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August 2010 Volume 11, Number 4 www.oilgas.net

Minimizing Risk, Maximizing Recovery in Oil Sands With Canada’s largest team of dedicated oil sands experts, we’re ready with the proven technologies you need to increase your returns in some of your most demanding applications, including ultra-high temperature SAGD wells. We can help you:

� ensure optimal cap rock integrity using our proprietary Segmented Bond Tool � optimize production parameters by accurately measuring downhole pressures and temperature with

the only fiber optic technology pre-qualified for ultra-high temperatures � boost recovery using our line of electrical submersible pumps (ESP), tested to 250°C and now

installed in several operations.

And, when faced with fluid separation and water treatment challenges, our proven chemical additives and application expertise can help you better manage operational, mechanical and chemical costs.

Contact your Baker Hughes representative at 403.537.3400 or visit booth #3401 at the Oil Sands Trade Show and Conference in Fort McMurray, September 14-15, 2010.

We can help minimize your oil sands risks while maximizing both your efficiency and ultimate recovery.

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A d v a n c i n g R e s e r v o i r P e r f o r m a n c e©

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August 2010 Volume 11, Number 4

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CONTENTS

Minimizing Risk, Maximizing Recovery in Oil Sands With Canada’s largest team of dedicated oil sands experts, we’re ready with the proven technologies you need to increase your returns in some of your most demanding applications, including ultra-high temperature SAGD wells. We can help you:

� ensure optimal cap rock integrity using our proprietary Segmented Bond Tool � optimize production parameters by accurately measuring downhole pressures and temperature with

the only fiber optic technology pre-qualified for ultra-high temperatures � boost recovery using our line of electrical submersible pumps (ESP), tested to 250°C and now

installed in several operations.

And, when faced with fluid separation and water treatment challenges, our proven chemical additives and application expertise can help you better manage operational, mechanical and chemical costs.

Contact your Baker Hughes representative at 403.537.3400 or visit booth #3401 at the Oil Sands Trade Show and Conference in Fort McMurray, September 14-15, 2010.

We can help minimize your oil sands risks while maximizing both your efficiency and ultimate recovery.

www.bakerhughes.com/canada

A d v a n c i n g R e s e r v o i r P e r f o r m a n c e

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5 Nightmare Nearing the End

7 PSAC’s Public Outreach Program – Can It Make a Difference?

9 Oil and gas price forecaster predicts relative stability despite US Gulf disaster, worldwide economic and environmental pressures

9 Alberta is back – independent evaluation shows province’s latest royalty regime is among the most competitive in North America

10 New moratorium: mostly the same, some differencesa

13 Junior Roughneck Camp 2010

13 Lea-der Coatings Launch Swift Environmental Products at Global Petroleum Show

14 Trinidad’s Technological Innovation Ahead of the Game

15 Innovation Key to Kudu’s Success

16 Canadian Conventional Gas at a Crossroads

23 G. Richard Drilling Celebrates 25 Years

26 Oil sands Production Projects at a Glance

28 Canada’s energy sector on the rebound after a difficult 2009, according to PricewaterhouseCoopers

34 Cellular provides cost-effective alternative to satellite, improving line integrity for a midstream oil company

36 Oilfield Automation with MRD-310 industrial 3G router

36 Intelligent Gateway from HMS Industrial Networks connects SAE J1939 networks to Siemens PLC systems

37 The World is Fractal

38 All Terrain Road Gains Popularity as Attitude Towards New Technologies Changes

39 Accu-Lift 10K Hydraulic Catwalk Provides Safety, Performance and Versatility

40 Emerson Revolutionizes Electronic Marshalling

42 Your Mission: Should You Decide to Accept It…

43 Benefits of Grooved Mechanical Piping in the Oilsand

44 BP Spill Prompts Canadian Review

44 Sewon Cellontech Hopes to Build Partnerships with Alberta’s Industry

46 ClearSCADA 2010 Features New Connectivity, Security, and System Support Functionality

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Nightmare Nearing the End In situations like the BP Gulf of Mexico oil spill, laughter may be the best medicine of all

As this is being written, the BP Deepwater Horizon well is still gushing. Completion of

the relief well, which should finally stop the flow of oil into the Gulf of Mexico, is still

more than a month away.

The media -- having recently declared that this tragic incident has now surpassed the

Exxon Valdez in the category of environmental catastrophe and Worst Oil/Resource Spill Ever

(WORSE) -- is starting to show signs of fatigue. Unfortunately for BP, Tony Hayward, Barack

Obama and the oil industry as a whole, there’s been little else in the news to take its place as

top story since the blow-out occurred in April.

This incident couldn’t have taken place at a worse time – not only was the offshore industry

began to see success in drilling deeper and into increasingly complex formations, it was also

seeking government and public support to lift moratoriums and open up new areas of explora-

tion. That’s not looking too good right now.

The public is understandably outraged by the devastation wrought by the spill. No amount

of PR is going to make people feel better until the operational issue is resolved. Nobody cares

about the technical details, they only want results and somebody needs to be held accountable.

Initially, it was just BP and they were an easy mark, considering its “Beyond Petroleum” mar-

keting promise focused on technological leadership and environmental stewardship, not to

mention its previous track record and British parentage -- 1776 all over again. A couple of

months in, the blame began to shift perceptibly to Obama’s democrats, so much so that it could

bring them down.

While it’s difficult to envision that anything positive will emerge from the spill other than a

profound and positive impact on crisis and reputation management planning, it’s been fascinat-

ing to watch this drama unfold on my big-screen TV. From a public relations perspective, I’ve

often been shocked at how one-sided, how out of control and how off-base the commentary

has been.

My enduring memory will probably be an episode of the Colbert Report where host Stephen

Colbert shows Obama how to get tough with BP by rolling up his sleeves and administering a

“beat down” to a Tony Hayward stand-in.

The scene begins with the host welcoming “Tony Hayward” to his show.

The actor repeats Hayward’s ill-advised comment as if he’s reading, woodenly and in a wimpy

British accent, from a script.

“Nobody cares about this incident more than me. I want my life back.”

To which Colbert grabs him by the scruff of the neck, pins him against the wall and throws

him down a flight of stairs. A stuffing dummy is then thrown off the roof and into the street

where he is run over repeatedly by an SUV driven by a sea turtle.

A CEOs worst nightmare indeed, but in situations as severe as this spill, sometimes the only

thing you can do is laugh. Humour is certainly a good remedy for the anger and frustration of

the public and should be looked at in that light.

Talk show hosts have been mercilessly in their attacks on BP and the government. A quick

Internet search reveals 3 pages of one-liners. With nothing left to say and no desire to ever see

Anderson Cooper’s face again, I’ll just conclude this column with a few of my favorites, bear-

ing in mind again the old axiom that when all else fails, laughter is, indeed, the best medicine.

“Have you been following the big oil spill in the Gulf of Mexico? Or as we now call it, the

Dead Sea.”

“This oil spill is affecting everybody. When I want to lunch this weekend and ordered the sea

bass, they asked if I wanted it regular or unleaded.”

“This is the worst thing to happen to beaches since the Speedo.”

“Here’s a little bit of good news. The Coast Guard says that BP is now catching up to 630,000

gallons of oil a day. The bad news is that they’re capturing it with pelicans.”

“There is so much oil and tar in the Gulf of Mexico, Cubans can now walk to Miami.”

“In a new interview, BP’s CEO said that the Gulf Coast oil spill is relatively tiny compared to

the ‘very big ocean.’ That’s like telling someone who’s just been shot not to worry about the

bullet because they’re really, really fat.”

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Since we last updated you on the progress of PSAC’s Public Outreach Pro-

gram, we’ve been busy rolling out some of the program’s initiatives. To briefly re-cap, the pur-pose of PSAC’s Public Outreach Program is to help strengthen indus-try’s social license to operate by re-establishing a strong relationship between industry and the public. Through communication and promotion of the indus-try, the program’s initiatives intend to help Canadians recognize the benefits our industry provides, and hope to turn around any nega-tive public opinion that could impede indus-try activity and growth. Program components will work to achieve the following:

Ensure that the industry is proactive and responsive regarding issues of public impor-tance;

Facilitate a process of communication and education between industry and the public;

Promote understanding of our industry and work to improve relationships with all stake-holders;

Address key issues within the industry including health, safety and the relationship between operators and service companies.

As PSAC President Roger Soucy com-mented when we announced our plans for the Public Outreach Program, “The Alberta Royalty Review of 2007 gave our industry a wake up call, telling us that we didn’t have quite the level of public support we thought we had. It’s clear that going forward, we need to pay much closer attention to the people living in the areas in which we operate.”

So we at PSAC have gotten down to busi-ness and following consultation with our members, our industry partners and the pub-lic, we’ve been rolling out some program components in advance of the next upswing in oilpatch activity.

1. Public Website: In April of this year, PSAC launched a new public website at www.oil-andgasinfo.ca. The site answers basic ques-tions about Canada’s oil and gas industry; questions like: How is the price of gasoline set? How does the oil and gas industry work? What products are made from oil and gas? PSAC created the site in response to input received from our public and member com-pany employee surveys. This input told us that many people don’t really know as much as they’d like to about how the oil and gas indus-try works and what value it offers Canadians. Even many service sector employees admit-ted they would like to know more about the industry, especially beyond their own area of expertise. The site also links to more detailed websites, and encourages discussion through questions on our “Let’s Talk” page. As PSAC receives feedback and questions from users, we will build on the foundational content currently on the site.

2. PatchWorks: In June, PSAC launched PatchWorks – a

series of short, monthly articles that provide

information, facts and statistics to industry employ-ees. In addition to monthly distribu-tion, PatchWorks will also be housed

on its own page at www.oilandgasinfo.ca.

Following the PSAC Member Employee Survey we conducted in 2008, we found out that many member com-pany employees feel ill-equipped to answer some of the industry-related questions asked of them by friends and family, and that they’d like to have access to more information about the industry and how it works. In just a single page, each issue of PatchWorks answers a commonly asked question about the oilpatch, provides examples, and points readers to more information.

Some of the upcoming topics we’ll address in PatchWorks include industry’s effects on quality of life; industry’s economic contri-butions; the structure of the industry and sectors involved; the cyclical nature of the industry – booms and busts; light vs. heavy oil; safety; training and competency programs; jobs and careers, and much more. And again, we are encouraging PatchWorks readers to send their questions and topic ideas to us so that we can address them.

3. Community Partners: PSAC, together with our industry partners, will be launching a program in September called Community Partners. This in-the-field courtesy program is being presented as an industry-wide initia-tive that will provide materials and tools to remind industry employees about courteous behaviour when working in communities.

Most of us would agree that the behaviour of personnel in the field when dealing with landowners and communities has a direct bearing on the public’s perception of our industry. Community Partners is a program that will serve to remind employees they are ambassadors for our industry, and through the use of various materials and tools, will make it easy for them to follow guidelines for good behaviour when working in the field. Built on a foundation of understanding the concerns of community members in the areas in which we work, Community Partners will encour-age oil and gas workers and contractors to communicate openly with area residents, and effectively manage local disturbances related to oil and gas activity – dust, gates, garbage, noise, traffic safety and driving.

Prior to program planning, preliminary dis-cussions with PSAC member companies told us that developing one industry-wide pro-gram would promote consistency and be eas-ier for companies to implement, rather than having to follow a variety of programs devel-oped by individual oil and gas companies.

PSAC’s Public Outreach Program – Can It Make a Difference?Holly Kerr, Manager, Communications and Member Relations

Continues on page 37

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Despite reaction to the US Gulf disaster, ongoing environmental concerns with hydrocarbon extraction and calls for alter-

native energy sources, Calgary- based AJM Petro-leum Consultants has released a June 30, 2010 oil and gas price forecast that is relatively unchanged from the previous quarter.

“Commodities are in ‘wait and see’ mode both domestically and internationally,” said AJM econo-mist and Vice President Ralph Glass.

“The markets are waiting to see if an economic recovery will take hold or if a double- dip recession is in the cards. Continued oversupply of both natu-ral gas and crude oil, especially in North America, is also keeping prices steady.”

Both the tragic situation in the Gulf of Mexico and recent G8 and G20 Summits have raised a lot of calls to find alternative energy sources, particu-larly for oil.

Mr. Glass believes this would be an expensive challenge that not many of the world’s fragile econ-omies could currently withstand.

In the absence of any other viable sources of cheap energy to fuel the development of growing economies in the Middle East, China and India, the world is likely to remain reliant on hydrocarbons for the foreseeable future.

“In a free market economy, oil and gas invest-ment will go where there is profit to be made,” said Mr. Glass. “So, even if new regulations make deep water drilling in the Gulf of Mexico too expensive, if there is a demand for oil, that investment will go to other areas.

That doesn’t mean that industry shouldn’t pause, take a deep breath and reflect carefully on what we can do to address environmental and safety con-cerns while meeting world energy needs. I think that’s partly what we’re seeing right now.”

Based on a current review of available data, AJM anticipates that Edmonton Par Crudewill remain at Cdn$80.65/bbl for the balance of 2010, rising in real terms to Cdn$103.45 by 2016. West Texas Intermediate (WTI) is anticipated to remain at US$80.00/bbl reaching US$100.00/bbl in 2016.

AECO natural gas is anticipated to reach Cdn$4.80/Mcf over the last six months of 2010, ris-ing in real terms to Cdn$7.50/Mcf by 2020.

NYMEX natural gas for the balance of 2010 is predicted to be US$5.00/Mcf, witha US$0.90/Mcf increase over 2011, then rising to US$8.00/Mcf by 2020. Complete forecast tables, commentary and documentation for AJM’s June 30, 2010 Price Fore-casts are available for download atwww.ajmpetroleumconsultants.com.

Alberta is back – independent evaluation shows province’s latest royalty regime is among the most competitive in North America

A follow-up to a January shale gas evaluation that placed Alberta dead last in terms of economic competitiveness among five main operating areas in North America shows that now, with Alberta’s recently reworked royalty

framework, the province has moved from the worst to one of the best regimes in which to invest in emerging shale gas developments. “In terms of after-tax rate of return,” said Energy Navigator President Boyd Russell – who performed both eval-uations, “the most recent Alberta royalty framework represents one of the best opportunities across all jurisdictions at all prices. When you look at higher prices – one of the areas where Alberta’s previous royalty framework was widely criti-cized – there’s no question that the Alberta government has listened to industry and made appropriate adjustments to make Alberta one of the pre-eminent places for development.” In both evaluations, Mr. Russell examined the same multi-year, multi-well field that is typical of a development found in any of the five major North American jurisdictions including Alberta, British Columbia, Texas, Louisiana and Pennsylvania. The only difference between the first and second evaluations was the inclusion of the most recent Alberta royalty framework. Depending on gas price, the results show Alberta leading or running a close second in terms of key indicators such as: after-tax rate of return; royalties as a percentage of after-tax cash flow; after-tax cash flow; and supply cost or break-even cost. While BC’s Net Profit Royalty is more competitive for shale gas at lower prices, Alberta’s new regime is more competitive at higher prices. Mr. Russell believes that, since current low prices have all but halted conventional gas drilling (which repre-sents approx. 70 per cent of total gas supply), the industry will experience supply shortages leading to rising gas prices.

Oil and gas price forecaster predicts relative stability despite US Gulf disaster, worldwide economic and environmental pressures

10 Oil & Gas Network, August 2010

The US government on July 12 imposed a new moratorium that bans most new deepwa-ter drilling in the Gulf of Mexico until November 30. The new ban is almost identical to the one that idled 33 deepwater drilling operations when it was issued by President

Barack Obama on May 27. One key difference is that the old moratorium banned new deepwa-ter drilling in waters of 500 feet or deeper. The new ban does not use water depth as a criteria, but instead suspends activities on the basis of drilling configuration and technology.

Specifically, drilling is banned on rigs that use subsea blowout preventers or surface BOPs on floating rigs. Interior justified the new moratorium in part because of problems found on the blowout preventers attached tothe two relief wells BP is drilling to intercept and kill the Macondo well that blew out on April 20, resulting in the massive oil spill.

Interior said new, more sophisticated testing procedures developed as a result of what has been learned since the April 20 blowout have allowed investigators to spot potential problems in the BOPs. Those problems include several leaky valves that resulted in test failures of key components; a failure of the “deadman” system that was caused by the installation of a valve that was not supposed to be there; and a broken solenoid connection on one of the BOP’s con-trol pods that prevented the pod from closing one of the casing shear rams. Those problems have since been fixed and federal officials are keeping a close eye on the relief well activities, Interior Secretary Ken Salazar said in a statement released by the department. While the drill-ing ban is essentially the same as the previous one that was struck down by two federal court decisions, Salazar said his decision is based on new evidence that shows the industry is not capable of handling another major oil spill. The new moratorium also includes a mechanism for its early termination.

Salazar has ordered Michael Bromwich, the new head of the Bureau of Ocean Energy Man-agement, Regulation and Enforcement, to hold a series of public meetings with industry groups, scientists and the public. The results of those meetings could be used to modify the drill ban, Salazar said. “I remain open to modifying the new deepwater drilling suspensions based on new information,” Salazar said in a statement. “But industry must raise the bar on its practices and answer fundamental questions about deepwater safety, blowout prevention and contain-ment, and oil spill response.” Like with the previous moratorium, shallowwater drilling can con-tinue if drillers can meetrigorous new safety requirements. Deepwater production activities are also not included inthe moratorium. Work on the two Macondorelief wells can also continue.

Mixed reaction to new ruleReaction to the new moratorium was mixed. One analyst said removing the 500-foot dis-

tinction might actually make the new moratorium more restrictive. “In our view, if ‘floating vs. tethered’ is the distinction, the main point is that it isn’t very different!” Clearview Energy Partners analyst Kevin Book said in a July 12 report. “If anything, we would suggest that the new moratorium could be more restrictive, because some floating rigs occasionally work in shallow depths.” Speaking before the new moratorium was issued, Larry Dickerson, CEO of Diamond Offshore, said “anything would be good,” to give the industry more certainty.

Shallow-water drillers said they were unhappy with the new ban. They said vague guidelines from Interior have resulted in a de facto ban, despite the administration’s reassurance that shallow-water activities can continue. “The reality is that permits for shallow-water drilling are not proceeding despite the widespread efforts being made by the industry to honor the let-ter and spirit of new Interior regulatory standards as reflected in Notices to Leasees, or NTLs,” Randy Stilley, CEO of Seahawk Drilling, said in a statement.

At well, BP is optimisticWith fair weather to accommodate a weekend of hectic activity, BP appeared on the verge

July 12 of stopping the leak at its runaway Macondo exploration well in the Gulf of Mexico through installation of a cap that would either plug the well or allow for total containment. But the company stressed that any success with its new sealing cap at Macondo would not eliminate the need for completion of a relief well as the ultimate solution expected some time in August. And analysts at Houston-based Tudor Pickering Holt were quick to describe as a “long shot” the prospect for a total kill with the sealing cap that BP had positioned for placement by the end of the day. Before deciding its next step, BP will need to monitor well pressures through that cap for six to 48 hours, said BP Chief Operating Officer Doug Suttles during a press briefing to update on the multiple operations accomplished over the weekend. If the cap displays high-enough pressure readings, Suttles said engineers would view that as a sign of strong wellbore integrity with a wellbore capable of holding the oil down below the cap until the relief well can kill the well at its source. But Suttles said lower pressure readings would indi-cate problems in the wellbore and prompt installation of a complex containment system with the capacity to collect as much as 80,000 b/d of the leakingoil. Unless a government panel has severely underestimated the Macondo flow with a range of 35,000 to 60,000 b/d, the expanded BP containment system likely would capture most of the oil leaking from the well. “Until the job is complete, we have to recognize this is a complex operation,” Suttles warned. But he also described his confidence as “growing” after the successful installation July 11 of a transition spool as the foundation piece for the sealing cap device.

If successfully installed, BP’s complete containment system would move oil from connec-tions on the sides of Macondo’s malfunctioning blowout preventer and through the top of the BOP to an armada of vessels waiting on the surface to process it and move it to shore on shuttle tankers. BP and the US Coast Guard launched the sealing-cap installation ahead of schedule July 10 after learning they would have a window of fair weather for the next week that might not recur all summer. One of BP’s primary containment options had already been delayed by Hurricane Alex, and national incident commander Thad Allen, a retired Coast Guard admiral, decided to seize the opportunity of an accommodating weather window to move forward. But

the operation did not come without risks as BP was forced to remove its initial containment cap July 10, allowing an estimated 15,000 b/d of oil, which was formerly being collected, to flow again into the Gulf temporarily while preparing the BOP for installation of the sealing cap that was about to occur July 12. BP had estimated the entire sealing-cap operation would take from four to seven days, and Suttles said July 12 that still appeared to be an accurate projection.

At the same time over the weekend, BP also was working to connect the Helix Producer I floating production vessel to the BOP’s kill line as an enhancement that could add 25,000 b/d of capacity to the two-pronged system that had been diverting 25,000 b/d since its installation in June. That earlier system included the containment cap removed July 10 and a connection to the BOP’s choke line with the Helix Q4000 multipurpose vessel, which has been flaring about 7,000 b/d of oil as part of the containment effort. Under the new system, none of the oil would be flared as the Q4000 would depart and yield to other production vessels that now have arrived on the scene. Although BP had expected to have the Helix Producer operating by July 11, Suttles said that installation encountered two problems that delayed it for about a day. But BP did have the Helix Producer connection completed by midday July 12 and expected to see it ramp to full capacity in a few days. Collection through the Helix Producer and the Q4000 was scheduled to halt, however, during the pressure testing of the sealing cap, Suttles said.

One analyst has doubtsCommenting on BP’s ambitious plan for using the sealing cap as a plug, analysts at TPH said

in a report: “We think this is a long shot.” Elaborating, they warned: “There is significant risk that the larger casing would rupture near the surface of the well, resulting in an underground blow-out. In that bad, bad, bad scenario, oil and gas would crossflow from the Macondo reservoir, up the well and out into the shallow formations.” The TPH analysts have also said they believe the relief well has a 99% chance of success for permanently killing Macondo some time in August.

BP’s primary relief well has reached a depth of 17,840 feet, including 4,993 feet of water, and Suttles said he expects its casing operation to begin this weekend. Meanwhile, a second backup relief well has reached a total depth of 15,874 feet and will be halted there unless the primary relief well fails to intercept Macondo, Suttles said. “We remain on track to have the cap in place in the four-to-sevenday time frame,” said Suttles, summarizing the multiple operations under way since July 10. “We are on day three, and later today we’ll begin on the Helix Producer.”

Diamond moving more rigsThe lack of work in the Gulf of Mexico has forced Diamond Offshore to move another

deepwater rig from the Gulf of Mexico to Africa and a jackup rig to Brazil, Diamond Offshore Drilling CEO Larry Dickerson told the National Commission on the BP Deepwater Horizon Spill and Offshore Drilling July 12 during its first day of hearings in New Orleans. “It is not pos-sible to retain our assets” if they are idle, Dickerson told the seven-member panel. The Diamond Offshore rig moves follow an announcement late last week that Diamond is moving its Ocean Endeavor to Egypt. Dickerson, like many of those before and after, warned of the dire conse-quences a deepwater moratorium will have on the region. “I see a slow-motion domino” impact on the industry, with the end result being offshore companies moving out of the US. “We will have effectively given away a high-tech, highwage workforce that is US-dominated,” Dickerson said. The commission, appointed by President Barack Obama in May, will meet over the next six months on how to prevent and mitigate the impact of future spills from offshore drilling. Before the commission hearing began early July 12, former Senator Bob Graham, co-chair of the commission, said any changes to deepwater drilling or other laws would not come from the commission, but rather the appropriate federal agencies. While the commission was given the task of looking at how to prevent future spills, testimony July 12 was primarily from oil, fishing and tourism officials detailing the economic impact of the oil spill and the de facto deepwater drilling moratorium. The commission does not have subpoena power, nor did it require those who testified to swear in before giving testimony. Graham defended the commission’s decision to focus on the impacts of the spill instead of investigate the cause of the April 20 accident. “I wouldn’t be dismissive of the consequences,” he said, adding that the commission would later delve into the possible causes of the accident.

Late July 12, Diamond said in a statement that it will suspend its current commitment with Murphy Oil for the semisubmersible Ocean Confidence and has signed a new multi-well deal with the Arkansas-based integrated company that will send the rig to the Republic of Congo. Diamond said the rig left the US Gulf last weekend and should arrive on location within 60 days. The new deal is a three-well commitment, plus an option for additional work, and includes an obligation for Murphy to mobilize the rig to and from the Congo, said Diamond. The sus-pended contract with Murphy has been restructured into a one-year commitment in the Gulf that should resume when Murphy is satisfied it can obtain the necessary permits and can meet new regulatory requirements, said Diamond. The remaining one-year US Gulf contract and new overseas commitment should generate total revenue of roughly $234 million. Murphy had leased the rig in 2008 for four years at a dayrate just over $510,000.

Reports of the US government telling Exxon- Mobil it would not stand in the way of a take-over of BP were incorrect, a White House official said Monday. “We are not aware of any dis-cussions with Exxon on this subject,” the official, who asked not to be identified, said in an interview. The Times of London Sunday reported ExxonMobil had consulted the Obama Admin-istration about a possible takeover bid for BP, which has seen its stock hammered in the wake of the Macondo well spill, and was told it would not “stand in the way” of such a move. Any combination of two huge energy players would certainly come under antitrust scrutiny, both in the US and in the EU. ExxonMobil spokesman Alan Jeffers, in an email Monday, declined com-ment on the Times report, citing company policy against comments on “media reports, market rumors or speculation.”

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rock formations and discovering signs of crude oil through powerful microscopes. Make your own replica of fossils from animals that lived 350 million years ago. In the world’s largest drill bit take a virtual tour over a kilometer beneath the earth’s surface to see oil oozing out of the Devonian formation. What flows through a pipeline: how to connect them together and test for a leak?

For the 6th consecutive year the Leduc #1 Energy Discovery Centre offers this pro-gram, which is presented by professional educators. Youngsters explore the exciting world of Energy every summer at the Jr. Roughneck Camp. It is a full day of fun learning and discovering about the many aspects of the Energy Industry: from geology, surveying and petro-chemicals to oil field related equipment and a challenging scavenger hunt throughout the Heavy Oil

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Lea-der Coatings Launch Swift Environmental Products at Global Petroleum ShowBy Seema Dhawan

Lea-der Coatings (Lea-der) launched its Swift Environmental line of products at the Global Petroleum Show. The response has been overwhelming says, Darrell Demers, President of Lea-der.

Swift Clean, a rig floor cleaning wand, compliments the Global Petroleum Show’s 2010 theme of Game Changers, as it brings a new level of safety to the drill floor. Swift Clean is a vacuum unit that has a custom cleaning wand. It collects the vacuumed fluids to ensure they’re not on the ground or in the environment. The contained fluids can then be disposed of properly.

The safety benefits of the unit make it a huge success, says Demers.“There are no competitive products with it,” he adds.The wand servers triple functions as it vacuums, pressure washes and steams. It washes and vacuums up at the same time, says Demers.Users of the unit state that it is a remarkable product and very innovative, he adds.The unit is not only useable in the Oil and Gas industry, but in any industry where environ-

mental concerns are at the forefront.A spill can be vacuumed promptly and contained for proper disposal.A lot of chemical manufacturing companies are using the unit and Demers says he expects

other markets to benefit from the unit as well.

Junior Roughneck Camp 2010museum and its 13 acre yard.

A complete agenda, including a delicious and educational snack which has all the required ingredients make this program a success. The number of participants in each camp is 20 stu-dents, who may indeed propel to become our future engineers, scientists or business leaders in the Energy sector. For more information for August classes contact [email protected]


Trinidad’s Technological Innovation Ahead of the GameBy Seema Dhawan

Trinidad Drilling (Trinidad) stays ahead of the game in economically uncertain times by specializing in deep, technically-advanced drilling generally found in unconventional oil and gas plays.

“It’s been an opportunity for Trinidad to show the industry the types of equipment we have,” says Lisa Ciulka, Director of Investor Relations at Trinidad.

There has been advancements in technology in drilling so companies are now able to drill reserves that they dint have access to or were uneconomic, says Ciulka.

Now you can get economic amounts of gas from these properties and we have that type of equipment, she adds.

Trinidad’s technologies use sound attenuation resulting in less noise pollution. This is an important factor as they often work in locations close to communities and have worked in university parking lots and playgrounds before.

“We are able to reduce the noise and exhaust fumes from the engines that are running,” says Ciulka.

These technologies can also tap into power lines and don’t need to run off diesel fire genera-tors, making them environmentally friendlier.

The rig can be placed at a location and move itself to another location, eliminating the need to disassemble rigs and transport them from one location to the other.

“The rig just gets itself from one location to another,” says Ciulka, resulting in less down time.This is a significant advantage, especially in Canada, where road bans are in place during

specific times of the year, including spring where it gets too mucky.The rig can be put in at the beginning of spring and move itself around, and get more work

done.This also improves worker safety as they are less involved in dangerous activity.Trinidad uses AC power, which means that we have the ability to be more precise and have

more control over the drilling power. Customers are willing to pay more to have their rigs drilled more quickly and more efficiently,

says Ciulka.Trinidad has also recently integrated all of their equipment which “allows everything to talk

to each,” she adds.The driller can now be in the dog house and see exactly what is going on with the mudways

and engines and troubleshoot with the flick of a button. Ciulka says having real time data also helps immensely.

The company’s ability to see trends in the industry and be ahead of the change, have led to its success, she adds.


Innovation is the guiding philosophy behind the success at KUDU Industries Inc. (KUDU), says Ray Mills, CEO of KUDU.

KUDU is constantly improving their service and employees are very customer oriented. They know to apply the product and what kind of technology to bring together for a Progress-ing Cavity Pump (PCPs) to be successful for the customers, he adds.

The employees attitude of wanting to make customers suc-cessful and their training, knowledge and expertise continues to set them apart, Mills says.

“Our people are really dedicated to making the customers successful, I know that sounds cliché but we’ve got a great team of people,” he adds.

KUDU has recently also entered new markets including Romania, Oman and other parts of the Middle East.

I think one of the keys is the innovation on products, Mills says. A lot of innovation is required to address customer’s needs, he adds.

KUDU is currently advancing new Driveheads which are improved in terms of reliability, durability and also have a sim-plified design.

KUDU has also been looking to simplify their supply chain to reduce cost and save energy. The new Driveheads use fewer components and are soured locally or within Canada, says Mills.

All the components of a PCP are also recyclable.We are continuing to experiment PCP’s in high temperature

applications like SAGD, says Mills. “We’ve been able to extend pump life significantly,” he adds.Mills attributes process innovation to be the most impor-

tant factor that has led to KUDU’s success. “Process innovation is key to us, doing those things cost

effectively for customers,” he says.A key part of KUDU’s strategy is to have a sharp focus and

avoid distractions, says Mills. “We are focusing all our research and development dollars

on progressive pumps,” he adds.Automation has also enabled us to take the efficiency and

optimization of wells pumped with PCP to the next level, says Mills. It has maximized the efficiency of the pumping system as the pump isn’t pumping harder than needed or slower than possible.

“We’re looking at the health and the safety of the environ-ment,” he adds.

Innovation Key to Kudu’s SuccessBy Seema Dhawan


For each Mcf of gas produced at today’s low natural gas prices, valuable gas reserves are being depleted that cannot be replaced by the cash flow generated. Ziff Energy believes the future of Canadian conventional gas is at a crossroads – can it be competitive, even with

royalty relief?The outcome has significant implications for all stakeholders in the Canadian gas indus-

try, from Alberta provincial revenue and local community employment by service companies, through processors and pipelines, to end-users.

OIL: Gas Price RatioWhile oil prices have recovered very quickly from their dramatic plunge over a year ago

(prices today are $70-80, double the $39 in Feb. 2009), gas prices remain extremely low.For example gas selling at $4.20 HH vs. oil at $75, is a 1:18 ratio, vs. the 1:6 heat value (at

market). Figure 1 shows the large discount of gas to oil price; based on current forward oil and gas strip prices, this large discount will continue, imposing severe financial hardship on gas producers. We refer to this as a ‘gas price meltdown’.

Historically, the price ratio of oil to gas ranged from 8:1 to 10:1, a moderate discount for gas.In a worst-case scenario in the past, the price ratio has risen to 12 or 15:1. However, when

the price of oil pushes past $80 a barrel at the same time that gas prices are hovering at around $4/Mcf, the ratio rises to over 20:1, a huge discount in the price of gas (to the particular benefit of SAGD/oil

sands producers, U.S. mid-stream ‘keep whole’ processors, and all gas consumers). In Western Canada, producers are increasingly shifting drilling activity towards oil (to the extent they can); even with Alberta gas drilling and royalty incentives, pure gas drilling remains very depressed, and conventional gas reserves will decline.

Full Cycle Cost for GasCurrently it’s much better

to be a McDonald’s than an explorer for new gas: sell-ing a hamburger for $3 is far more profitable than sell-ing natural gas for US$4+/Mcf. Input costs for the back-yard do-ityourself hamburger are just $1.25, whereas full cycle input costs in Q4 2007 for new gas were about $7/Mcf (for royalties/produc-tion taxes, operating costs, finding & development expenses, overhead, return to investors, & transportation costs). Even now, full cycle gas costs, as measured in Ziff Energy’s 2nd Economic Ranking of North America Gas Basins assessment (April 2010), are US$5.60/Mcf for North America, well above the 2009 average Henry Hub gas price. Figure 2 contrasts the traditional hamburger cost to the new North American natural gas “hamburger” cost in Q4 2007 and now.

Western Canada Full Cycle CostsWestern Canada’s Gas industry has changed significantly in the past decade. Paul Ziff, CEO

notes:“WCSB conventional gas production peaked at the turn of the millennium.Unconventional gas (Horn River Gas Shale, Montney Tight/Shale Gas,and Horseshoe Canyon CBM) are moderating the Western Canada decline, but are not arrest-

ing it, which means the conventional gas industry is shrinking.The ratio of proven gas reserves to current production, commonly referred to as the WCSB

“Reserve Life Index (RLI)”, has eroded to less than 8 years (from more than 20 years at deregula-tion), 37% lower than the U.S. (12.5 year RLI )”.

At current gas prices, Western Canada Conventional Gas Producers are challenged ---- every Mcf produced generates a large financial loss [due to high unit DD&A (Depreciation, Depletion, & Amortization)].

Figure 3 illustrates the full cycle gas cost of new gas in Western Canada. Note the consistent and prolonged value gap (red hatch area) that gas producers are experiencing. Even with the Alberta and B.C. Government royalty adjustments included (which are significant and quite helpful), the average cost structure is too high relative to the gas price. The Canadian average new gas cost is estimated at Cdn$6.85/Mcf1, 7% higher than the North America average of US$5.60/Mcf (both referenced to Henry Hub).

Shrinking FortunesWith an 8 year RLI, each year Canadian gas producers need to replace 20% of their produc-

tion and 12% of their reserves, just to replace current gas production. Figure 4 illustrates the ‘Iceberg’ analogy and shows that the cost to find, develop, and produce (‘full cycle’ gas cost, referenced to

Henry Hub) new Western Canada gas averages Cdn$6.85/Mcf2 (US$6.00)

Canadian Conventional Gas at a Crossroads

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su ered by you, or by any third party, from the use of these marketing materials (the “Materials”) if they have been modi� ed,

distorted, combined with third party content, or manipulated in whole or in part by any party other than JKM. Further, once the

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As the proven reserve base is produced into a low gas price environment, reserves are ‘can-nibalized’ to sustain production levels; but with low conventional gas drilling, the reserve base shrinks, thereby decreasing financial loan amounts, which can lead to a ‘death spiral’.

Figure 5, from Ziff Energy’s “Natural Gas Strategy” service3 for the top 20 producers, shows that the U.S. grew reserves last year (all additions were 1.7 times production), while Canada’s replacement was only a third of production. Additions from Drilling (i.e. excluding revisions) were 215% of production in the U.S., more than double 85% in Canada. The poor 2009 perfor-mance continues the poor trend: the Canadian gas reserve life (top 30 producers) has fallen to 7.9 years, the lowest ever and well below the U.S. gas reserve life of 12.5 years!

“Producers’ conventional gas reserve base is shrinking, and in the near future more equity or debt will be needed to fund replacing the gas produced today.”

Ziff Energy’s annual assessment of the industry gas reserve replacement rate is based on total annual proved reserve gas additions (discoveries and extensions, improved recoveries, and revi-sions) divided by the annual gas production.

The replacement rate does not include acquisitions or divestments, which do not add to total industry reserves

Data SourcesFigure 6 illustrates some of the types of cost data sources where Ziff Energy obtains its opera-

tions data (red studies; this approach is now used in 30 countries).

New capital, and the return on it, are two of the biggest cost categories. Figure 7 provides additional detail on the Finding and Development process that Ziff Energy uses. This Canadian study (red studies above), in its 24th year, is the longest running basin economics study in the world!

Canadian Conventional Gas Comparison to U.S. Gas PlaysZiff Energy recently completed (April 2010) its 2nd Economic Ranking of North American

Gas Basins. This study assesses the economics of new gas in basins across all North America; the challenges for Canadian new gas are even more dramatic than first thought. Paul Ziff concludes:

“Canadian conventional natural gas plays are again among the least economic in North Amer-ica”. Full cycle cost data for more than 60 gas plays in 2 dozen gas basins were analyzed and sorted to determine the economic rankings of North America’s gas basins.

Figure 8 provides insight to the North American supply cost curve for new gas, and shows a range of $4 to $7 /Mcf being needed for new gas supplies. Most Canadian new gas plays are in the 3rd and 4th quartiles.

Western Canada ProductionWestern Canada gas producers are drilling only a third of the wells compared to the record

gas well count several years ago of over 15,000, as a result of the low gas price and high costs.As a consequence, Canadian gas production has already declined to 14.8 Bcf/d, down almost

2 Bcf/d since 2006. Ziff Energy’s Western Canada gas outlook report released to our North American Gas Strategies Retainer Clients, projects WCSB gas production will decline a further 15% to under 13 Bcf/d by 2020 despite Shale and Tight Gas development. Figure 9 shows that while conventional gas contributed over 80% of gas supply in 2002, by 2020 it will drop to less than half (47%).

Western Canada ChallengesWestern Canada’s conventional gas industry faces a number of disadvantages compared to

the U.S., which hinder its competitiveness in the years to come. The first several issues are new in the last few years. Combined, the impact is considerable on Conventional gas in Western Canada.

1. The High Canadian DollarThe Canadian dollar has had a huge uplift over the past 8 years. Every time the Canadian

dollar gets stronger, it’s good for our vacations but lousy for our commodities, whose effective price is reduced.

The negative impact of the strong loonie hits natural gas harder, because the price of gas is much weaker than the price of oil. Figure 10 highlights the exchange rate and challenges it creates.


Figure 11 shows the impact of the strengthening Canadian dollar on natural gas prices using a constant US$6/Mcf gas price, and converting to Canadian dollars using the average exchange rate for each year. In the last 3 years, Canadian gas producers have lost 1/3 of their gross rev-enue, due to the stronger C$.

2. Maturity: Conventional Gas in WCSB is a ‘Senior Citizen’The Western Canadian Sedimentary Basin (WCSB) is approaching ‘old age’. Like a Senior Citi-

zen, it merits special concessions because it’s not capable of as much production as previously.For example, Conventional Gas in the N.E. area of Alberta has been d clining for the past

decade, despite rising gas prices through most of that period. Pools in this area are well defined by 2 and 3D seismic (Amplitude Versus Offset analysis has a high success rate of identifying gas accumulations), hence, exploration is highly efficient and remaining pools are small with mar-ginal or poor economics. In a similar way, 3D seismic in the Gulf of Mexico Shallow Shelf (to 15,000 feet total depth) has been highly successful, and production is in an irreversible decline.

3. Heritage: Less Deep SedimentsThe WCSB sediments are like a wedge --- thickest under the Rockies west of the 5th meridian

(the Calgary/Edmonton line). This contrasts to the U.S., whose average sediment is more wide-spread, and generally deeper, allowing greater potential, especially for unconventional plays.

For example, a typical gas well in Western Canada is 1,300 m deep, whereas in the U.S. it averages 40% deeper.

4. ‘Made in Alberta’ Hyper-Inflation – Oil Sands FeverAlberta is not very populous, and the northern city of Fort McMurray is even smaller. Only

so many billions of capital spending can be crammed into that small region without causing regional hyperinflation --- both in the oil sands sector, and a ripple effect across Alberta for Labour, Services, and Manufacturing that is required for conventional operations. This is exac-erbated by the fact that Oil Sands receives ‘oil prices’ and thus has a much higher ability to pay, while Conventional Gas

receives low natural gas prices. While current oil sands activity is moderate compared to two and three years ago (when oil sands activity sucked labour from across Canada, and caused Alberta inflation to be higher), oil sands activity can increase in a short time period if oil prices strengthen,causing a return of ‘hyper inflation’, with its negative impact on other industries, especially gas.

5. Seasonality (old issue) – Impact on Service and F&D CostsService costs in Canada tend to be higher than in the U.S., due to restricted rig activity dur-

ing, A. winter-only seasonal access to northern areas with muskeg, and B. spring break-up. As a result, a drilling or service company in Canada must maintain more equipment than a U.S. company, which increases prices in Canada, even if the two companies are equally efficient. Figure 12 shows winter only drilling today in the north and northwest part of the basin has become less seasonal than in 2002.

Figure 13 illustrates both B.C. and Alberta have reduced drilling activity due to the annual spring break up in 2002 and 2009. Ziff Energy’s 2003 Western Canada Drilling Cycle Optimiza-tion Study undertaken for ADOE, BCDOE, CAGC, CAODC, CAPP, and PSAC, illustrated the WCSB had very weak drilling in the spring. This disadvantage has been diminished in recent years.

6. ‘Sticky Costs’Figure 14 illustrates that Western Canada operating costs increased rapidly in recent years,

and have only plateaued in 2009, in contrast to U.S. producer operating costs, which have declined.

Operating costs have been very ‘sticky’ in Canada based on early results of the Ziff Energy’s17th Edition of Western Canada operating cost benchmarking assessment; declining produc-

tion volumes offset fixed cost savings, and labour costs have remained ‘sticky’.

7. ‘Location, Location, Location’ – old issue… worse with U.S. ShaleGas costs a lot to transport – it needs to be compressed at regular intervals to flow efficiently

in the pipeline. Since Western Canada is far from eastern markets, and Canadian pipelines are on average newer and less depreciated than the older U.S. pipeline grid, the cost of transpor-tation / WCSB basis differential means WCSB producers get less than U.S. competitors who produce closer to Henry Hub.

With less total gas supply, and increasing gas use by the Alberta oil sands, less gas is exported from Alberta, so eastern pipeline tolls (per Mcf of gas) have escalated since most of their costs are fixed. The new ‘twist’, or threat, is that a number of the U.S. Shale Gas plays are found in the center or East, much closer to market than traditional gas supplies, which are mainly ‘west of the Mississippi’.

Therefore, those more easterly Shale Gas plays benefit from an extra ‘basis bump up’.


INDUSTRY SOLUTIONS: Thinking & Acting in New WaysThe conventional Western Canada Sedimentary Basin (WCSB) is mature and tired; not dead,although certainly not the lowest cost. The future stakes are high for all parties, direct, and

indirect.Continuation of the status quo means the Conventional Gas industry will shrink. Jobs, capital

spending, taxes, & royalties will also shrink. Ziff Energy believes in preserving the conventional gas industry (to the extent possible) and finding solutions to make it profitable. Conventional

gas production represents over 70% of Western Canada’s gas production and could drop to under 50% by the end of this decade. If companies in the Canadian conventional gas value chain continue doing business as usual, focussing on the short term, and not taking a longer term, strategic view, then all aspects of the conventional industry will shrink.

For these reasons, Ziff Energy thinks it’s important for the industry to begin moving to a dif-ferent way of doing business. Traditionally, Paul Ziff observes:

“When energy prices are high, service companies increase their service rates.When prices are low, the producers beat up the drillers and service providers”.Similarly, producers and 3rd party Midstream operators, along with pipeliners, usually engage

in a ‘zero sum’ game called ‘I win, you lose’.Ziff Energy believes a new business paradigm is needed that recognizes many challenges.While this will not be easy, the alternative, the status quo is worse: if we continue doing busi-

ness the traditional way, with the above disadvantages, then the overall size of the industry, all stakeholders, is guaranteed to progressively get smaller, hurting all stakeholders. The reason is that annual production decline is large, and the capital to replace reserves and production is mobile --- particularly for the U.S. super-independents and the Majors (U.S. and international). Many of the latter have already ‘voted with their check book’ in the last decade, abandoning conventional assets for new resource plays, or for international oil plays. Large Operators may want to invest in the oil sands, and in unconventional plays, but their capital is not captive for conventional gas (and oil).

Discretionary capital will migrate to the region or country that gives the best economic return.

FiscalThe Alberta and B.C. provincial governments have offered a number of concessions to the

energy industry which help competitiveness, increasing industry activity above what it would otherwise have been.

Since 2004, the B.C. government has provided an Infrastructure Royalty Credit program to encourage oil and gas infrastructure development. B.C. also provides incentives for wells drilled in the summer, and royalties as low as 2%.

From January 1, 2009, Alberta offered transition royalty rates for conventional oil & gas wells drilled deeper than 1,000 m, through 2013. On March 3, 2009, the Alberta Government provided further relief by temporarily lowering royalties for new wells to 5% for up to1 year and introduced the New Well Drilling Incentive – up to a $200/m drilled royalty reduction for new wells.

Current IncentivesOn March 11, 2010, the Alberta Government reduced the maximum royalty rate (effective

January 1, 2011) from 50% to 36% for natural gas wells and 40% for conventional oil wells, and immediately made permanent the 5% royalties for new wells (same time and volume limi-tations).

On May 27, 2010, the Alberta Government announced new royalty rates (‘curves’) for natural gas & conventional oil effective January 1, 2011. These provide significantly lower royalties for low productivity gas wells at gas prices over $5.25/Mcf, with minor changes for oil and high

productivity gas wells. Additionally:• new CBM wells will have a 5% royalty for the first 36 months, up to 0.75 Bcf• Shale Gas wells will have a 5% royalty for the first 36 months, no production limit• Natural Gas Deep Drilling Program now includes wells drilled from 2,000 to 2,500 m• the Emerging Resources and Technology Initiative will be reviewed in 2014 and industry

will be given 3 years of any changes, which therefore suggests royalty stability until 2017 at a minimum.

Unconventional GasIn its March 2010 policy statement, “Energizing Investment”, the Alberta government com-

mitted to: “explore additional ways to recognize and account for the higher costs of new and advanced technologies needed to develop mature conventional oil and gas plays and uncon-ventional natural gas”.

Also, “front-end modifications to the royalty framework for natural gas and conventional oil will recognize the higher cost often associated with the deployment of new technologies and enable investors to recoup these upfront investments.”

To this direction, the May 2010 Alberta royalty changes have focused on growth opportuni-ties for Unconventional Gas.

Regulatory ReviewDuring 2009, the Alberta government committed to a number of near-term enhancements to

the Alberta regulatory system, through an inter-departmental task force scheduled to make its first report before June 11, 2010.

Despite these positive fiscal changes by Government, the problem today for WCSB Con-ventional Gas is bigger --- provincial governments through royalties and incentives cannot fix everything --- so the various industry sectors also need to be proactive. We now face the larger problem of how the other players in the Canadian gas industry are going to make conventional gas competitive.

Absent this, what we will see is service companies sending equipment overseas, as they did in the recent downturn, and Canadian E & P companies such as Encana, Talisman, and Enerplus have become more active in the U.S., or internationally.

II. PRODUCeR BeHAvIOUR

‘Low Cost Survives/Wins!’ - encana Producers have to be rigorous and focus persistently on Low Cost Production operations,

by reducing costs for drilling, finding, and operating, and concurrently strengthening their gas production uptime metrics (maximizing production). To strengthen the industry, annual bench-mark feedback on key performance metrics can be used to keep the industry on the path to success.

We note that only a quarter (25%) of Gas Producers can be ‘Top Quartile’ performers; how-ever three quarters (75%) claim to be!

Stable Capital Spending from Year to YearThe traditional pattern of spending cash flow when gas prices are high, fuels inflation of land

& service costs.Paul Ziff recommends: “Level spending, means investing ‘counter the cycle’, over-spending

Cash Flow when costs are low, to ‘lock in’ low F&D/Future DD&A (generates higher future profits); and under-spending (discipline) when costs are high”.

Stable Activity Throughout the YearDesigning programs away from the winter peak and spreading through the year (‘level–

loading’) will bring stability for service equipment and related labour. The industry has made considerable progress since the 2003 study that Ziff Energy conducted for the Governments of Alberta and BC, and the 4 Industry Associations: CAGC, CAODC, CAPP, and PSAC.

HedgingThis financial strategy can be a powerful tool to ensure predictability in cash flow capital

programs and dividend payments. It helps by taking risk out of the natural gas markets --- the most volatile commodity in the world! Some producers view hedging as risky – but what is riskier than investing huge capital sums and seeing the pricing bounce large amounts from day to day?

The goal is not to “beat the house”, or try to outsmart the market, rather to generate predict-ability for investors and create a sustainable spending program.

The opportunities were greatest in 2008; however, when the gas price bumps up, so does the forward price, producers need to be aware of their play economics, and have a well designed, price approved strategy they can quickly execute.

Shutting In ProductionWhile it may be viewed as a short term pain for a long term gain, shutting in excess gas sup-

ply when prices are very low (like wheat, cars, or iron ore) can help save the resource for a later date.

Some producers in both Canada and the U.S. have shut-in gas supply during times of low prices, preserving the value of their limited reserves. While this action is not feasible for some fields (CBM) and situations (fixed processing or transportation or high liquids), companies should identify well in advance where they can shut in.

Continues on Page 45


G. Richard Drilling celebrates 25 years and Gerry Richard, owner of the com-pany, attributes the company’s success to strong team work. “We’d like to thank the people who got us here,” he said.

Richard grew up on a farm that had cattle, pigs and also grew own vegetables, providing his family with a self-sufficient lifestyle.

“I’ve been farming ever since I’ve been wearing diapers,” he says.He worked as a driller in the winter times which gave him time to farm during

the summer.He started his own business in 1985. “[I] built a new rig and slowly every year

kept building the fleet up,” he says.The company first started with 6-7 employees and 2 drills and has grown to over

50 employees and almost 28 drills. Having a farming background has enabled him to understand the needs of a farmer, he says.

“If we are drilling over farmers land we know what it’s like so we respect their land,” he adds.

His farm was 300 acres wide in 1985 and has grown to be 13,000 acres. He also raises Elk for their meat and antlers.

He applied his farming knowledge and equipment expertise to the oil and gas industry as well.

Richard says a key factor to the company’s success lies in working together as a team. He joins his employees for the hard work and knows the ins and outs of drilling.

“I go out with my guys, I’m in a jumpsuit,” he says.He also believes having multi-skilled employees lead to the company’s success. “My employees are able to do just more than one job,” he adds. Technology has also evolved since the birth of the company. The drills now used are more

productive, cost efficient and safer. All technologies change in 25 years, says Richard, and he believes the company has some of the best drills out there.

However, the key to safety is using common sense and effective communication, he says.“Just cause you got all that extra gear on doesn’t mean you are bullet proof.”The company has seen almost four recessions in the past 25 years and Richard believes it

has maintained its success by never overcharging clients, as you’d be the first one to go during a recession. Overcharging burns the bridge with a client, he says, as they tend to find cheaper replacements during a recession.

The company employees experienced drillers, some with more than 30 years of experience. “They’ve got the common sense factor,” says Richard. Experienced employees also guide

new recruits to be more efficient and productive. “Anybody can buy equipment; it’s the people that do the job,” he said.

G. Richard Drilling Celebrates 25 YearsBy Seema Dhawan

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The oil sands will help drive significant growth in Cana-dian crude oil production over the next 15 years, according to the Canadian Association of Petroleum

Producers. Canadian oil sands production in 2010 is estimated at 1.5 million barrels per day in CAPP’s 2010 Crude Oil Fore-cast. That’s expected to climb to 3.5 billion barrels daily by 2025, making up more than 80 per cent of total Canadian crude oil production. The shift in the economic climate has caused some companies to pursue development and expan-sions that were previously put on hold. Here is a glimpse of recent developments and future plans for some of the major projects as well as smaller ones. And since the bitumen found in those oil sands needs to be upgraded and then piped to market, the latest in what’s happening on those fronts is also included. The following information was gathered from vari-ous web sites, public disclosure documents, news releases and news clippings with effort made to obtain the most current information. Due to space and sometimes available informa-tion, not all projects have been included.

Algar LakeCalgary-based Grizzly Oil Sands ULC has submitted an appli-

cation to start an 11,300-barrel-per-day oil sands project near Fort McMurray.

The Algar Lake project, not related to Connacher’s Algar project, will use steam-assisted gravity drainage (SAGD) technology. The project is located 45 km southwest of Fort McMurray.

The application, which has been filed with the Alberta Energy Resources Conservation Board and Alberta Environ-ment, calls for approval of the first stage of development at Algar Lake. The plans include two plant phases.

“We are now embarking upon the detailed engineering and construction planning phase of the Algar Lake SAGD Project and expect to commission the first phase in 2012,” stated John Pearce, CEO of Grizzly.

McDaniel & Associates, Grizzly’s third-party engineering firm, estimates the project will produce about 89 million bar-rels of bitumen in total.

Athabasca Oil SandsThe current production capacity of Shell’s Athabasca

Oil Sands Project, which it owns with Chevron Corp. and Marathon Oil Corp., is 155,000 bpd of synthetic crude, but

will grow to 255,000 barrels when the enlarged mine and expanded Scotford upgrader are opened next year.

Shell Canada’s 100,000 barrel-a-day expansion of bitumen mining and upgrading facilities is underway.

This phase of expansion includes construction of mining and extraction facilities at the Jackpine Mine, expansion of froth treatment facilities at the existing Muskeg River Mine and expansion of the Scotford Upgrader.

Muskeg River is about 75 kilometres north of Fort McMur-ray and the expansion of the Jackpine mine is just east of that operation. The Jackpine Mine Expansion will bring produc-tion at that mine up to 300,000 barrels a day.

While these expansions take place with a proposed comple-tion date of 2010, partners in the Athabasca Oil Sands Project are looking ahead to more growth in the future.Future propos-als include expanding the Pierre River Mine production base by 200,000 bbl/d.

Shell has also applied to the Alberta Energy and Utilities Board and Alberta Environment for approval to construct and operate Scotford Upgrader 2 adjacent to Shell’s existing Scot-ford facilities near Fort Saskatchewan.

The proposed Scotford Upgrader 2 would be constructed in four phases and process Shell’s share of future Athabasca mineable bitumen production as well as bitumen from the company’s in situ oil sands developments.

Scotford Upgrader 2 could ultimately process up to 400,000 barrels-a-day of oil sands bitumen into a range of synthetic crude oil products.

Carmon CreekShell Canada made application to the government in Janu-

ary 2010 for approval of its Carmon Creek Project. The project is situated in the Peace River oil sands region in the Bluesky formation and Shell plans to use thermal recovery methods.

Shell initially submitted a regulatory application for the project in 2006, but later withdrew it after further engineer-ing work resulted in changes.

The Carmon Creek proposal is for production of 80,000 barrels per day. About 95 well pads and two central process-ing facilities to process bitumen will be required over the proj-ect’s anticipated 35 years of operation.

The five oil sands leases in the area are estimated to contain 4.9 billion bbl, about 600 metres deep.

Fort HillsThe Fort Hills oil sands mine could see startup in 2016. It

is 60 per cent owned by Suncor with the rest split evenly between UTS Energy Corp and Teck Resources Ltd.

UTS chief executive William Roach told analysts in a con-ference call that while the timing will ultimately be Suncor’s decision, first oil could come in late 2016 or early 2017. In order for the partners to keep the leases, it would need to hap-pen before July 31, 2019.

Put on hold in 2008, the proposed project consists of an integrated oil sands mine and bitumen extraction plant 90 kilo-metres north of Fort McMurray. Original plans also included an upgrader in Sturgeon County northeast of Edmonton.

Suncor is reassessing the economics of the project, which was put on hold in 2008 by majority own Petro-Canada. Sun-cor became involved when it merged with Petro-Canada.

Fort Hills is one of the largest remaining undeveloped oil sands leases in the Athabasca region. The bitumen resource has an estimated 4.7 billion barrels (estimated by Sproule Associates Limited, Oil and Gas Consultants in 2006).

Original plans were for the first phase to produce 140,000 bpd of synthetic crude oil.

Great DivideConnacher Oil and Gas held a ceremonial opening of Algar

in June, a 10,000 barrel per day SAGD plant at its Great Divide oil sands project in northeastern Alberta.

Algar is located eight kilometres east of the Great Divide’s Pod One.

Oil sands Production Projects at a Glance

Continues on Page 29

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Lower operating costs and new drilling approaches help pro-duce higher Q1 drilling activity and set the stage for long term health of oil and gas sector

In 2009, Canada’s oil and gas producers suffered their weak-est earnings performance since 2002, albeit with improvement in the second half of the year. This is according to the Canadian Annual Energy Survey, an annual review of the financial and opera-tional results of the Top 100 oil and gas companies from Pricewa-terhouseCoopers (PwC). The survey is completed in partnership with JuneWarren-Nickle’s Energy Group.

Key financial and operational highlights for 2009 include:

• 2009 gross revenue for the Top 100 oil and gas companies declined 32 to $132.9 billion from $194 billion the prior year. Revenue from the Top 20 oil and gas operators accounted for over 90% of total revenues.

• The Top 100 producers booked a combined profit of $8.5 bil-lion in 2009, a decrease from $36.0 billion from 2008.

• - Total 2009 oil and gas production rose slightly to an average 4.64 million barrels of oil equivalent (BOE) per day from 4.48 million BOE per day in 2008.

• Operating costs per BOE declined by 7% to $13.61 in 2009 from $14.67 the previous year.

Canada’s energy sector on the rebound after a difficult 2009, according to PricewaterhouseCoopers

“While in many respects 2009 was a year that Cana-dian oil and gas producers would like to forget, it produced outcomes that were necessary for the long-term health of the sector,” says Scott Bolton, partner and national leader of the Energy practice for PwC. “Soaring costs were brought back to earth in the face of a dramatic pullback in capital spending.”

Stephen Marsters, editorial director at JuneWarren-Nickle’s Energy Group, adds, “Lower capital spending also forced the Alberta government to back off its higher royalty agenda. Both occurrences were neces-sary, given a mid-term outlook where we are not likely to see a rise in natural gas prices.”

Many producers proved that the combination of horizontal drilling and multi-stage fracturing could unlock new reserves in many different oil and gas formations across Western Canada. The combination of all of these factors has already helped to produce a notable increase in first quarter 2010 drilling activ-ity. For the first three months of 2010, the rig release count of 3,634 wells increased 22% from the 2009 multi-year low of 2,970.

The future of Alberta’s oilsandsThe tremendous investment by Canadian business

and government to the Alberta oilsands continues to point a global spotlight on the province. In 2009, Alberta produced an average of 1.49 million barrels per day of raw crude bitumen from the oilsands, reports the Energy Resources Conservation Board (ERCB).

Indeed, the annual total of 544 million barrels in 2009 represents a 14% increase over Alberta’s 2008 production, and has pushed total oilsands produc-tion since 1967 to nearly seven billion barrels. By 2019, Alberta’s raw bitumen production is expected to increase to 3.2 million barrels per day based on announced expansions of existing projects and the start of new projects. By 2019, synthetic crude oil pro-duction is forecast to increase by approximately 77%, to 1.3 million barrels per day, according to the ERCB.

“The recovery in crude oil prices has revitalized new oilsands development, however the trend is towards smaller scale projects,” says Bolton. “And while projects appear to be moving ahead, the sec-tor’s development is still a very expensive, capital-intensive initiative and the need for skilled labour and more efficient regulatory processes will continue to pose challenges.”

“The direction the oilsands industry takes will really depend on a myriad of related issues including access to capital, cost-competitiveness, and environ-mental regulations that will shape and impact the sec-tor as a whole,” said Bolton.

“The recovery in crude oil prices has revitalized new

oilsands development, however the trend is towards

smaller scale projects,” says Bolton


First production from Algar is expected in August 2010. The project came in under budget at $370 million and was completed in April.

It is designed for future expansion to 34,000 bpd of bitumen production. Connacher is con-structing a cogeneration plant for power and supplemental steam.

The company is hoping to receive regulatory approval in late 2011 for a third expansion phase that would add another 24,000 bpd. Start up of that phase could take place in 2013.

Horizon Project (and Primrose Lake)Canadian Natural Resources Limited (CNRL) is planning to add four more phases to its Hori-

zon Project upgrader.The first oil from Horizon was produced in 2009 and it is still ramping up to 110,000 barrels

per day (bpd) of expected production. The target for 2010 is between 90,000 and 105,000 bpd of synthetic crude.

Operations problems had led to reduced production volumes, but a planned maintenance outage in May was expected to limit future issues.

Eventually, the project could produce 500,000 bpd.The Horizon Project is the largest capital project in Canadian Natural’s history at $9.47 bil-

lion, about eight per cent above the previous estimate and 36 per cent higher than originally estimated back in 2004.

CNRL president Steve Laut says the company is continuing to focus on reaching sustainable production volumes at Horizon, as well as increasing reliability and reducing operating costs. “We are committed to completing lessons learned from the construction of Phase 1 to ensure an optimal strategy for the development of future expansions,” he says.

Projected costs for the second phase will likely be known early 2011.The Horizon Project is located about 70 kilometres north of Fort McMurray. The project has

a fly-in and fly-out camp. The airstrip on the Horizon site allows workers to commute from the Atlantic provinces.

In addition to the Horizon Project and various other ventures, CNRL is the owner-operator of the Primrose-Wolf Lake oil sands project located 55 kilometres north of Bonnyville.

Cyclic steam stimulation and SAGD technologies are being used to produce about 80,000 barrels of oil per day at Primrose-Wolf Lake.

JackfishThe first phase of Devon Energy’s Jackfish

project is now operating at 35,000-barrel-per-day and construction on the second phase is almost complete. The company plans to file a regulatory application for a third phase in 2010.

If the third phase is approved, site work could start in 2012, with commissioning in 2014.

Each phase of Jackfish is virtually identical, with a few improvements added as necessary.

Once fully operational in 2012, Jackfish 2 will produce about 35,000 barrels of oil per day through SAGD methods. Devon expects to recover about 300 million barrels of oil from Jack-fish 2. When Jackfish started production in 2007, it became the first commercial SAGD operation to rely completely on saline water for production.

KearlImperial Oil’s board of directors has approved

the first phase of the Kearl Lake oilsands proj-ect, a surface mining operation northeast of Fort McMurray. The project was shelved for a time due to the slumping economy, but Imperial Oil

announced in May 2009 that it would move forward with Kearl.There are three phases planned for the project, which could ultimately produce more than

300,000 barrels per day of bitumen. The first phase of the project is expected to begin produc-tion in late 2012, with total production averaging 110,000 barrels per day.

The cost for Phase I is estimated at $8 billion. A permanent workforce of around 1,100 to 1,300 is anticipated when all three mine trains

are in operation. Imperial will adopt a camp-based operation with a workforce on a rotating schedule.

Kirby/PikeAs part of a $7-billion asset deal with BP this spring, Devon Canada received an operating

interest in the Kirby thermal oil sands project in northeastern Alberta near its existing Jackfish project.

Through its joint 50-50 venture with BP, Devon will become the operator of the development project, located next door to Devon’s Jackfish oil sands project.

No date has been set for production, but plans are in the works to begin a delineation drilling program in the third quarter of this year. The project will involve about 170 wells.

Kirby is in the process of being renamed Pike. This will help differentiate the Devon-BP proj-ect from the Canadian Natural Resources proposed Kirby in situ oil sands development located about 85 kilometres northeast of Lac La Biche.

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Long LakeBitumen volumes are growing at the Long Lake Project,

which is no longer in start up mode. Early in 2009, Nexen acquired an additional 15 per cent

interest in the Long Lake Project and the joint venture lands from OPTI, increasing its ownership level to 65 per cent. Fol-lowing this acquisition, Nexen is now responsible for oper-ating both the SAGD bitumen extraction process and the upgrader for Phase 1 as well as for future phases.

The Long Lake Project uses new technology and is the first to combine SAGD, (steam assisted gravity drainage) with hydrocracking and gasification. Long Lake is using the pat-ented OrCrude process in order to use 100 per of the bitu-men.

Phase 1 of the Long Lake Project is located 42 km southeast of Fort McMurray.

The Project has an estimated reserve life of 40 years and started producing premium sweet crude in the fall of 2008.

In 2010, the capital program at Long Lake Phase 1 is focused on the drilling of sustaining well pads and the continued installation of electrical submersible pumps in the SAGD wells. About 50 per cent of the wells have already been con-verted from gas lift to electric submersible pumping. About 80

per cent are to be converted by the end of the year to advance well productivity.

Phase 1 has potential for 72,000 barrels per day of SAGD oil production and is currently averaging 25,000 bpd of bitumen.

MacKay RiverAthabasca Oil Sands Corp. announced plans in the summer

of 2009 to sell working interests in the company’s MacKay River and Dover oil sands projects to the Chinese energy giant PetroChina. The $1.9 billion deal has now closed and gives the Chinese-based company a 60 per cent working interest in the two projects.

Located 60 kilometres northwest of Fort McMurray, MacKay River is one of the largest commercial SAGD projects in the Athabasca oil sands area.

The bitumen resource at MacKay River totals 2.4 billion bar-rels, giving a lifespan of 25 to 30 years for the current plant and the planned MacKay River expansion.

The Athabasca Oil Sands Corporation has also announced it is planning to hold an initial public offering IPO to fund its share of development costs for its oil sands projects. Accord-ing to a preliminary prospectus released by the company, the initial public offering will be held in 2010.

May RiverThe May River Project is Petrobank’s first

large-scale commercial THAI™ applica-tion on its oil sands leases west of Conklin, Alberta. The project will be built in phases, with initial production capacity of 10,000 bopd and ultimate capacity of up to 100,000 bopd. The ERCB application is now moving through the regulatory process and Petro-bank anticipates approval shortly.

Front-end engineering and design for the May River Project was completed at the end of 2009. The project has been designed to

be a net water producer, rather than consumer.

Narrows Lake (and Christina Lake)

A new multi-billion dollar oil sands project is being planned as a 50/50 joint venture between Cenovus Energy and ConocoPhil-lips.

Narrows Lake is forecast to have a production capacity of 130,000 barrels per day, up to three phases and a project life of

up to 40 years.Production is expected around 2016, taking into account an

18-month to two-year regulatory process.Cenovus, created at the end of 2009 from an EnCana split,

hopes to utilize new technology on its Narrows Lake proj-ect — the first ever commercial-scale solvent aided process (SAP). It could potentially yield extra bitumen while using less energy.

Narrows Lake would be built in phases with construction possibly starting January 2013. Regulatory applications are being filed this summer.

Narrows Lake is located near Christina Lake, which along with Foster Creek is a 50/50 business venture of Cenovus and ConocoPhillips. Production from the next phases at Foster Creek and Christina Lake is expected to begin a year earlier than originally planned.

Cenovus and ConocoPhillips have signed a deal with Enbridge to build new pipeline and terminal infrastructure for the Christina Lake project.

At Cenovus’ first investor day in June, the heavy oil company said it hopes to push past 300,000 barrels per day by 2019. That’s a five-fold increase from current bitumen levels.

“We believe we have ample resource to achieve significant growth for decades,” says Brian Ferguson, Cenovus chief exec-utive.

Cenovus plans to file a regulatory application toward the end of 2011 for the Grand Rapids 60,000 bpd oil sands proj-ect. A SAGD (steam assisted gravity drainage) well pair is to be tested at Grand Rapids this fall.

Evaluation work is underway for several other projects that are expected to start producing after 2019. Additional strati-graphic wells are being drilled to support the current applica-tion at the Telephone Lake project in the Borealis Region.

An external evaluation of Cenovus’ oil sands assets by McDaniel and Associates Consultants identified “best estimate total bitumen initially-in-place” of 137 billion barrels.


Northern Lights ProjectThe Northern Lights Project is located in the Athabasca

region of Alberta, about 100 kilometers northeast of Fort McMurray.

Total SA is to be the operator and owns a 50 per cent inter-est in the Northern Lights Project. Sinopec Corporation, a Chi-nese company, purchased an additional 10 per cent in April 2009 to bring its share to 50 per cent.

The latest estimate of contingent resources of the Northern Lights Project is 1.08 billion barrels of bitumen. Total formally withdrew the current regulatory application for the project in December 2008, stating it is in the process of integrating the asset into its Canadian portfolio and is working on long term plans for it.

SuncorSuncor Energy is moving ahead with its tailings manage-

ment plan, after receiving approval from the Energy Resources Conservation Board (ERCB) in June. The oil sands giant has developed a new approach to tailings management called TRO, a technology it has been developing since 2003.

“We expected to invest more than $1 billion to implement our new TRO technology, potentially reducing tailings recla-mation time by decades,” says Kirk Bailey, executive vice presi-dent oil sands.

Mature fine tailings will be mixed with a polymer floccu-lent and deposited in thin layers over sand beaches with shal-low slopes. Suncor says the result is a dry material that can be reclaimed in place or moved to another location for replanting with native vegetation.

Suncor is also moving forward with its Firebag Stage 3 expansion, an in-situ project put on the back burner in early 2009 due to low commodity prices. At the time it was deferred,

it was about 50 per cent complete.Suncor now expects the project to begin production in the

second quarter of 2011, with volumes beginning to ramp up to about 68,000 barrels per day (bpd) of bitumen.

Plans are also in the works for Firebag Stage 4 for a target of first bitumen production in the fourth quarter of 2012. Stage 4 also has a design capacity of 68,000 bpd.

Suncor has budgeted to spend $5.5 billion on capital in 2010 and expects to grow oil sands production by 10 to 12 per cent.

The majority of the capital budget is earmarked for mainte-

nance on existing projects. Only $1.5 billion will be used for company growth.

Production at Suncor averages 350,000 barrels per day. The plan is to increase production to 550,000 barrels per.

Before the recession, Suncor planned to build Voyageur, an upgrader with estimated $11.6 billion price tag. Now the com-pany says the Voyageur upgrader will be deferred indefinitely.

Suncor completed its merger with Petro-Canada Aug. 1, 2009, becoming Canada’s largest energy company and the fifth largest North American based energy company.

Sunrise ProjectFront end engineering and design is now complete for

Phase I of the Sunrise Oil Sands Project, jointly owned by Husky Energy and BP.

Husky has obtained necessary approvals from the Govern-ment of Alberta, Environment Department and the Energy Resources and Conservation Board (ERCB) to proceed.

Requests for proposals for the central plant and field facili-ties will soon be issued. The first five well pads are being built and it is expected that site preparation work for the central facilities will be finalized in 2010. Construction of the project could start in the second half of 2010, with Phase 1 produc-tion anticipated in 2014.

The Sunrise Oil Sands Project, located 60 km northeast of Fort McMurray, will use SAGD technology. Husky estimates that Sunrise contains 3.7 billion barrels of proved, probable plus possible reserves. Capital cost for Phase I (60,000 barrels per day) is now estimated at $2.5 billion, lower than the ear-lier forecast of $3.8 billion to $4 billion.

Under current regulatory approvals, production is expected to ramp up to 200,000 barrels per day once all phases have been built and are operational in the 2020 timeframe.


SurmontConocoPhillips and Total SA are making plans to boost pro-

duction at the Surmont project to 110,000 barrels per day, four times the current amount.

Construction at Surmont, which currently produces about 27,000 barrels a day, will begin this year and is slated to be complete by 2015. The cost of the project was not released.

Surmont, located southeast of Fort McMurray, uses steam-assisted gravity drainage (SAGD) technology. The method pre-serves more of the region’s landscape, but burning natural gas to produce steam generates significant amounts of green-house gases.

The partners say they plan to spend $300 million on research and development over the next five years to come up with new technologies to reduce Surmont’s environmen-tal footprint. The project is expected to employ about 2,500 workers during construction and add 300 permanent jobs once work is complete.

SyncrudeCanadian Oil Sands Trust is planning to increase production

at Syncrude Canada 60 per cent by 2020.The Trust has a 37 per cent stake in Syncrude, making it the

project’s largest shareholder. Canadian Oil Sands Trust says it plans a series of small proj-

ects that will raise production of synthetic crude from Syn-crude’s upgraders to 425,000 barrels per day by the end of the decade. That’s up from 375,000 bpd.

Its goal is to produce 25,000 bpd more than previously expected from the projects. That would be 75,000 bpd above current capacity.

Syncrude plans to begin construction of its Aurora South mine in 2012, building it in two 100,000 barrels-per-day phases to be complete in 2016 and 2020.

When the second phase is finished, Syncrude will produce about 600,000 bpd of bitumen, about 115,000 bpd more than needed to supply its upgraders.

Syncrude has only sold low-sulfur synthetic crude, but in the future could also sell sulfur-rich crude and heavy oil into the market to manage its excess output.

The plans still need regulatory approval and to be approved by Syncrude’s owners. The other partners are Imperial Oil, Suncor Energy, Nexen, ConocoPhillips, Murphy Oil and Nip-pon Oil unit Mocal Energy. A cost estimate has not been announced.

Terre de GracePlans for the Terre de Grace Project are moving forward

after BP (British Petroleum) purchased a majority stake in Calgary-based Value Creation in March 2010.


First oil from the 10,000 barrel per day pilot phase of Terre de Grace, northwest of Fort McMurray, is expected in 2011. The project is designed to eventually produce 300,000 barrel per day.

The lease area is more than 74,000 hectares. The project will utilize SAGD technology, as well as ADC (accelerated decontamination), where a low viscosity, low contaminant crude is produced that requires little to no diluent for trans-portation. The Terre de Grace project will house a central pro-cessing plant.

ADDITIONAL UPGRADeRS

North West UpgradingNorth West Upgrading Inc. and Canadian Natural Resources

Limited (Canadian Natural) are submitting a joint proposal to the Alberta Government to construct and operate a bitumen refinery near Redwater, Alberta.

North West and Canadian Natural will each own 50 per cent of the partnership, with North West acting as the operator.

Closing is anticipated later in 2010 and remains subject to satisfaction of a number of conditions.

The refinery is targeted to be built in three identical phases of 50,000 bpd and will be designed to produce finished prod-ucts from raw bitumen. It represents the world’s first facility with a one step conversion process of bitumen to finished products and an integrated CO2 management solution. The process incorporates gasification to convert the bottom of the barrel to hydrogen and reduces the need

for natural gas. CO2 from the facility will be used for enhanced oil recovery purposes, which will reduce CO2 emis-

sions by about 3,500 tonnes per day for each of the three tar-geted phases.

Total e & P Canada

Hearings took place in Fort Saskatchewan in June to decide if Total E&P Canada should be allowed to build an upgrader in the industrial heartland.

While the company highlighted the benefits the project could bring to the economy, some residents from around the area held placards with slogans such as “Protect farms and families.”

The three-member ERCB panel will make its ruling by the end of September.

Applications were filed back in 2007 for the upgrader and Total’s website says regulatory approvals are expected this year.

The proposed upgrader is part of Total’s overall oil sands development plans. Located in Strathcona County, about four kilometres northeast of Fort Saskatchewan, at full capacity the Total Upgrader will process and convert 295,000 barrels per day of bitumen into light sweet synthetic crude oil.

The bitumen extracted by Total’s upstream projects, includ-ing Surmont, will be transported to the Fort Saskatchewan area by pipelines and will be available as feedstock for the Total Upgrader.

It is expected that up to 4,000 workers would be needed to construct the upgrader and the company estimates another 300 to 400 employees would be needed to operate the project once it is up and running.

If the upgrader is approved, it would be built in three phases, likely over a four-year period.


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Showcased at theGLOBAL PETROLEUM SHOW 2010Calgary, Alberta

TechnologyOnce named the oil capital of the world, Tulsa,

Oklahoma rests near the foothills of the Southern Ozark Mountains. Winding among these wooded

hills and across the open wheatlands toward Medford, Oklahoma more than one hundred miles away, lays a Liquefied petroleum gas (LPG) pipeline belonging to a midstream oil company.

The organization handles over 3 million barrels per day of crude oil, refined products and LPG through an extensive network of pipelines throughout the Midwest.

Nationwide, pipeline operational data is monitored in real-time from the company’s office control center in Texas. For security, safety, and real-time accessibility, all critical data is transmitted via satellite to the SCADA control center.

To improve line integrity, the engineering team responsible for this one hundred mile LPG pipeline wanted to increase monitoring for some non-critical data points at 12 PLCs along the length of the pipeline. The crux: how to do so when their standardized satellite solution would be cost-prohibitive for these non-critical, low data transfer locations. Without additional monitoring points, they were left with visibility at only three points on the pipeline. In the event of a leak, discovery requires an operator to physically drive the entire length of the pipeline between point A and point B to locate the leak, which in this case could be anywhere along a 20, 30 or 40 mile stretch of pipeline. From a line integrity standpoint, having nothing in between these points meant less resolution as to what was happening on the pipeline, and though leaks are rare, when they occur it’s essential to find and isolate them quickly; for the safety of personnel, collateral, and the environment.

With the plethora of wireless products now available, the engi-neering team began investigating alternatives to satellite for these non-critical locations.

“When I was first approached about this opportunity, I immedi-ately thought of ProSoft,” comments Brian White from Rexel Dis-tribution. “With its extensive line of products and services and his-tory of assistance to Rexel in Oklahoma, I felt confident they could provide a viable option for this application.”

SolutionOriginally, 900 MHz industrial radios were considered for these

stations, because of their long-range capabilities and ability to pen-etrate foliage. Because of the dramatically different landscape, how-ever, a site survey concluded that of these twelve locations, three lacked the required line-of-sight. To bring these sites onto the net-work, towers would have to be built, which would have brought

the cost of implementation close to a hundred thousand dollars, rendering yet another solution infeasible.

Luckily, every site had cell service.“Cellular technology is fantastic for real-time network access to

industrial devices around the world,” explains Jim Weikert, Wireless Product Marketing Manager at ProSoft Technology. “This applica-tion highlights the ease with which devices in remote areas can be made accessible at an affordable price.”

The company went with cellular GSM (or Global System for Mobile Communications) serial modems on an AT&T contract. Doing so, they were able to bring the site cost down from a poten-tial $200 monthly satellite fee at each of twelve locations, to $50 per month, and with very minimal hardware costs.

Implementation Challenges

Within three weeks from the time the order was placed, the radios were onsite. Installation was a challenge for the company only in that they had never worked with cellular. When they began the setup process, ProSoft Technology’s technician engineer, Dan Blome, walked them through the process and with 15 minutes of setup per device, had the radios talking.

ResultsThe cellular radios are scattered along that length of the pipe-

line, monitoring line pressure and valve statuses along the way. Each radio is wired to a PLC via serial Modbus, gathering informa-tion from their remote locations. A thirteenth cellular radio is con-nected to the satellite network, relaying data from all twelve points back to the control center in Texas.

By adding these data points to the network, the company was able to minimize risk while keeping the application safe and oper-ational. In fact, using cellular has enabled them to pinpoint line pressures to 5 mile intervals versus 40, so should pressure drop off between two of these points, they can quickly isolate leaks with as little impact as possible.

The FutureSince this initial project, the company has begun two other simi-

lar projects. The first involves five cellular radios along a crude oil pipeline that runs from terminal-to-refinery. The second is an iden-tical application involving two cellular radios.

Cellular provides cost-effective alternative to satellite, improving line integrity for a midstream oil companyBy Adrienne Lutovsky, Staff Writer, ProSoft


Lufkin Automation has chosen the Westermo MRD-310 3G router to equip its SAM Well Manager product, the oil industry´s most advanced technological solution for

high-precision monitoring and control of rod-pumping wells. Used in a series of pilot projects, mainly for the European and Asian markets, the MRD-310 provide a very high level of con-nectivity, and support many mobile standards including GSM, GPRS, 3G UMTS, HSDPA and HSUPA. Dedicated to harsh envi-ronments, MRD-310 is aimed to demonstrate significant cost savings in this application.

Lufkin Automation was formed by the merger of two com-panies, the Delta X and Nabla Corporations, pioneers in rod pump controls. Delta-X was a leader in test and analysis sys-tems for pumping processes using new innovative and user friendly methods. Nabla was the developer of software solu-tions that in many ways has simplified the analysis and control of the pumping process. Today these two companies are a part of Lufkin Automation oil field division and offer analysis, secu-rity and control solutions for rod pumping wells.

Oil fields are often situated in remote and demanding envi-ronments where extreme variations in temperature, moisture and other environmental variables are an issue. To install the control and monitoring systems in these environments can be difficult as oil fields often consist of hundreds of pumps spread over large geographic areas.

The Lufkin-developed SAM Well Manager is the oil indus-try’s most advanced technological solution for high-precision monitoring and control of rod-pumping wells. The SAM Well Manager allows the operator to optimise pump performance and reliability. Pump flow can be analysed, service and main-tenance requirements are calculated before the event of mechanical failure and energy consumption is optimised.

The SAM Well Manager can be configured to stop the pump-ing process at low oil levels and when maintenance or service are required. The system also creates a complete action his-tory that can be used for further optimisation.

The SAM Well Manager is connected to the pump’s SCADA system. To remotely control the system a variety of technolo-gies such as copper, fibre and radio links have previously been used. Although Lufkin’s European division has further enhanced the system and new solutions using mobile net-works have been developed. Lufkin have decided to use the Westermo MRD-310 3G router in a series of pilot projects, mainly for the European and Asian markets.

The MRD-310 is perfectly suited for this type of applica-tion in many ways. Its support for the wide variety of mobile standards used globally allows installations in practically the

whole world. It also supports IPSec encrypted VPN tunnels which is a requirement for safety critical applications that use unsecure public networks (The Internet). Furthermore, the MRD-310 provides a serial interface and serial to IP con-version, which is necessary to connect to the controller. The routers are also developed for extreme environments and can operate in temperatures from -20C to +60C. Today, this appli-cation is installed in a number of pilot projects to demonstrate the potential for significant cost savings.

Using High Speed Uplink Packet Access (HSUPA), the uplink capacity is 2 Mbit/s, together with the 7.2 Mbit/s downlink data making the unit suitable for even high data rate applica-tions. MRD-310 also distinguish itself with a very high level of connectivity. It provides built-in two port 10/100 Ethernet switches and an RS-232 and thus easily allows devices to seam-lessly connect over a vast geographical distance. To extend the life of legacy equipment there are a number of tools included in the MRD-310 that will ensure connectivity with PLCs and other RS-232-based devices. The unit supports both packet and circuit switched mode, Serial to IP conversion, Modbus Gateway, DNP3 Level 1 Outstation and Dial-Up modem emula-tion.

Rod_Pump.jpeg: Individual oil pumps can be easily be monitored and controlled from a central control room using the MRD-310. The MRD-310 is a 3G/GPRS router that allows a secure IP connection to be established using IPSec encrypted VPN tunnels.

Westermo Teleindustri AbWestermo provides a full range of data communication and

Ethernet equipment and solutions for such demanding appli-cations as railways, aeronautics, military, water treatment, sub-station automation, roads and tunnels. The staff at Westermo provide the highest levels of service and technical support to help our customers to chose, configure and install the best solution for each specific application requirement. Our knowledge goes far beyond our own product range; we have a unique competence regarding your environment whether it is on a train, in airplanes, on the seabed or in a substation. To ensure a close relationship with the customer, Westermo has a local presence in more than 30 Countries. Westermo has three main product lines, Remote Access, Local Access and Indus-trial Ethernet, including more than one thousand different types and versions of modems, switches, routers, time servers or converters and the world’s fastest recovery time redundant Ethernet.For more information : http://www.westermo.com

Oilfield Automation with MRD-310 industrial 3G router

Intelligent Gateway from HMS Industrial Networks connects SAE J1939 networks to Siemens PLC systems

This new addition to the Anybus gateway family enables a Profibus-DP Master to read and write J1939 network data for control and monitoring tasks. The gateway

accomplishes this by operating simultaneously as a Profibus-DP Slave on a Profibus network and as a CAN node on a J1939 network. Data is exchanged from either network based on a user defined configuration. HMS provides a free Windows-based configuration tool (BWConfig) that allows the user to map J1939 parameter (PGN) data into the module’s input and output tables, accessible by the Profibus Master over the Pro-fibus-DP network.

With is rugged industrial design the device is designed for use across a wide variety of applications and industries. These include heavy duty equipment and vehicles used for agricul-ture, construction, fire and rescue, oil and gas, mining, power generation, motor control, material handling, trucking, mass-transportation and marine applications.

Typical uses include applications in oil & gas production, or on-vehicle applications where the gateway is used as an inter-face between the J1939 network and Profibus based industrial PLCs. On the Profibus side the gateway supports Profibus-DP Slave functionality with cyclic I/O data transmission and it can handle up to 244 bytes Input and 244 bytes of Output data. On the J1939 side the gateway supports up to 35 incoming J1939 transport protocol (large message) sessions and can monitor up to 120 different PGNs in the Input data point configura-tion and transmit up to 100 different PGNs in the Output data point configuration. The J1939 transport protocol (large mes-sage) handler rejects incoming session requests (both BAM and RTS/CTS) for PGN/Address pairs that are not configured as input data points.

The J1939 to Profibus gateway is the newest member of HMS’ Anybus gateway family which consist of more than 180 individual versions providing inter-network communications between almost any fieldbus or industrial Ethernet network.

HMS Industrial Networks is the leading independent sup-plier of embedded network technology for automation devices. HMS develops and manufactures solutions for inter-facing automation devices to industrial networks. Develop-ment and manufacturing takes place at the head office in Halmstad, Sweden.

Local sales and support is provided by the HMS branch offices in Chicago, Beijing, Karlsruhe, Milan, Mulhouse and Tokyo. HMS employs over 150 people and reported sales of 33 million in 2008. HMS was formed in 1988 and is listed on the NASDAQ OMX Nordic Exchange in Stockholm in the category Small Cap, Information Technology with ISIN SE0002136242.


In a highly successful 2007 book entitled “The World is Flat”, Pullitzer Prize winner Thomas Friedman argued in favour of the de facto revo-

lution of the global outsourcing phenomenon. Mr. Friedman convincingly made the case that in an economic world so arrantly connected, companies face a binary choice. Either they play along with the irrevocable forces of dislocating globalization or face extinction from invisible players sprawled across the barren landscape of second and third world countries.

What you see is notOutsourcing is globalization. And globalization

is outsourcing. What was, for the longest time, a strategy for buying expertise evolved over three decades into a ubiquitous drive to placate costs at all cost. Western economies, once the undisputed rulers of the manufacturing world ended up on the serf side of the ledger.

The West is no longer self-sufficient across the entire product life cycle. The West’s industrial titans set up Eastern shops in anticipation of boom-ing domestic and export bonanzas. The promised profit land never materialized. In its stead, China and India found themselves recipients of a fully mature, potent and unassailable manufacturing framework against which its originators are now utterly unable to compete. The West effectively taught, trained and equipped the East into its own economic master. The result: a staggering one-way transfer of technological acumen eastward.

The sublime vision of corporate managers, blinded by the promises of offshore economics and untapped markets, led to the complete dis-connect between thinking and building. This new-found dogma, now enshrined into management tenets of Western boardrooms, holds the process of innovation and creation in higher esteem than of interpreting them into products. Blissfully, Asia obliterated that specious dogma, to the utter dis-may of our corporate scions.

China and India do not outsource. They export. This “duh” moment makes it clear that engineering and manufacturing are not only inter-dependent but symbiotically indivisible. Friedman’s avocation of the flatness of the world is flawed. Its weakness surges in the quality and safety scares of Chinese export recalls of 2007 and 2008. The world isn’t flat after all; it is, at best, fractal.

Brilliantly executed mediocrityThe underlying assumption of outsourcing upon

the belief system that all can be communicated when a priori quantified. Or, in computer parlance, wysiwyg (what you see is what you get). One assumes that outsourcing is reducible to measur-able variables that can be coded through specifica-tions and numbers.

That assumption is fundamentally wrong. On the contrary, what you see is not (wysin). Ein-stein’s statement on commensurables goes to the very heart, the very foundation of the outsourcing debate, summed up in a single word: Ethics. There exists a generally accepted principle of respect for human life in the West. It is a deeply held tenet, one that pervades the mechanics of corporations and governments alike, (banking and insurance notwithstanding). There are such things as ethical

behaviour, pride of workmanship and concern for the safety of people that override the bottom line.

It is within this framework of ethics that we find the intrinsic connection between design and fab-rication (the thinking vs building argument). They form a symbiotic relationship that cannot be rent asunder without sacrificing the ethical values in the process. No safe product can arise from crap design nor safe design emerge from crap prod-ucts. It’s one thing to farm out pizza order taking or tooth pick production. It’s an utterly different thing to outsource the design and construction of a nuclear reactor to a country where human life has no value save its replaceable character.

In order to work, outsourcing requires that such intangible factors as ethics, safety and qual-ity of life will permeate, guide and constrain the manufacturing. These factors are woven into the very fabric of engineers’ mantra in the West. They are to the process of design what profitability is to CFOs. Therein lies the crux of the flaw in usual outsourcing proposition: where human life is nei-ther valued or respected, safety in design is an oxymoron whose cost cannot be justified. Where human dignity is crushed, there can be no impetus to design, or fabricate anything that upholds that dignity. Where people are valued strictly in terms of labour rates, output will be valued strictly in terms of labour costs.

There will be people to inveigh against this argu-ment. Yet, one cannot honestly deem irrelevant the notion that ethics and pride affect the entire prod-uct life cycle. Moral values guide the designer and the machinist.

Engineers will not design an explosion-prone fuel tank. Machinists will not leave sharp burrs on an exposed edge. Nobody knowingly builds a dan-gerous baby crib. These are values. These are ethi-cal stances that invariably colour everything that is done in the West.

Faith is not a strategyOutsourcing is all about cost. Or the lack thereof,

to be precise. Invariably, statistics on the number of foreign university graduates are used to support the cost and productivity benefits of their respec-tive work forces. And here again, the idealized flat-ness of this line of reasoning fails. There is no cor-relation between quality of training and quantity of trainees, save the statistical probability that a few will indeed be superior.

The opposite conclusion obtains; that is, mass production of graduates leads to lower qual-ity in the workforce. Pumping out programmers and engineers by the millions dilutes, rather than increase the talent pool. Doubling the manpower may speed things up, but it will not lead to the spontaneous emergence of a concern for quality or safety in the end product.

The cost argument is unavoidable. On the one hand, outsourcing based on labour costs can make accounting sense (all logistic factors aside). One may get more bang for the buck. But how many bucks will bang cost when all hell breaks loose? What is the risk embedded in a product whose design is driven by labour cost efficiency? What is the liability bred into a widget designed with safety first but built on the basis of absolute minimum cost?

Ultimately, outsourcing must be a risk-based strategic decision. What is more cost effective: thorough insight or regrettable hindsight? To every business challenge there is at least one simple and elegant solution. And it is wrong. Sometimes, it is not even wrong. Outsourcing can make sense. But sensing the merits of outsourc-ing on the sole basis of cents is spurious at best, criminal at worst. Economics is the measure of engineering. Engineering is ethics in action. Without ethics, you get lead-tainted painted toys and poisoned pet foods.

As a final thought, consider this simple question. Would you fly a plane designed in China, powered from America, controlled from the EU, and built in Sri Lanka?

The World is FractalBy Steven Keays M.A.Sc., P.Eng.

As a collaborative industry-initiative, Community Partners will encourage all sec-tors and companies to adopt and use this program and its tools to demonstrate our commitment to healthy stakeholder relationships. We expect to tell you more about Community Partners and reaction from community members in the coming months.

Will these outreach efforts make a difference? Time will tell. But some of the early feedback indicates some very positive results. We are already receiving email from the public and from industry employees with questions about the oil and gas sector – this tells us they are becoming engaged or re-engaged. We also know that industry employees are receiving PatchWorks and are telling us they’re finding the articles useful. Community Partners will be launched in September, and we expect to start receiving feedback soon thereafter. And so PSAC’s Public Outreach Program seems to be encouraging dialogue between industry and the public – a good sign that bridges are being re-built, and that mutual understanding is an end goal which may very well eventually be reached. For more on the Public Outreach Program, visit www.psac.ca.

Continued from page 7


All Terrian Road (ATR) received a positive response at the Global Petroleum Show in Calgary this year.

“I was taken a little bit by surprise about how positive it’s been,” said Craig Wronko, President of ATR.

“The international response has been excellent,” he added.

All Terrain Road Gains Popularity as Attitude Towards New Technologies ChangesBy Seema Dhawan

Wronko attributes this increase of interest to a more open attitude emerging to accept new technologies. He says companies are eager to understand how new technology can benefit their operations.

“There seems to be a real motivation on the owner’s part to look at new technologies and incorporate them into their operations,” said Wronko.

Owners are interested in these technologies from a safety, environmental and cost pers-pective.

The easy installation and movement of the ATR road system made it a popular pick at the show. The system is designed to accommodate environmentally sensitive areas such as rains land, green areas and has the ability to protect ice roads and permafrost.

“We have designed a composite mat that is really the world’s strongest and stiffest mat for its weight,” he said.

There are six different versions of the mats; including ones that are capable of a 90 degree directional change.

The bright yellow colour of the mats make them easily identifiable in the winter and low light conditions, a feature that enhances safety, especially for access roads and work surfaces.

“We have enabled companies to get into areas that they didn’t think they could access,” says Wronko.

As a result, companies have either finished projects ahead of time or got into areas they didn’t think they could until it was frozen, he adds.

On an average, a mat can be installed and connected in less than one minute. The record has been installing approximately 700 mats per day, which is just less than 2 kilometres of access roads.

The strong lightweight mats have the ability to float, are easily cleaned and transported.“It will always be on top of the surface in any time of type environment,” Wronko said.The mats also reduce transportation cost up to 80 per cent and can be transported by

helicopters.“We can transport a lot of mats out to a site very quickly at a very inexpensive cost,” he

added. “Every material on the mat is tested on a quality control basis so that when our customer

does get a product it’s going to be a product that is not going to fail them in the field,” Wronko said.

ATR plans to attend the Oil Sands trade show in Fort McMurray in September.


Accu-Lift 10K Hydraulic Catwalk Provides Safety, Performance and VersatilityBy Seema Dhawan

Accuform Welding Ltd’s (Accuform) Accu-Lift 10K hydrau-lic catwalk system provides a safe, high performance and versatile catwalk to the industry.

The system contains a self contained hydraulic system that utilizes an axial piston pump in a load sense system.

The versatile design of the unit works on several different rigs. It is also more stable as the pipe is always supported on the way up to the rig.

With Accuform’s standard catwalk, making one simple change to the V-door enables it to work on virtually any rig.

When the Adjustable Height V-Door feature is added to the Accu-Lift 10K catwalk, a number of different floor heights can be achieved with one catwalk. The Accu-Lift 10K hydraulic cat-walk system is designed to be safe, versatile and have excellent performance.

There is essentially no need for an operator to come into contact with the tubular because of the hydraulically operated gullwings, pipe rack and deck indexers, alignment rollers, and tubular kickers.

The catwalk can also be operated from the rig floor with the use of a wireless remote control. “There are a lot of different catwalks out there but this is different than any of them,” says Nathan Crossley, Operations Manager at Accuform. “Ours is more stable because it is always in contact with two points and there is no opportunity for the pipe to ever fall out,” he added.

The hydraulic system also has an intergraded cooling circuit that ensures cooling capacity, even when nothing is function-ing. “There’s a lot of interest in South America,” says Crossley.

A catwalk is also being currently built for a company in Alberta.

Accuform also provides 24 hour technical support and service.

Artificial Lift System Boosts Annual Revenue on Bakken Shale Well $845,000

Annual production from a horizontal well in the Bakken shale formation increased by 5,238 barrels after an operator in Saskatchewan, Canada, replaced a rod pump-ing system with a Centrilift electrical submersible pumping (ESP) system, boosting

annual revenue to $845,000.

Benefits from the system included:

• Revenue per year increased more than $419,000 (at $80/bbl oil price)• The Baker Hughes ESP system extended pumping system run life from an average

of three months to one year, saving an estimated $420,000 in annual workover costs• Power savings with the ESP system totaled $6,000 a year• Switching from the rod pump to ESP technology avoided shutting in the well, based

on the then-oil price of $35 per barrel

In the 1 1/2 years that the operator used the rod system, the well was worked over every three to four months for various downhole problems. The Baker Hughes lift solution initially increased oil production to 89 barrels of oil per day (BOPD) vs. 5.28 BOPD with the rod lift system. This production was achieved by drawing down the pressure on the tight Bakken shale formation, allowing additional oil to escape. The well soon reached a stable production level of 19.63 BOPD, significantly above the capability of the previous rod lift system.

In addition to increasing production, the Baker Hughes ESP system required only half the horsepower of the rod lift system, saving 50 percent ($500/month) in power costs.


Emerson’s DeltaV digital automation system promises to revolutionize electronic marshalling. Inspired by user feedback, the system repackages marshalling into a digi-

tal design.“We take our users very seriously,” says Leo Bello, Principal

Marketing Engineer at Emerson.

The DeltaV system is part of the Plant-Web architecture and includes a suite of digital busses, embed-ded advanced control and delivers precision control and predictive maintenance.

It offers a neat and clean replacement for field wiring, one of the most costly parts of the system. The conven-tional method is also time consuming and labour intensive.

This conventional system makes factory acceptance tests (FAT’s) complicated.

“We thought there’s got to be a better way to

do this,” says Bello. “We started doing this in a modern way, a digital way,” he

added.A module, known as a CHARM, converts the I/O informa-

tion to a digital form. The digital information is then collected on a digital base and through the use of Ethernet is made availiable for the rest of the control system.

The product offers huge benefits and savings says Bello. Customers often say, “Where were you 10 years ago?” he says.

”This is a simple idea, not rocket science, but [has] pro-found impacts,” he added.

This technology has huge potential to revolutionize how companies do projects in the future. It also reduces environ-mental impact as it significantly reduces the need for wiring and uses less energy.

“It’s as simple as a drag and drop on a computer, you don’t touch a wire,” says Bello.

The software behind the technology is modeled by Human Centered Design (HCD).

“We need to make this friendlier, easier for the human being that is operating this,” says Bello.

The software takes factors such as eye strain, colour con-trasts, pattern recognition and a study of how people interact with computers into consideration.

The system is also equipped with a database of expertise knowledge from more experienced operators of industrial plants.

“In the next 5 years, 40 per cent of that workforce is retir-ing,” says Bello. The database allows new operators to learn quickly and improves productivity.

“When your rookie comes he could have access to that bag-gage of knowledge that the experienced operator gave him,” he says.

The driving force behind the system is the company’s desire to make things easy for the human, Bello says. If an opera-tion previously took 20 clicks, Emerson wants to make it two clicks.

“We are fighting complexities,” says Bello.“It’s a charming system,” he adds.

Emerson Revolutionizes Electronic MarshallingBy Seema Dhawan

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