But shed no tears, it’s been a good life, and there may be a few more years of production left.
Some of the early SAGD oilsands wells have now produced a few million barrels of bitumen. That production was refined into about a half billion litres of gasoline, jet fuel or diesel for the combines in our fields, the machinery that builds our suburbs, the buses and cars that transport people of all persuasions to work, to exotic lands, to anti-oil protests or to their children’s soccer games.
Other barrels have become the materials we take for granted, from the rubber soles of our shoes to the glasses on our noses and the smart phones we seemingly can’t do without.
Admittedly, that bitumen came with some extra greenhouse gas (GHG) emissions compared to other crudes, about 10–12 per cent more based on a wells-to-wheels life cycle assessment. But there are even more GHG-intensive crudes such as California thermal oil. And ultimately, the consumer released the majority of the fossil fuel’s carbon emissions content in the pursuit of happiness.
So rather than blame the oilsands for providing the energy people want, it might be more effective to embrace our complicity in this vast human experiment and reconsider what people and societies desire. And in the meantime, a little sympathy for the aging SAGD well, a stalwart workhorse that’s just trying to do its job, is in order.
Some of these wells aren’t getting any younger, particularly those that came on stream at the turn of the millennium under Cenovus Energy Inc. at Foster Creek or at Japan Canada Oil Sands Limited at Hangingstone. Engineers are doing what they can to extend their golden days. Retirement isn’t what it’s cracked up to be when you’re a thermal. Soon the heating will get disconnected because you aren’t paying the bills, and the damp earth will start to cool and grip you in its silent embrace as memories of youth pass before your eyes.
“There are roughly five stages in the life cycle of a SAGD well,” says Jared Wynveen, associate with McDaniel & Associates Consultants Ltd., a firm that specializes in geological studies, reserves evaluations, resource assessments, economic evaluations and petroleum engineering studies.
After drilling and completing a well pair, well life begins with the circulation stage. The reservoir between the top injector well and the bottom producer needs to be heated by injecting steam to establish communication between the well pairs.
The circulation stage goes more predictably in clean sand than reservoirs with shale deposits, breccia and muds. Well trajectories that stray into second-tier reservoir areas can also cause problems, as can overly aggressive efforts to mobilize the exploitable zone, for example, going with an eight-metre well-pair spacing rather than the more typical five-metre separation.
“People overlook the importance of the circulation stage all the time, but it’s critical to seeing effective production,” Wynveen says. “If a producer doesn’t achieve a uniform voidage along the well pair in this early stage, they’re likely to have poor conformance [uniformity of the steam distribution] leading to poorer productivity down the road. We’re starting to see a lot of companies with early conformance issues.”
Rising steam to oil ratios (SORs are a measure of efficiency) at Cenovus’ older Foster Creek areas have prompted the company to evaluate its long-term reservoir management plan and apply new techniques. “It has led us to change some of the ways in which we start up wells and manage the reservoir,” said Brian Ferguson, president and chief executive officer, in a fourth-quarter conference call earlier this year. Cenovus now plans to inject steam into the wells and circulate for longer periods before bringing on full production.
After bitumen is sufficiently mobilized, the ramp-up stage begins with the conversion of the well pair into a full-time steam injector and a full-time bitumen producer.
“It’s good to clarify that in the circulation stage, you’re injecting and circulating from both wells [in the pair],” Wynveen says. “The conversion happens in the ramp-up stage, which sees pretty rapid vertical growth of the steam chamber and, to a lesser extent, horizontal growth, depending on the permeability distribution.”
Ideally, ramp-up takes less than a year. It ends when heat reaches the full reservoir thickness, or when its expansion becomes limited by permeability. Production growth levels off.
The higher the permeability, the faster the vertical growth of the chamber. “In the very best reservoirs like the Christina Lakes [both Cenovus and MEG Energy Corp. have Christina Lake projects] and in the Foster Creek [Cenovus], ramp-up stage may take only eight months,” Wynveen says. “But if you hit shale distributions within the reservoir, the total thickness of the package becomes less important than the reservoir thickness at that first reservoir baffle.”
Reservoir baffles, whether shale, breccia or mud, slow the expansion of the steam chamber. Continued steam injection will still grow the chamber horizontally to the edges of the baffles where secondary steam chambers will then expand vertically again. Ramp-up in reservoirs full of baffles can last many years, depending on the thickness of the overall package being heated.
Some Surmont (ConocoPhillips Canada), Long Lake (Nexen Energy ULC), and Hangingstone wells are examples. Hangingstone is similar in thickness and permeability to the Foster Creek reservoir, but production is only 500–600 barrels per day per well pair compared to 900 to over 1,000 barrels per day per well pair. Reservoir baffles are the main difference.
The upside of baffles is that this lower production will last a very long time.
There are some new technologies to shorten the ramp-up stage. At Christina Lake, which has some of the highest quality and thickest oilsands reservoirs, wells produces as much as 3,000 barrels a day. But even there, ramp-up of Cenovus’ initial wells took more than two years “to get notional production of 1,200–1,500 barrels a day,” Wynveen says. “With some newer completion techniques to increase early conformance, they’re now seeing productivity that’s more than 50 per cent higher in the ramp-up.”
One advance is high pressure steam pulsing to create dilation in the reservoir. “It’s still sub-frac pressure, but you’re trying to increase the near-well permeability” Wynveen says. “It’s dilating the reservoir to reorient the sand grains. By doing that, conformance is established in a far shorter period.”
Another innovation eliminates the interference of steam at the producing well, allowing the producer to draw more bitumen. ConocoPhillips has used this technology at Surmont with “very positive results,” according to Wynveen.
In full flight
The plateau stage of SAGD well life is reached when there is no more production growth. From a technology perspective, this is actually kind of a boring stage. The drainage area stays relatively constant even as the steam chamber continues to grow because the area that is being added roughly equals what is being depleted. This plateau typically lasts many years, but that varies as well depending on the reservoir. It can be as short as one year or as long as seven or more years.
The decline stage of a SAGD well is where some of the most intensive engineering efforts are being directed. The well has now produced about half of the recoverable volume. The steam chamber is still growing but horizontally under the cap rock and is experiencing greater thermal losses. Adjacent well-pair steam chambers are now coalescing.
If the operator maintains the same steam injection rate in the decline stage, the SOR will climb, which means the economics of the well are becoming less attractive. So technologies that dial back SORs are the order of the day.
Methane co-injection is one of these. Methane displaces steam at the leading edges of the steam chamber and creates a thermal buffer below the cap rock, slowing thermal losses and improving SORs.
(A related technology to methane co-injection is solvent co-injection, but this is actually an altogether separate technology to SAGD. A number of oilsands players have solvent co-injection pilots, including Connacher Oil and Gas Limited. Chris Bloomer, Connacher’s chief executive officer, described its proprietary SAGD+ solvent co-injection technology as “a bit of a game changer.” Three wells on the SAGD+ pilot project at Algar saw about a 25 per cent increase in overall bitumen production. The company has since obtained regulatory approval for the commercial process along with resources recognition.)
Another technology specific to the SAGD decline stage is the drilling of wedge wells. The wedges refer to the shape of the area between adjacent well pair steam chambers. These wedges have already absorbed some heat but not enough to mobilize the bitumen. They are at about 60 degrees Celsius as opposed to 200 degrees Celsius. Continued steaming will slowly chip away at those wedges, however, by drilling infill wells directly into these wedges and injecting some steam, that temperature is raised to 80 degrees Celsius or 100 degrees Celsius, and these wedge areas can be produced much more effectively.
“MEG implemented both methane injection and infill wedge wells at the same time and saw its already top-tier SORs of 2.4 drop to about 1.4,” Wynveen says.
By dropping the SOR, MEG was able to free up steam generation capacity for new well pairs in other areas of the reservoir and increase the overall production of the field. This is optimal timing for project expansions balanced against declines. If a producer doesn’t have new wells for redirected steam, reducing SORs in a declining area on its own isn’t particularly helpful since boilers run most efficiently at near maximum capacity.
“If you try to run a once-through steam generator at below capacity, whether you are running it at 95 per cent or 80 per cent capacity, the [natural] gas usage won’t be that dramatically different,” Wynveen says. “So realistically, you want to divert the steam to new wells.”
The end game for a SAGD well is blowdown, when steam injection is shut off. By now steam input costs outweigh production benefits. The wells have tapped in excess of 75 per cent of the recoverable bitumen. And yet, well life still isn’t over because the reservoir has years of latent heat stored within it, so it can continue to produce for years to come if pressure is maintained by injecting a non-condensable gas such as methane or air.
“We’re just getting to the blowdown stage,” Wynveen says. “Foster Creek is the only one that has any meaningful blowdown wells. The interesting thing is that we don’t know how long it will take to reach the end of the life cycle of a SAGD—other than relying on simulation. We don’t know how long the tail is going to be, but if you can continue to produce 100 or 70 barrels a day for the next five, six, seven or eight years, why not?”
A number of tricky issues also arise in this stage of life. Well economics drive the timing of well blowdown from the corporate perspective because it’s possible to over-invest in steaming a tired reservoir. But the regulator has a responsibility to the people of Alberta, so as long as there is production, it may not want to see a company go to blowdown too soon.
According to recent research by advisory firm Raymond James Ltd., Cenovus has applied for blowdown approval on additional pads to its Foster Creek Pad C, which was the first to start blowdown in 2013. The criteria for appropriate blowdown timing needs to be clarified.
Another consideration that every oilsands producer will eventually face is balancing pressures between the pads of different vintages. A pad of new wells next to a pad of old wells can pose challenges if the high pressure steam chamber breaks through to a steam chamber where pressures have been dialed back for years.
“It’s not so much a technology question as it is a reservoir management question,” Wynveen says. “We’re only now starting to see this.”
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