EX D: boundary of blast area, flattened trees

EX A: main crater at steam-release ground zero EX B: pipeline damage from rock projectile EX C: shale/siltstone rock projectile EX D: boundary of blast area, flattened trees CAP ROCK RUPTURE An explosive surface release of steam at Total E&P Canada s Joslyn Creek SAGD thermal operation in northeast Alberta created a 175-by-75-metre crater and launched debris up to a kilometre away. 1 New Technology Magazine May 2010

keep your cap on Three very different uses of technology aim to reduce cap-rock risk in thermal bitumen recovery especially in shallow reservoirs By Pat Roche New Technology Magazine May 2010 2

Shortly after dawn on a spring morning in 2006, the ground burst open beneath a wooded area of northeast Alberta, hurling rocks and trees into the air. By the time the dust settled some of it a kilometre away the fate of what may have been the world s shallowest thermal oil project was already sealed. GEOMECHANICAL ANALYSES A three-dimensional cutaway view of the model vertical permeability (md), with the 100 C isotherm (red) and the steam finger. The cap rock that was supposed to keep injected steam inside the bitumen reservoir at the Joslyn Creek steam-assisted gravity drainage (SAGD) project had been breached. SAGD projects inject high-pressure steam into reservoirs to heat bitumen (which is essentially a solid at the natural reservoir temperature) so it will flow to wells. After an investigation that lasted nearly four years, Alberta s oil and gas regulator concluded the underlying cause of the spectacular accident was that the operator, the Canadian subsidiary of French oil giant Total S.A., had significantly exceeded its approved steam injection pressure. The Energy Resources Conservation Board s recently released 177-page report said the eruption occurred at about 5:15 a.m. on May 18, 2006, near the heel of one well pair, creating a 125-by-75-metre surface disturbance and hurling rocks up to 300 metres horizontally from the main crater. The majority of this displaced material was deposited in the immediate area, but there was evidence of a fine dusting of material and rock across an area about one kilometre long by 100 metres wide to the southwest of the release point, the report said. Fortunately, no one was hurt and no harmful gases were released. Total has since de-booked the reserves associated with its Joslyn SAGD project, which it is abandoning. The incident was a blemish on the record of Canada s thermal oil industry, which had operated for decades without such a catastrophe. But Joslyn wasn t a typical project. I believe it was the world s shallowest thermal recovery project at the time. It was only 60 metres down. And so clearly there are going to be some challenges, says Peter Putnam, chairman of Petrel Robertson Consulting Ltd., a global geoscience consultancy based in Calgary. Putnam is also senior vice-president of geoscience with Osum Oil Sands Corp., a company started last decade to develop thermal bitumen projects in northern Alberta. The ERCB said Total is shutting down the Joslyn SAGD project based largely on the poor scheme economics due to operating pressure restrictions, monitoring requirements and shut-in well pairs. A company spokeswoman would only say the decision was based on a variety of economic factors, including world oil prices. Meanwhile, Total still plans to develop an open-pit mine to extract shallower bitumen deposits at Joslyn. The fact that the in-situ project is being abandoned and the facilities dismantled suggests the owner has concluded the bitumen resource targeted by the SAGD project can t be developed economically with that technology. An advantage of SAGD is it can be used in shallower reservoirs than cyclic steam stimulation (CSS), an older, higher-pressure thermal oil recovery technology. (Canada s first commercial CSS project began in 1985 but the first large-scale SAGD project didn t open till about a decade ago.) However, there is still a need for a technology to extract bitumen that is too shallow for conventional SAGD but too deep to mine economically. Examples of technologies designed to bridge that gap include Osum s proposed underground drilling rigs (New Technology Magazine, July 2006) and E-T Energy Ltd. s in-situ electric heaters (NTM, March 2007). Both companies are Calgary-based start-ups. 3 New Technology Magazine May 2010

In-situ rigs Subterranean drilling rigs are a long-term goal for Osum. In the short and medium term, the company plans to use standard thermal technology. The company recently filed a regulatory application for a 35,000-barrel-a-day project that would use both SAGD and CSS to recover bitumen in the commercially established Cold Lake oilsands region of northeast Alberta. Osum will also use standard drilling technology in a pilot test planned with Laricina Energy Ltd. in bitumen-bearing carbonate rock at Saleski, about 120 kilometres west of Fort McMurray. Commercial exploitation of Alberta s vast bitumen carbonate resource has yet to occur. Privately held Osum has no production yet, but has raised $375 million. Only after the company has established commercial operations does it plan to test underground drilling rigs. This isn t as farfetched as it seems and not just because it s been used for decades in the tunnelling and mining industries. Few people are aware this was actually done in the heart of the Alberta oilsands. The setting was the Underground Test Facility, the incubator of SAGD. The Underground Test Facility was started in the mid-1980s by the Alberta Oil Sands Technology and Research Authority (AOSTRA), an Alberta government/private-sector partnership that played a key role in commercializing the oilsands. The Underground Test Facility was built within a limestone formation roughly 175 metres beneath the surface near Fort McMurray. It consisted of two vertical shafts, each more than three metres in diameter, and a horseshoe-shaped horizontal tunnel about five metres wide and four metres high. A small, custom-built drilling rig was brought inside this tunnel, which was beneath the bitumen-bearing McMurray sands. Horizontal wells were drilled through the limestone up into the overlying oilsands reservoir. It could develop very shallow reservoirs much more safely because it could run at much lower pressure, Putnam says of the concept. The lower the operating pressure, the less chance of steam breaking through cap rock. Oil and water would flow via gravity into a collection tank underneath the reservoir and be pumped to [The UTF] had one of the lowest steam/oil ratios and one of the highest recovery factors of any McMurray thermal recovery project. And it was never optimized because it wasn t there to be maximally efficient. It was there to prove a concept. surface from there. Eliminating the need to lift fluids from every wellbore would allow much lower operating pressures thus reducing the chances of breaching the cap rock. Putnam says another advantage is fewer wells would need to be drilled from surface to delineate the bitumen resource. The fewer holes punched in the cap rock, the less danger of it being compromised. Osum insists the overall capital cost of underground drilling rigs would be no more than surface-based rigs. Drilling costs a major component of SAGD capital budgets would be lower because well pairs wouldn t have to be drilled through the overburden and hence would be much shorter. There would be no need for a pump in every wellbore, a big saving in capital and operating costs. By pumping fluids from a single collection point (rather than from every wellbore), fuel consumption would be reduced. Underneath the reservoir the temperature is 15 C all year, says Putnam, so many weatherrelated drilling and production issues would be eliminated. (Steam and water-handling facilities would still be located at surface.) While the idea of working underground may give some people visions of Chinese coal mines, subways that safely move millions of commuters every day are also underground. And Osum is only proposing the idea for shallow reservoirs. Putnam notes there is minimal methane in McMurray bitumen. The Underground Test Facility ran for over a decade [and] had a superb safety record. PIONEERING RESEARCH Carved out of the limestone about 175 metres deep, the Underground Test Facility near Fort McMurray played a vital role in the early development of steam-assisted gravity drainage. While the underground-rigs concept has never been proved commercially, Putnam says there is no question about the technical feasibility. The Underground Test Facility proved all this, he says. It had one of the lowest steam/oil ratios and one of the highest recovery factors of any McMurray thermal recovery project. And it was never optimized because it wasn t there to be maximally efficient. It was there to prove a concept. In-situ heaters Electric heat may be another way to avoid SAGD shocks. E-T Energy installs electrodes in 100-metre vertical wells to melt the bitumen so it can be produced from wells. Since steam isn t used, there are no concerns about injection pressures breaching the cap rock. In fact, the system is pressure neutral, says Bruce McGee, E-T Energy s president. (Royal Dutch Shell plc experimented with a different type of electric heaters in deeper Alberta bitumen deposits with the more ambitious goal of upgrading in the reservoir. New Technology Magazine May 2010 4

PLUG IN PRODUCTION E-T Energy has field tested its electric heat process intermittently in recent years near Fort McMurray. Shell reported positive results (NTM, June 2008), but put the work on hold shortly after the September 2008 financial crash.) Privately held E-T (the letters stand for electro-thermal) Energy has intermittently field-tested its electric heat process over the past few years. The company is currently testing some commercial features in the electrode well completion and awaiting regulatory approval for a 10,000-barrel-aday project, says McGee. Since the project was unveilled the economics have improved because bitumen prices have climbed and electricity costs have fallen, says McGee, who has a doctorate in electrical engineering and a degree in chemical engineering. As this article went to press the company was in business discussions with an industry partner and hence restricted in what could be disclosed about planned developments. McGee estimates a 10,000-barrel-a-day project would cost $150-160 million. E-T Energy hopes the second phase of testing will provide definitive data on how much energy will be consumed to produce a barrel of bitumen, recovery factors and commercial execution strategies. How not to get burned in thermal oil In-situ heaters and underground drilling rigs are technologies that have yet to see commercial application. But what about existing thermal recovery methods? Combined output from Alberta s CSS and SAGD projects is now more than half a million barrels of oil a day. What can SAGD and CSS developers do to optimize performance while mitigating the risk of compromising cap rock integrity? Operators of steam-assisted bitumen projects want to maximize daily production and ultimate recovery. In an ideal world, an operator could do this by simply cranking up the steam injection pressure. But in the real world, there are two significant constraints. One constraint is economic. Almost all SAGD projects burn natural gas to boil water to make steam. With even the best projects burning one mcf of gas to extract one barrel of bitumen, a low steam/oil ratio is a key goal. The other constraint is safety and environmental excessive operating pressures can lead to groundwater contamination or, in the worst-case scenario, the kind of catastrophic failure that occurred at Joslyn. These challenges have been pondered by two Calgary employees of one of the world s biggest oilfield service companies. Schlumberger s David Bexte, heavy oil sales manager, and Stan Cena, data and consulting services sales manager, are preparing a paper on the subject. The first step in planning a thermal oil project is to know exactly what nature has provided and to avoid assumptions based on insufficient sampling. The next step is to try to predict how the reservoir and surrounding rock will change during steam injection and oil extraction. Steam injection raises pressure and temperature well beyond the natural reservoir conditions. As steam is injected, the reservoir expands as pore spaces dilate to hold the extra fluid. And during production the sands compact as oil drains from the pore spaces. In cyclic steam operations where wells cycle between steam injection and oil production the dilation/compaction cycles are observable at surface. The September 2002 issue of NTM describes ground heave as steam is injected, and subsidence as fluids are produced a visual clue of why cyclic steam is called huff and puff. SAGD, on the other hand, continuously injects steam and produces oil through dedicated injector and producer wells. But it, too, has its cycles. Bexte points out SAGD undergoes cycles due to surface activities such as plant turnarounds and other temporary shutdowns, and it undergoes cycles in the subsurface as different areas of the reservoir become depleted or become active, and as steam chambers start to merge between nearby well pairs. The magnitude of these cycles is something to be measured, or inferred, says Bexte. But it s certainly not something that should be assumed because they all interrelate to each other. We, as an industry, definitely need to take a holistic approach in how we evaluate the performance of the reservoir. And although SAGD may be less cyclical and use lower injection pressures than cyclic steam operations, Bexte and Cena contend that the shallow formations where SAGD is used are particularly susceptible to cap rock damage. The bottom line: changes in pressure, temperature and volume can alter rock stresses and, over time, the fabric of the rock itself. These changes occur not only in the reservoir but also in the surrounding boundary layers that are crucial to steam and hydrocarbon containment. According to Bexte and Cena, the changes can be used to optimize project performance, depending on how well they re understood and the harmful effects mitigated. To understand these effects, they say, it is necessary to examine the geomechanics of the reservoir and boundary layer system. 5 New Technology Magazine May 2010

Geomechanics predicts changes in rock properties based on the integration of core, well log, well test, seismic and surface data. This requires extensive subsurface data at the outset of a project, updated with data from ongoing monitoring techniques such as time-lapse seismic and microseismic. This is integrated into a predictive system such as Schlumberger s Visage reservoir geomechanics modelling system. Schlumberger s Visage system uses calculated pressures, temperature and oil saturation to predict the behaviour of the reservoir rocks under existing and imposed stresses. It can be coupled to a reservoir simulator to model the flow of fluids in the reservoir and calculate the pressure, temperature and saturation changes that result. In a draft of an as-yet unpublished paper they re co-authoring, Bexte and Cena write: A geomechanical simulation begins with a 3-D structural model which is then populated with geomechanical data from the reservoir and boundary formations to build an Earth model. Boundary conditions are added to simulate the stress profiles at the sides of the model. In contrast to reservoir models, mechanical Earth models take into account overburden, underburden (the rocks beneath the reservoir) and sideburden (adjacent rock which often provides boundary conditions). These models have substantial data requirements that can be difficult to fulfil and are larger than reservoir models. The models use data such as porosity measurements at pressure, vertical variability in rock strength, cluster analysis of well logs, core measurements and The magnitude of these cycles is something to be measured, or inferred. But it s certainly not something that should be assumed because they all interrelate to each other. We, as an industry, definitely need to take a holistic approach in how we evaluate the performance of the reservoir. core-log integration. Core must be obtained in the boundary layers as well as the reservoir. Well logs should also be run over the entire section, including a sonic scanner to measure the in-situ stress regime. A baseline 3-D seismic survey should be taken. Well log data is calibrated to core and seismic data. The mechanical Earth model is then imported into Schlumberger s Visage system to simulate the evolution of stresses caused by pressure and temperature changes due to steam injection and production of fluids. Fluid flows are calculated using a reservoir simulator. Schlumberger says these pressure and temperature changes are accounted for in Visage, providing a prediction of changes in formation stresses over time. Bexte and Cena say geomechanical analysis and modelling can help optimize project design and operating parameters. This improves project economics and reduces the chances of project failures. Thermal future Because of the unusually shallow depth of its reservoir and its catastrophic failure, Joslyn is unique in Canadian thermal oil history. But that doesn t mean other projects have been problem free. In a research note in January, Peters & Co. Limited said Husky Energy Inc. s Tucker SAGD project was trickling out less than 5,000 barrels of bitumen a day with a cumulative steam/oil ratio of 11. Tucker was designed to produce 30,000 barrels a day within 18 to 24 months of its November 2006 start-up. More recently, the ramp-up of Canadian Natural Resources Limited s Primrose East CSS project was significantly delayed after oil seeped to the surface. Other projects such as Nexen Inc. s Long Lake, Suncor Inc. s Firebag and ConocoPhillips Company s Surmont have struggled to ramp up production for a grab bag of reasons. None of this means thermal oil technology is a failure. Far from it. Canada s first large-scale commercial SAGD project was built a mere a decade ago. Today, Canada s total SAGD output is approaching 300,000 barrels a day. Thermal oil projects such as Imperial Oil Limited s Cold Lake, Cenovus Energy Inc. s Foster Creek, Devon Energy Corporation s Jackfish and Petro-Canada s (now Suncor s) MacKay River are successes everyone wants to copy. The prize is huge. About 80% of the 170 billion barrels of bitumen the Alberta government deems recoverable is too deep to mine economically. So it s safe to assume the technology innovation and optimization that has been the story of Alberta s oilsands will continue as a growing number of global players stake their claims in one of the world s largest hydrocarbon resources. CONTACTS FOR MORE INFORMATION: Peter Putnam, Osum, Tel: (403) 283-3224, Email: pputnam@osumcorp.com Bruce McGee, E-T Energy, Tel: (403) 569-5101, Email: bmcgee@e-tenergy.com David Bexte, Schlumberger, Tel: (403)-509-4000, Email: bexte1@exchange.slb.com New Technology Magazine May 2010 6