface drainage. Impact-absorbing surface: The GeoTerra system’s non-rigid surface absorbs dampening energy during touchdown. The impact-absorbing surface results in less stress accumulation for the mechanical and structural components of the helicopter as well as lower impact to the personnel within the helicopter. Safe surface prevents debris movement: A helipad system which reduces or prevents particles from becoming airborne is essential. Airborne particles can be dangerous to ground personnel near the site during landing and takeoff of the helicopter as well as harmful to the engines of the helicopter when drawn into the air- intake of the helicopter. Also of concern is the potential visibility reduction created by swirling materials upon takeoff and landing.The GeoTerra system completely separates the underlying soils over which it is installed from the surface thereby preventing movement of typical surface debris associated with non-stabilized surfaces. Used on several remote Amazon Basin oil exploration and production sites, the GeoTerra structural mat system was ideal for the harsh environment and proved successful in creating low-impact, low-cost, and highly-effective helipads that met all of the environmental and logistical criteria.

GoExpo Heavy Oil the Future of Alberta? GO EXPO By Seema Dhawan etrobank offers a solution to increase production of heavy oil in a demanding oil industry that caters to a global market. The solution is producing more heavy oil.“There is probably three times of heavy oil in the world compared to light to medium oil,” said Chris Bloomer, SVP and COO Heavy Oil, Director of Petrobank. A fundamentally technology driven company, Petrobank is moving beyond the pilot stage of their technology THAI™ and are in the feed engineering stage of their product, now moving to commercial. THAI™ is an evolutionary new configuration for in-situ combustion which combines a horizontal production well with a vertical air injection well placed at the toe. “We have basically proven in the past three years [why] we use this technology and demonstrated it,” said Bloomer. “It’s a heavy world going forward, it’s all about heavy oil,” he added. The system designed by Petrobank has no corrosion in the pipes making it very straightforward. It has no delay,“we inject the air and get the combustion,” said Bloomer. The process does not use pumps and works completely on gas pressures. The line drive combustion is ideal for oil. Its horizontal design results in oil having a lower permeable point. Bloomer said Petrobank knows conclusively that air in equal’s air out daily in their system. The production is at approximately 12 degrees API and therefore has very low viscosity. “This is dramatic, day in day out pipe line spec oil,” said Bloomer.“[This is the] only place in the world where this is being done,” he added. The THAI™ system also has lower environmental impact because of its negligible fresh water usage, 50 per cent less greenhouse gas emissions, smaller surface footprint and easier reclamation. Still a technology company, Petrobank is looking at enhancing creative technology. “We want to build an integrated technology that has long term sustainability,” said Bloomer. “This is cookie card, design one build away,” he added.

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Our Planet: Small, Flat, Smart GO EXPO By Seema Dhawan BM gave a glimpse of what they call a smarter planet, at the gas and oil exposition this year. The world is smaller and flatter and this evolution to a smarter planet has impacted our ability to deal with goods and services. Steve Edwards, a Partner of IBM Global Business Services, said the use of interconnected technologies is going to change the world. A global world means frozen credit markets and limited access to capital, economic downturn and future uncertainty, concern for climate change and volatility in price and demand for energy worldwide. There is little doubt that the world is connected economically, socially and technically. “Globalization produces many benefits but challenges as well,” said Edwards. In a new world of interconnectedness the need for progress is clear. On an average it takes 90,000 man hours to execute turnaround effort every two years on an offshore platform. By adopting best in class asset management strategies the amount of man hours spend can be reduced by 10 per cent. New technologies that can make seismic mapping efficient by 85 per cent, increase 1.5 per cent of oil recovery and improve asset utilization by 10 per cent also exist. The three key factors to be successful in these changing times are to meet the worlds growing requirements of energy, energy affordability and environmental impact. IBM emphasizes the need to transform raw data into actionable insight. To do so companies need to become instrumented, interconnected and intelligent. There are now 1 billion transistors for each person on the planet. “We have an internet community of one billion people, we have four billion mobile phone subscribers,” said Edwards. This technology can then mould itself to a consumers need and help connect with others in entirely new ways. The intelligence then propels the system further, bringing it all together. “What makes it the mark solution is the intelligence, it is the next step we need to make,” he said. Using intelligent technology also enables companies to make quick and accurate changes to plans and ensures better results by predicting and optimizing for future events. Adapting this technology is risk free and many companies are following IBM’s footsteps, some of which have collaborated with IBM.

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Continued from page 25 Calgary can speed up its ability to do reservoir modeling by five to fifteen per cent. This is important to ensure global supply of [oil], retain decade’s worth of expertise and because it is possible to do some of these things now. “You can first time really look at a range of operations and fields, something that is actually very hard to do,” said Edwards. IBM invites companies as they move forward to harness “the ability to make the world smarter and [an] easier place to live,” he added.

SAGD Goes Green GO EXPO By Seema Dhawan fina Energy’s technology may be the answer for making SAGD green in a world where being environmentally friendly is becoming increasingly important. “We are looking at developing a commercial prototype,” says Guido Bachmann, CEO of Afina Energy. SAGD can be green, says Bachmann, and should be in light of the continuous negative attention the oil and gas industry receives. Though the “dirty oil card” will continue he says. “SAGD producers have to think about this like energy producers need to think of global warming,” he says. It does not matter if global warming is happening or not when a large population believes it, therefore action must be taken.“Here we go, it’s starting, and it’s starting now,” he added. Post carbon removal is too costly making pre carbon removal the easier option. The BioSyn Gasification Process, a Canadian developed technology, reduces environmental impact in SAGD operations via low severity gasification. The process goes through thermal oxidization of feedstock. “It[the process] does reduce environmental impact,” said Bachmann. The cool down and heating session of this technology is significantly less in comparison with current technologies. The expected efficiency of the Afina system is approximately 50 per cent higher with much lower utility and operation costs as well. This system requires 1000kPa of pressure compared to the current average requirements of 10,000 kPa. “[The] Gasification process is not in itself enough,” said Bachmann. An additional oil processing island would remove the top end of the diluent and the bottom end of oil. The recovered diluent would be sent back to SAGD. The systems modules are sized for 10,000 BDP but can be smaller or larger, using multiple modes, if necessary. At this point a consumer of this system can decide what they want to do with the syngas. By using this process companies can acquire gas credits and avoid 90 per cent of carbon emissions in comparison to natural gas. Almost all of the CO2 of syngas is removed in this process. Bachmann predicts that conservation of water will be the next concern after carbon emissions. “Water is even more important,” he said. Not only does the low severity gasification to SAGD significantly reduce carbon emissions it also reduces waste water disposal, diluent usage and associate transport, energy intensity of SAGD operations, and gives producers the ability to produce the environmental products from syngas.

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Continued from page 7 half of 2009, producers paid the Alberta government an average of $137 per hectare for petroleum and natural gas rights versus $307 per hectare in the first six months of last year.

Climate Change Canada’s climate change plan aims to reduce the country’s total greenhouse gas (GHG) emissions by 20% from 2006 levels by 2020 -- and by 60-70% by 2050. Survey respondents indicated they are taking a number of steps to respond to the issue of climate change, and, within the next 12 months, 40% will make strategic investments to lower GHG emissions, 35% will adopt more rigorous risk management processes, 34% plan to optimize their supply chain management and 32% anticipate deploying new technologies “All Canadian oil and gas producers -- from small juniors to trusts to large integrated companies – are affected by a list of growing concerns related to the economic downturn: volatile and weakened commodity prices, input costs misaligned with current prices, changing royalty situations and the disruption of capital markets,” says Stephen Marsters, Editorial Director at JuneWarren-Nickle’s Energy Group.“Respondents to the Canadian Energy Survey provided detail on the state of the industry, their own set of challenges as well as key drivers affecting growth and we felt it was important to provide this forward-looking view of the industry.”

Methodology and Demographics The 2009 Canadian Energy Survey contains results from an online survey, conducted by PricewaterhouseCoopers and JuneWarren-Nickle’s Energy Group during the 22-day period from May 25 to June 15, 2009, to better understand issues currently impacting the industry. Close to 85% of the 140 respondents fill senior roles within the energy sector (49% in a leadership role; 35% in a managerial role), with the balance comprising employees and consultants. The majority of respondents work for exploration and production (E&P) companies that produce a mix of natural gas and crude oil. Just over 50% of respondents reported their company’s annual revenues at more than $500 million, with about 17% listing revenues at $100 million to $500 million per year, and close to 16% said annual revenues were $10 million to $100 million. About 15% of respondents said revenues were $5 million or less per year. For more information, please visit www.pwc.com/ca/energy.

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Oil and Gas Price Forecaster Cautions Against False Hope Recent rise in crude oil price not driven by supply and demand fundamentals algary, AB, July 6, 2009 – In its June 30, 2009 oil and gas price forecast, AJM Petroleum Consultants cautions against false hope driven by the recent rally in the crude oil price. While AJM economist and Vice President Operations Ralph Glass still sees conditions setting up for a longer-term recovery in Alberta into 2010, he believes the rise in crude oil price over the past few months has been driven more by speculation and currency markets than by a real shift in supply and demand. “As the US dollar has dropped in relation to the euro, the crude oil price has risen correspondingly,” said Mr. Glass. “When the US dollar begins to decline, money traders start moving dollars into commodities like crude oil.This can influence the crude oil price even though demand has not changed. In fact, we haven’t seen any indication of an increase in demand for crude oil, other than speculation, since demand dropped off as the recession took hold in October 2008.” Mr. Glass believes that, until such time as there is an indication of a sustained US recovery that would affect crude oil demand – and until decreased drilling brings about a production decline in natural gas – current price increases may be a short-term phenomenon. A similar situation occurred in June 2008 when speculation, rather than a sustainable supply and demand equation, drove prices. With this in mind, AJM’s current price forecast shows crude oil prices in constant dollars based on a WTI forecast of US$65.00/bbl for 2009, rising to US$70.00/bbl in 2010, then reaching US$100.00/bbl by 2016 and holding for the balance of the forecast. The US NYMEX natural gas price in constant dollars is expected to average US$4.50/Mcf in 2009, rising with oil to a long-term price in 2016 of US$9.00/Mcf. The Canadian priced AECO forecast, which has been cut by $0.50/Mcf for the first four years of the forecast to reflect Canadian natural gas being supplanted by US shale gas, is expected to average Cdn$4.50/Mcf in 2009 rising to Cdn$8.00/Mcf in 2016. Complete forecast tables, commentary and documentation for AJM’s June 30, 2009 Price Forecast are available for download at www.ajmpetroleumconsultants.com. AJM Petroleum Consultants, a privately owned Calgary-based company, has extensive experience in exploration prospect reviews, basin evaluation studies, and reserve evaluations including evaluations of the unconventional reserves and resources of tight gas, shale gas, coalbed methane, bitumen and heavy oil. With a staff of more than 60 engineers, geologists and technicians, AJM consults for clients including active oil and gas exploration and production companies, natural gas transmission companies, regulatory bodies, financial houses, banks and investment analysts in Western Canada, North America and around the world.

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‘Canadian Gas at a Cross Roads’ Options for Producers to Preserve Value! assive value destruction is occurring for the shareholder, or unit holder, for each Mcf of gas produced today at low prices. Core gas reserves are being sold/depleted that simply cannot be replaced by the cash generated. While Oil prices have recovered very quickly from their dramatic plunge, Gas prices remain extremely low. At a price of C$3/Mcf at AECO, gas is selling for a 2/3 discount to oil --- disconnected from the traditional oil/gas price relationship. For over 3 years, Ziff Energy has voiced its concern regarding the dire economics of new gas in Western Canada. The chart below shows an increasing ‘lost Value’ gap between producers’ average full cycle cost to add new gas, and what the market is willing to pay.

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Seeing the large gap in gas vs. oil values – the largest in many years, Ziff Energy undertook research to compare the fiscal results of ‘Gas vs. Oil’ production at current price levels for a set of mainly oil producers vs. ‘pure’ gas producers. This represents today’s economics.

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To validate our understanding, last year Ziff Energy undertook and released a major study on the economics of new gas in basins across all North America, including LNG and Northern Gas (‘Economic Ranking of North American Gas Basins’). The results were even more dramatic than first thought: whereas a US study in 2007 informed the Alberta Government that Canadian gas plays were among the most economic in North America, Ziff Energy found the opposite, as the next Chart confirms. (A later study by Canada’s National Energy Board, “Energy Brief – Natural Gas Supply Costs in Western Canada in 2007”, Sept. 2009, reported similar high costs for most WCSB plays).

The drop in Alberta drilling, land bonuses, seismic activity etc. validates our analysis. Today, the Canadian Gas industry is far different than 2 decades ago. Paul Ziff, CEO says: “First, WCSB gas production has peaked --- 8 years ago, for conventional production. Unconventional gas (Tight, CBM, & Shale) is moderating the Western Canada decline, but not reversing it. Second, the Gas Reserve Life (or Reserves to Production Ratio) has plummeted from 20+ years to below 9 years, well below the US average.” Oil & Gas Network, August 2009 27

Gas Producers are retaining a perilously low amount of cash flow, and every Mcf produced generates a large loss. We do note that Interest, G&A, Processing & Transportation (if firm service) and at least half of, Operating costs are fixed. Royalty cost drops right away --- Drilling and Operating costs are much ‘stickier’ on the way down.

With an average Gas Reserve Life under 9 years, Gas Producers need to replace 12% of their reserves each year, just to sustain current production. The ‘Iceberg’ analogy below shows that the cost to find & develop new gas averages $3.50/Mcf, and the current ‘full cycle’ cost is $8/Mcf (this will gradually moderate with lower levels of activity in the basin).

Paul Ziff concludes: “Massive value destruction is occurring for the shareholder, or unit holder, for each Mcf of gas produced today. Core gas reserves are being sold/depleted at market prices that simply cannot be replaced by the cash generated --- so producers’ reserve base shrinks, and in the near future more equity, or debt will need to be issued to fund replacing the gas produced today”. PRESERVING VALUE Ziff Energy believes that there are solutions to preserve the Gas Producers’ value, and sustain the Western Canada Gas Industry. The traditional ‘tools’ for a gas Producer are Fundamental and Financial.

Fundamental: 1. Rigorous and persistent focus to be Low Cost Producer (driller, finder, operator); annually independently validate progress (similar to reserve & financial audits)

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• logically a quarter (25%) of Gas Producers can be ‘Top Quartile’; but three quarters (75%) claim to be! 2. Reduce Capital Spending (CapEx) to match realistic expected Cash Flow • an operators reserves are ‘cannibalized’ (i.e. the reserve base is produced at a loss, and the borrowing base is reduced, decreasing borrowing amounts --- a ‘death spiral’) • this pattern, everyone spending cash flow when prices are high, fuels inflation of land costs & service costs, especially in Canada, and the Deepwater Gulf of Mexico 3. Shift Spending Focus from Gas to Oil • Conventional oil prospectivity in Western Canada is limited – there are not many oil plays “waiting on the shelf”, especially for ‘pure’ gas producers.

Financial: 1. Buy Back Shares (‘Financial Engineering’, to meet Analyst expectations) Majors and the largest Independents do this – but it doesn’t add reserves; there is no impact on organic sustainability of the industry, or those companies. And aren’t those shares cheaper today?? 2. Hedging -- this can be a powerful tool to give predictability of distributions or dividends and capital programs. Hedging is for a short duration (e.g. a year) --- hedges need to be replaced, although NYMEX is always optimistic! The goal is not to “beat the house”, i.e. one is not trying to outsmart the market, but to generate predictability for investors and create a sustainable spending program. Executives often complain that they get no credit from Analysts for good hedges – those same analysts should look in the mirror at the success of their own institutions, before casting stones. What is the ‘win’ percentage of any top sports team? 3. Buy Reserves (when valuations are attractive) – good for an individual trust (very active) or company; but does not increase the overall basin reserves, and therefore the industry’s ‘sustainability’.

New Options for Gas Sustanability: Ziff Energy believes the traditional options are not sufficient for today’s critical situation, and suggest 3 key options be considered. Paul Ziff comments: “First, shut-in some gas production, essentially ‘holding gas reserves’ until the market will pay a decent price, sufficient (or closer than now) to replace those reserves, to sustain your Company’s future.” [Chesapeake, the 2nd largest US gas producer (despite high debt) does this regularly, and EnCana and Paramount have just announced (June 15) some modest shut-ins. Some operators face greater challengers to do this: e.g. Trusts or high debt gas producers.] “In our opinion, the Shareholder or Unit holder is not well-served by the Operator giving away their gas reserves --- there is little or no contribution to the Replacement Cost, so one is only postponing the day of reckoning. The Financial equivalent is issuing new shares not at the market price, but at a large discount! Management’s role is to ‘lead’ (please see Ziff Energy’s ‘Comment’ Newsletter, Spring 2009 http://www.ziffenergy.com/download/newsletter/comment2009-03.pdf) and communicate to the investors, and bankers; the reason: to preserve shareholder value.”

suppliers to jointly reduce costs, which leads to greater volume sales. The time may be somewhat early to develop these relationships with service companies --- we hear that costs are still higher in Western Canada as compared to the US. For unconventional resource plays, supplies of some key services and goods can delay development. Chesapeake solved this by buying into the service companies. Another option is a long term agreement, with fixed prices (a ‘service cost hedge’). b. Banks & Investment Firms Last year some Canadian banks were forecasting a $150-200/barrel oil price. Now they have slashed their price forecasts, with the effect of curtailing credit at exactly the time when its expansion would allow E & P companies to create higher value opportunities. While ‘CYA’ (or ‘CYCR’ – Cover Your Credit Rating) and higher facility fees are ‘least risk’ for lenders in the short term, they do not represent a collaborative long term relationship. Does anyone really doubt that energy prices will rise? Economic growth does not occur without energy; cars still run on gasoline, and North American winters are still cold! Energy risk is low. Investment Analysts are too prone to ‘flavour of the year’ themes such as Shale gas & Bakken oil this year, previously SAGD, Tight Gas, CBM, etc. This reflects the exaggerated expectations of Wall Street/Bay Street for ‘unreal’ returns that are multiples of the inflation rate. This psychology led to the Enron & gas marketer ‘melt- downs’, the creation of nontransparent securitization markets, and big risks and speculation being taken by pension funds such as La Caisse [not to mention crooks like Madoff]. The record of many of these same ‘investment banks’ (notably American, like Lehman, Goldman, etc.) speaks for itself. However, analysts penalize companies that reduce production/cash flow on a short term basis, to preserve value. The best analysts focus more on Management’s long term strategy and execution. But most analysts focus on ‘growth for growth’s sake’, e.g. producing more gas at current prices, and very short term cash flow. Considering that analysts give no credit for positive hedges, this is illogical. The quick ‘grow & flip’ (i.e. sell out) scenario is gone --- traditional value is ‘in’.

Several analogies: • Natural Gas Liquids Business: marketers store in summer, to take advantage of higher winter prices. • Oil Marketers: were recently storing oil on tankers, waiting for oil prices to rebound [they did] • Gas Pipeline expansion from Western Canada -- 15 years ago the price of WCSB gas was very depressed, due to constrained pipeline capacity out of Western Canada. The combination of TCPL expansion, and the Producer-initiated Alliance Pipeline project expanded the ‘take-away’ capacity. The result was a dramatic decrease in the ‘basis differential’ (or discount), resulting in much higher Canadian gas prices. “Second, invest ‘counter the cycle’, over-spending Cash Flow when costs are low, and ‘lock in’ low F&D/Future DD&A (generates higher future profits); and under spend when costs are high A few companies are doing this: • well-funded Majors: - Exxon/Imperial at the Kearl Lake Oil Sands project, - BP for Tight Gas • Junior Celtic (despite debt) is a notable exception, taking advantage of the Alberta Drilling Relief Program to cut net gas Drilling costs by half, effectively reducing their F & D costs (and future DD&A). Companies with a demonstrated low cost resource play and low debt levels can easily pursue this strategy. This strategy would not apply to ‘early development’ resource plays (e.g. Horn River Shale, where costs are still high at this early development stage).” “Third, a New Relationships with Suppliers, Banks, & Government The conventional Western Canada Sedimentary Basin (WCSB) is mature and tired; not dead, but certainly not the lowest cost. The stakes are high. A collaborative strategy would require a new approach by Operators, Service companies, Banks, and Governments, to promote a sustainable gas future in Western Canada.” a. Suppliers (Drillers & Service Companies) The up & down cycles are harmful for capability -- staffing and even equipment. For Service companies (especially the Trusts), there is a Value to predictability and sustainability. Alliances/Gain sharing have been tried; while challenging, they can align Producer & Service company interests. One analogy would be US retail mega-marketers who lend their Efficiency specialists to Oil & Gas Network, August 2009 29

R&M Energy Systems’ SENTRY® Closure Features Innovative One-Piece Sea &M Energy Systems offers its latest, most technically advanced solution for pipeline and vessel closures. Marketed under the SENTRY® brand name, this non-threaded, internal door closure now features an innovative one-piece seal. This seal provides many features and benefits that are not available in other types of closures. The SENTRY closure’s one-piece seal: • Is molded in all sizes with no vulcanized splices • Is available in FKM (Viton), EDR FKM (Viton), NBR, or HNBR low temperature materials (other compounds are available upon request) • Features an anti-extrusion spring molded directly into the seal for easy installation and to ensure secure sealing Installation of the one-piece replacement seal is quicker than ever resulting in reduced maintenance time and lower incurred maintenance costs. All pressure-retaining components on the SENTRY Closure are manufactured from ASME SA designated materials. An improved hinge arrangement and a unique means of holding the locking segments in the open position, make operation of the SENTRY Closure smooth and easy. The innovative method of securing the Closure’s locking components to the door also helps to prevent the possibility of injury during pipeline or vessel servicing.

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Senior Advertising Sales Representative required The Oil & Gas Network has an opening on their sales team. If you are a dynamic individual with excellent communications skills, this is your chance to join a great organization. The successful applicant will be responsible for an active client list, developing new business, selling ad space in special features, online sales and providing ideas for Oil & Gas Network. You work well as a team player, have a positive attitude and an overwhelming desire to succeed. You have a proven track record of sales success and are able to work effectively to deadlines. OTHER QUALIFICATIONS INCLUDE: Self Motivated Effective time management Excellent verbal and written skills Creativity Computer skills Drivers license and vehicle General knowledge of the Oil & Gas industry

To respond to this opportunity e-mail your resume to John Robertsen at [email protected]. All resumes must be received by Sept 4th, 2009 Thanks you in advance for all resumes. Only those candidates that receive interviews will be contacted.

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