- Japan, 2011
- Indian Ocean, 2004
Friday, January 25, 2013
Tsunami - Japn, 2011
To add some additional visuals to our recent discussion of tsunamis, seismic sea waves. Watch the video below. Spend some time watching other videos on YouTube of two tsunami events:
- Japan, 2011
- Indian Ocean, 2004
- Japan, 2011
- Indian Ocean, 2004
Sunday, January 20, 2013
Resource Use and Conservation
During the first trimester, we devoted an entire chapter to the study and discussion of natural resources. We learned about resources utilized today along with efforts to wisely use those same resources and preserve them for future generations.In conjunction with a print article, Scientific American created an interactive version by the same title," How Much Is Left?"
Click the link to read it: Scientific American Interactive: How Much Is Left?
Monday, January 14, 2013
Dust Bowl
In conjunction with 2012 being called the warmest year ever for the lower-48 states and the conclusion of our discussion of the Dust Bowl, which in the opinion of many scientists, is the worst natural/environmental/manmade disaster to befall the United States, I thought a related post was in order. One natural factor (the population of the plains states was not without blame) contributing to this terrible chapter in the history of this great nation was the drought. The drought began around 1931 and continued through the end of the decade.
To help give some perspective on the intense heat waves during this period, I posted a column from Weather Underground.
The Great Heat Wave of 1936; Hottest Summer in U.S. on Record
As the eastern two-thirds of the United States continues to swelter under some of the hottest temperatures seen in recent years I thought it opportune to look back at the nation’s worst heat wave and hottest summer in history, that of 1936.
1936; A Year of Extremes
The climatological summer (June-August) of 1936 was the warmest nationwide on record (since 1895) with an average temperature of 74.6° (2nd warmest summer was that of 2006 with an average of 74.4°) and July of 1936 was the single warmest month ever measured with an average of 77.4° (beating out July 2006 by .1°). Ironically, February of 1936 was the coldest such on record with an average nationwide temperature of 26.0° (single coldest month on record was January 1977 with a 23.6° average). In February of 1936 temperatures fell as low as -60° in North Dakota, an all-time state record and Turtle Lake, North Dakota averaged -19.4° for the entire month, the coldest average monthly temperature ever recorded in the United States outside of Alaska. One town in North Dakota, Langdon, went for 41 consecutive days below zero (from January 11 to February 20), the longest stretch of below zero (including maximum temperatures) ever endured at any site in the lower 48.
With this in mind, it is truly astonishing what occurred the following summer. The temperature in North Dakota that had reached -60° on February 15 at Parshall rose to 121° at Steele by July 6, 1936. The two towns are just 110 miles from one another!
The Great Heat Wave
JUNE 1936
June of 1936 saw unusual heat build initially in two nodes, one centered over the Southeast and another over the Rocky Mountains and western Plains. This differs from the current heat wave that began mostly over Texas and the Deep South.
By the end of June 1936 all-time state monthly records for heat had been established in Arkansas (113° at Corning on June 20th), Indiana (111° at Seymore on June 29th), Kentucky (110° at St. John on June 29th), Louisiana (110° at Dodson on June 20th), Mississippi (111° at Greenwood on June 20th), Missouri (112° at Doniphan on June 20th), Nebraska (114° at Franklin on June 26th), and Tennessee (110° at Etowah on June 29th). A total of 8 states and all these monthly records are still standing.
JULY 1936
By July the dome of heat locked in place over the central and northern Great Plains and remained there for the entire month.
Around July 8-10 the ridge briefly extended all the way to the East Coast when virtually every absolute maximum temperature record was broken from Virginia to New York. This held true for most sites in the Ohio Valley, Upper Midwest, and Great Plains as well. There are so many superlatives that it is impossible to list them all. In short the following states broke or tied their all-time maximum temperatures that July:
Add to the above list a 120° reading at Gann Valley, South Dakota on July 5th. Unfortunately I am unable to update the table with this record since it would involve rewriting and posting the table (not an easy task!). Sorry for the omission!
Some of the many major cities to record their all-time maximum temperatures during July 1936 included:
On July 15th the average high temperature for all 113 weather stations in Iowa measured 108.7°. Similar to the current heat wave the nighttime low temperatures were also remarkably warm. Bismarck recorded a low of just 83° on July 11th. Milwaukee, Wisconsin endured five consecutive nights above 80° from July 8-13. Even near the normally cool shores of Lake Erie amazing temperatures were recorded such as the low of 85° and high of 110° at Corry, Pennsylvania on July 14th. And most amazing of all was the low of 91° at Lincoln, Nebraska on the night of July 24-25th warming to an all-time record of 115° on the 25th.
Residents of Lincoln, Nebraska spend the night on the lawn of the state capital on July 25, 1936. The temperature that night never fell below 91°, perhaps the warmest night ever recorded anywhere in the United States outside of the desert Southwest. Photo from the Nebraska State Historical Society.
AUGUST 1936
By August the heat dome shifted a bit further south from its position over the northern Plains and became anchored over the southern Plains.
More all-time state records were broken or tied:
Oklahoma City also broke its all-time heat record with a high of 113° on August 11th as did Kansas City also with 113° on August 14th and Wichita with 114° on the 12th. The list just goes on and on.
All in all, nothing like this heat wave has before or since occurred. It is hard to believe how people fared without air-conditioning, although there were some rudimentary forms of such:
When the temperature peaked at an all-time high of 108° in Minneapolis, Minnesota, the want-ad staff at the 'St. Paul Daily News' was provided with 400 pounds of ice and two electric fans to cool the air in the press room. Photo from the Minnesota Historical Society.
The only saving grace was that, unlike the current heat wave, humidities were low as a result of the ongoing and prolonged drought which had been affecting almost all of the central part of the country for several years come the summer of 1936. This is also probably one of the reasons that such anomalous extreme high temperatures were recorded.
Seventeen states broke or equaled their all-time record absolute maximum temperatures during the summer of 1936 (still standing records).
Below is a map reproduced from my book Extreme Weather: A Guide and Record Book that summarizes some of the records broken during the summer of 1936:
To help give some perspective on the intense heat waves during this period, I posted a column from Weather Underground.
The Great Heat Wave of 1936; Hottest Summer in U.S. on Record
As the eastern two-thirds of the United States continues to swelter under some of the hottest temperatures seen in recent years I thought it opportune to look back at the nation’s worst heat wave and hottest summer in history, that of 1936.
1936; A Year of Extremes
The climatological summer (June-August) of 1936 was the warmest nationwide on record (since 1895) with an average temperature of 74.6° (2nd warmest summer was that of 2006 with an average of 74.4°) and July of 1936 was the single warmest month ever measured with an average of 77.4° (beating out July 2006 by .1°). Ironically, February of 1936 was the coldest such on record with an average nationwide temperature of 26.0° (single coldest month on record was January 1977 with a 23.6° average). In February of 1936 temperatures fell as low as -60° in North Dakota, an all-time state record and Turtle Lake, North Dakota averaged -19.4° for the entire month, the coldest average monthly temperature ever recorded in the United States outside of Alaska. One town in North Dakota, Langdon, went for 41 consecutive days below zero (from January 11 to February 20), the longest stretch of below zero (including maximum temperatures) ever endured at any site in the lower 48.
With this in mind, it is truly astonishing what occurred the following summer. The temperature in North Dakota that had reached -60° on February 15 at Parshall rose to 121° at Steele by July 6, 1936. The two towns are just 110 miles from one another!
The Great Heat Wave
JUNE 1936
June of 1936 saw unusual heat build initially in two nodes, one centered over the Southeast and another over the Rocky Mountains and western Plains. This differs from the current heat wave that began mostly over Texas and the Deep South.
By the end of June 1936 all-time state monthly records for heat had been established in Arkansas (113° at Corning on June 20th), Indiana (111° at Seymore on June 29th), Kentucky (110° at St. John on June 29th), Louisiana (110° at Dodson on June 20th), Mississippi (111° at Greenwood on June 20th), Missouri (112° at Doniphan on June 20th), Nebraska (114° at Franklin on June 26th), and Tennessee (110° at Etowah on June 29th). A total of 8 states and all these monthly records are still standing.
JULY 1936
By July the dome of heat locked in place over the central and northern Great Plains and remained there for the entire month.
Around July 8-10 the ridge briefly extended all the way to the East Coast when virtually every absolute maximum temperature record was broken from Virginia to New York. This held true for most sites in the Ohio Valley, Upper Midwest, and Great Plains as well. There are so many superlatives that it is impossible to list them all. In short the following states broke or tied their all-time maximum temperatures that July:
Add to the above list a 120° reading at Gann Valley, South Dakota on July 5th. Unfortunately I am unable to update the table with this record since it would involve rewriting and posting the table (not an easy task!). Sorry for the omission!
Some of the many major cities to record their all-time maximum temperatures during July 1936 included:
On July 15th the average high temperature for all 113 weather stations in Iowa measured 108.7°. Similar to the current heat wave the nighttime low temperatures were also remarkably warm. Bismarck recorded a low of just 83° on July 11th. Milwaukee, Wisconsin endured five consecutive nights above 80° from July 8-13. Even near the normally cool shores of Lake Erie amazing temperatures were recorded such as the low of 85° and high of 110° at Corry, Pennsylvania on July 14th. And most amazing of all was the low of 91° at Lincoln, Nebraska on the night of July 24-25th warming to an all-time record of 115° on the 25th.
Residents of Lincoln, Nebraska spend the night on the lawn of the state capital on July 25, 1936. The temperature that night never fell below 91°, perhaps the warmest night ever recorded anywhere in the United States outside of the desert Southwest. Photo from the Nebraska State Historical Society.
AUGUST 1936
By August the heat dome shifted a bit further south from its position over the northern Plains and became anchored over the southern Plains.
More all-time state records were broken or tied:
Oklahoma City also broke its all-time heat record with a high of 113° on August 11th as did Kansas City also with 113° on August 14th and Wichita with 114° on the 12th. The list just goes on and on.
All in all, nothing like this heat wave has before or since occurred. It is hard to believe how people fared without air-conditioning, although there were some rudimentary forms of such:
When the temperature peaked at an all-time high of 108° in Minneapolis, Minnesota, the want-ad staff at the 'St. Paul Daily News' was provided with 400 pounds of ice and two electric fans to cool the air in the press room. Photo from the Minnesota Historical Society.
The only saving grace was that, unlike the current heat wave, humidities were low as a result of the ongoing and prolonged drought which had been affecting almost all of the central part of the country for several years come the summer of 1936. This is also probably one of the reasons that such anomalous extreme high temperatures were recorded.
Seventeen states broke or equaled their all-time record absolute maximum temperatures during the summer of 1936 (still standing records).
Below is a map reproduced from my book Extreme Weather: A Guide and Record Book that summarizes some of the records broken during the summer of 1936:
Thursday, January 10, 2013
Vanishing Glaciers
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Wednesday, January 2, 2013
Tar Sands - An Energy Panacea?
If you remember Chapter 4 (the natural resources chapter), we discussed the tar sand sands in Canada and other locales. Included in the discussion (as we did for all natural energy resources) were the pro's and con's of each. Greenhouse gas emissions and serious site degradation were two big con's. Find below an excellent article from Scientific American regarding recent improvements to extraction technologies and the remaining hurdles.
The Opposite of Mining: Tar Sands Steam Extraction Lessens Footprint, but Environmental Costs Remain
Melting bitumen in place is less unsightly than mining tar sands, but increasing efficiency, lowering costs and--perhaps most importantly—minimizing greenhouse gas emissions remain challenges
MELTING TAR: A production well, like the one pictured here at Cenovus's Christina Lake facility, sucks bitumen melted by steam out of the ground--an alternative to strip mining for tar sands.Image: © David BielloMore In This Article
CONKLIN, Alberta—The challenge of pulling oil from sand near here has typically required scraping away the boreal forest and underlying peat to expose the tar sand deposits below. The thickened sand is scooped out, then boiled to separate out the bitumen, with the leftover contaminated water and muck dumped in vast holding ponds the size of small lakes. From orbit the enormous strip mines and tailings lakes created by this process stand out, like a spreading sore—a scar on the planet evidencing the American thirst for oil. But the future of this Canadian province's oil sands leaves less of a visible mark, as can be seen near this town that is not so much a community as an intersection of roads that lead to camps for oil sands workers. That means fewer strip mines, tailings lakes and even giant trucks, but it also means more of the invisible greenhouse gas carbon dioxide accumulating in the atmosphere and warming the planet.
This future is melting bitumen where it lies at least 200 meters below the surface rather than mining tar sands. In 2011 more than 11,000 barrels of bitumen were melted out of the frozen ground not far from here each day, where the airstrip sees more human traffic than the town as workers commute in and out by plane from as far away as Newfoundland.
"Most of what's going on happens 375 meters below the surface," says Greg Fagnan, director of operations and production at Cenovus's Christina Lake oil sands production facility, during a recent tour. Cenovus extracts bitumen by employing a technique called steam-assisted gravity drainage, which can be thought of as the opposite of mining. Instead of melting the bitumen out of sand in an industrial plant after clawing the tar sands out of the ground, Cenovus melts it out in place with steam. That means Christina Lake is, in a sense, a giant water-processing facility "that happens to produce oil," Fagnan says. "It's not a complicated business, it's just complex."
Conklin is one of the frontier towns of a new tar sands boom, given that 80 percent of the at least 170 billion barrels in the Canadian province's tar sands are only accessible this way rather than by mining. In 2011, for the first time, oil production from such in situ operations surpassed that of mining for oil in the tar sands—a trend that is only likely to increase as more oil sands production comes online in Canada. Already, plumes of steam billow from the boreal forest across northeastern Alberta where a host of developers work—from Nexen, recently acquired by the China National Offshore Oil Corp. (CNOOC), to oil majors such as Royal Dutch Shell—like mushrooms springing up from the ground after rain.
But this recovery of bitumen in place will have to continue to improve its efficiency and cost if it is going to compete with other fast-growing oil recovery technologies, such as fracturing rock with high-pressure water, or fracking, to release trapped oil. As it stands, Alberta is estimated to hold more than 400 billion barrels of such "tight oil," which is already being produced in places like North Dakota's Bakken Shale by the number-one customer for Canada's tar sands oil: the U.S.
Melting tar
Steam dominates the Christina Lake facility, where mushroom clouds rise into the wintry blue sky, pierced only by the orange glow of a flare near the bitumen processing plant. Nine industrial boilers, powered by natural gas, heat treated brine from nearby aquifers to 350-degree-Celsius to inject it as steam into what can be likened to three giant, underground sandboxes—vast rectangular blocks of oil-bearing sand. Each sandbox is pierced by pairs of pipes, one perforated to release pressurized steam along its 800-meter length and melt oil from the tar sands, another to suck melted bitumen, bits of sand, water and natural gas with electric pumps back up to the surface. The pipes are strung with sensors, gauges and fiber optics, or "jewelry" in the industry jargon, that allow well operators back at the surface to continually monitor conditions under the earth, such as the steam pressure that starts out at a crushing 120-kilogram-force per square centimeter. Christina Lake pumps out a barrel of oil for every 2.3 barrels of injected steam.
Cenovus claims to use just 0.07 barrel of freshwater to produce each barrel of oil at Christina Lake, thanks to the recycling and almost exclusive use of brackish waters. According to the Royal Society of Canada's 2010 report on such tar sandsdevelopment, a typical facility uses 0.6 barrel of freshwater and 0.4 barrel of brine per barrel of oil. "Conventional oil from the Saudis uses more water than the [steam-assisted gravity drainage] process," says geologist John Zhou, executive director of environmental management at Alberta Innovates, a government-funded technology innovation effort.
Drilling the wells themselves presents the first challenge. During installation, the pairs of wells in each sandbox site are drilled simultaneously, rigorously maintaining a spacing of only five meters apart, with a rig specially modified for this kind of oil sands exploitation. At each site, or well pad, roughly eight such wells are drilled, lining up side by side—on one side eight or more steam injectors and on the other a matched number of oil-producing wells.
After a few years of production, such as at Cenovus's older Foster Creek facility started up in 2001, additional wells are drilled to recover oil from the wedges of tar sand between each steam-created balloon-shaped melt zone. Such wedge wells have enabled Cenovus to add 20,000 barrels of production per day to Foster Creek without requiring any additional steam—and a given well is expected to produce for roughly 20 years, though no well is yet that old.
"These fields are really like laboratories," says Cenovus spokesman Brett Harris, and operators are making continual adjustments and suggesting improvements, such as pumps that can withstand the high temperatures underground but also run on electricity rather than natural gas. Operators are also constantly adjusting the flow of steam, closing off sections of the perforated pipe to shut off heat to certain sections and ensure even melting throughout. Such in situ production has always been experimental, starting with the first attempt back in 1926: The pipes available at the time could not withstand the steam's heat and pressure, resulting in a steam explosion that destroyed the start-up plant and injuries to entrepreneur Jacob Owen Absher, among others.
That is not a problem that has entirely disappeared. Oil company Devon Canada actually used too much pressure on its subterranean sandbox and caused a blowoutthat shot scalding steam and bitumen into the sky in the summer of 2010 near here, and Total Energy caused a similar explosion of steam, oil and rock north of Fort McMurray in 2006. The steam pipelines themselves have also blown as a result of cooled water trapped inside. Such a "water hammer" has tossed pipelines as much as a kilometer, Cenovus's Fagnan says, leaving them sticking out of the ground like toothpicks embedded more than three meters deep. The steam "packs a pretty big punch," he says.
Better engineering
The engineering challenges faced by in situ projects range from a lack of a sufficient seal above the oil sands deposit—allowing steam to escape without melting oil or, even worse, the oil itself to flow away—to underlying aquifers, or "thief zones," that can quench barrel after barrel of steam heat. And that's after the expensive well pairs have been put in place. At Christina Lake the reservoir sits below a layer not of rock, but of natural gas—and that means Cenovus operators must continually inject air to ensure that the gas pressure matches or exceeds the pressure of the pumped in steam, so the steam doesn't escape without doing its melting work.
The ultimate engineering challenge of the tar sands, however, may be coping with greenhouse gases. As a result of increasing in situ production, greenhouse gas emissions from Alberta's tar sands rose by 1.7 percent last year, and are up 16 percent since 2009, according to the Canadian Association of Petroleum Producers. The newly dominant in situ technology produces oil at a cost of 2.5 times more CO2 emitted to the atmosphere than the more brute-force, conventional mining. Whereas this may be equivalent to what's emitted when using steam to flood out heavy oils in California or Nigeria, neither of those sources of greenhouse gases is growing as fast as the tar sands.
In an effort to get ahead of this climate challenge, Alberta has invested more than $1.5 billion in developing CO2 capture and storage (CCS) technology. But it has yet to be applied to an in situ operation; the one current project in the oil sands involves capturing CO2 emissions from mini-refineries at Shell's operation near Fort Saskatchewan, a project dubbed Quest. That project is slated to open in 2015 and there are, as yet, no plans for CO2 capture and storage at any in situ facilities.
The Pembina Institute, a Canadian environmental group, estimates that it would cost more than $200 per metric ton of CO2 to add CCS to tar sands production facilities like Christina Lake. Alberta's current price on CO2 is $15 per metric ton. "The trick is to find a way to make capture and storage economic," Harris says, noting that Cenovus has done exactly that at its Weyburn enhanced oil recovery project in Saskatchewan. The company uses CO2 captured at a gasification plant across the border in North Dakota to scour more oil out of the ground—and the extra oil produced helps pay for the CO2 capture process, although the oil also ends up contributing to the growing greenhouse gas burden when burned.
Reducing energy use, then, may prove a better route. By using solvents, such as the hydrocarbon butane, in situ producers can boost the bitumen recovery ability of the steam itself. Cenovus has been testing the process at Christina Lake since 2004 and will implement it at the company's newly approved Narrows Lake project, slated to start producing oil in 2017. Using such solvents "can drop the energy consumption by as much as 50 percent," says chemical engineer Murray Gray, scientific director of the Center for Oil Sands Innovation at the University of Alberta.
Such new technology means more cost to develop and produce what is already among the most costly forms of oil, Gray notes. At present, Cenovus spokesman Harris says that the company needs to earn at least $35 per barrel of oil. With West Texas Intermediate grade oil at $85, that is not a problem, except for the atmospheric warming. And it's not as if in situ development has no impact on the land: there's the industrial plant for producing steam and processing bitumen, tank farms to hold the final product, and big, boxy clearings for well pads kitted out with machinery like an elongated caterpillar with wells for legs that also connects to multiple pipelines snaking through the boreal forest. So do row after row of clear-cut lines for the seismic testingthat reveals where the tar sand deposits lie, cuts that take a long time to heal given the slow growth rate of trees this far north.
But the technology for melting bitumen out of the ground is still developing. The first commercial steam-assisted gravity drainage facility only started up in 2001. Already experiments have started with potential advances such as microwaving the ground to loosen the oil, as attempted in tests by U.S. defense contractor Harris Corp. this year. "This industry is so young," says Scott Wenger, manager of government relations at original oil sands company Suncor, which hosted Harris's electromagnetic sand-heating effort. "Who knows what will happen with new technology?"
This future is melting bitumen where it lies at least 200 meters below the surface rather than mining tar sands. In 2011 more than 11,000 barrels of bitumen were melted out of the frozen ground not far from here each day, where the airstrip sees more human traffic than the town as workers commute in and out by plane from as far away as Newfoundland.
"Most of what's going on happens 375 meters below the surface," says Greg Fagnan, director of operations and production at Cenovus's Christina Lake oil sands production facility, during a recent tour. Cenovus extracts bitumen by employing a technique called steam-assisted gravity drainage, which can be thought of as the opposite of mining. Instead of melting the bitumen out of sand in an industrial plant after clawing the tar sands out of the ground, Cenovus melts it out in place with steam. That means Christina Lake is, in a sense, a giant water-processing facility "that happens to produce oil," Fagnan says. "It's not a complicated business, it's just complex."
Conklin is one of the frontier towns of a new tar sands boom, given that 80 percent of the at least 170 billion barrels in the Canadian province's tar sands are only accessible this way rather than by mining. In 2011, for the first time, oil production from such in situ operations surpassed that of mining for oil in the tar sands—a trend that is only likely to increase as more oil sands production comes online in Canada. Already, plumes of steam billow from the boreal forest across northeastern Alberta where a host of developers work—from Nexen, recently acquired by the China National Offshore Oil Corp. (CNOOC), to oil majors such as Royal Dutch Shell—like mushrooms springing up from the ground after rain.
But this recovery of bitumen in place will have to continue to improve its efficiency and cost if it is going to compete with other fast-growing oil recovery technologies, such as fracturing rock with high-pressure water, or fracking, to release trapped oil. As it stands, Alberta is estimated to hold more than 400 billion barrels of such "tight oil," which is already being produced in places like North Dakota's Bakken Shale by the number-one customer for Canada's tar sands oil: the U.S.
Melting tar
Steam dominates the Christina Lake facility, where mushroom clouds rise into the wintry blue sky, pierced only by the orange glow of a flare near the bitumen processing plant. Nine industrial boilers, powered by natural gas, heat treated brine from nearby aquifers to 350-degree-Celsius to inject it as steam into what can be likened to three giant, underground sandboxes—vast rectangular blocks of oil-bearing sand. Each sandbox is pierced by pairs of pipes, one perforated to release pressurized steam along its 800-meter length and melt oil from the tar sands, another to suck melted bitumen, bits of sand, water and natural gas with electric pumps back up to the surface. The pipes are strung with sensors, gauges and fiber optics, or "jewelry" in the industry jargon, that allow well operators back at the surface to continually monitor conditions under the earth, such as the steam pressure that starts out at a crushing 120-kilogram-force per square centimeter. Christina Lake pumps out a barrel of oil for every 2.3 barrels of injected steam.
Cenovus claims to use just 0.07 barrel of freshwater to produce each barrel of oil at Christina Lake, thanks to the recycling and almost exclusive use of brackish waters. According to the Royal Society of Canada's 2010 report on such tar sandsdevelopment, a typical facility uses 0.6 barrel of freshwater and 0.4 barrel of brine per barrel of oil. "Conventional oil from the Saudis uses more water than the [steam-assisted gravity drainage] process," says geologist John Zhou, executive director of environmental management at Alberta Innovates, a government-funded technology innovation effort.
Drilling the wells themselves presents the first challenge. During installation, the pairs of wells in each sandbox site are drilled simultaneously, rigorously maintaining a spacing of only five meters apart, with a rig specially modified for this kind of oil sands exploitation. At each site, or well pad, roughly eight such wells are drilled, lining up side by side—on one side eight or more steam injectors and on the other a matched number of oil-producing wells.
After a few years of production, such as at Cenovus's older Foster Creek facility started up in 2001, additional wells are drilled to recover oil from the wedges of tar sand between each steam-created balloon-shaped melt zone. Such wedge wells have enabled Cenovus to add 20,000 barrels of production per day to Foster Creek without requiring any additional steam—and a given well is expected to produce for roughly 20 years, though no well is yet that old.
"These fields are really like laboratories," says Cenovus spokesman Brett Harris, and operators are making continual adjustments and suggesting improvements, such as pumps that can withstand the high temperatures underground but also run on electricity rather than natural gas. Operators are also constantly adjusting the flow of steam, closing off sections of the perforated pipe to shut off heat to certain sections and ensure even melting throughout. Such in situ production has always been experimental, starting with the first attempt back in 1926: The pipes available at the time could not withstand the steam's heat and pressure, resulting in a steam explosion that destroyed the start-up plant and injuries to entrepreneur Jacob Owen Absher, among others.
That is not a problem that has entirely disappeared. Oil company Devon Canada actually used too much pressure on its subterranean sandbox and caused a blowoutthat shot scalding steam and bitumen into the sky in the summer of 2010 near here, and Total Energy caused a similar explosion of steam, oil and rock north of Fort McMurray in 2006. The steam pipelines themselves have also blown as a result of cooled water trapped inside. Such a "water hammer" has tossed pipelines as much as a kilometer, Cenovus's Fagnan says, leaving them sticking out of the ground like toothpicks embedded more than three meters deep. The steam "packs a pretty big punch," he says.
Better engineering
The engineering challenges faced by in situ projects range from a lack of a sufficient seal above the oil sands deposit—allowing steam to escape without melting oil or, even worse, the oil itself to flow away—to underlying aquifers, or "thief zones," that can quench barrel after barrel of steam heat. And that's after the expensive well pairs have been put in place. At Christina Lake the reservoir sits below a layer not of rock, but of natural gas—and that means Cenovus operators must continually inject air to ensure that the gas pressure matches or exceeds the pressure of the pumped in steam, so the steam doesn't escape without doing its melting work.
The ultimate engineering challenge of the tar sands, however, may be coping with greenhouse gases. As a result of increasing in situ production, greenhouse gas emissions from Alberta's tar sands rose by 1.7 percent last year, and are up 16 percent since 2009, according to the Canadian Association of Petroleum Producers. The newly dominant in situ technology produces oil at a cost of 2.5 times more CO2 emitted to the atmosphere than the more brute-force, conventional mining. Whereas this may be equivalent to what's emitted when using steam to flood out heavy oils in California or Nigeria, neither of those sources of greenhouse gases is growing as fast as the tar sands.
In an effort to get ahead of this climate challenge, Alberta has invested more than $1.5 billion in developing CO2 capture and storage (CCS) technology. But it has yet to be applied to an in situ operation; the one current project in the oil sands involves capturing CO2 emissions from mini-refineries at Shell's operation near Fort Saskatchewan, a project dubbed Quest. That project is slated to open in 2015 and there are, as yet, no plans for CO2 capture and storage at any in situ facilities.
The Pembina Institute, a Canadian environmental group, estimates that it would cost more than $200 per metric ton of CO2 to add CCS to tar sands production facilities like Christina Lake. Alberta's current price on CO2 is $15 per metric ton. "The trick is to find a way to make capture and storage economic," Harris says, noting that Cenovus has done exactly that at its Weyburn enhanced oil recovery project in Saskatchewan. The company uses CO2 captured at a gasification plant across the border in North Dakota to scour more oil out of the ground—and the extra oil produced helps pay for the CO2 capture process, although the oil also ends up contributing to the growing greenhouse gas burden when burned.
Reducing energy use, then, may prove a better route. By using solvents, such as the hydrocarbon butane, in situ producers can boost the bitumen recovery ability of the steam itself. Cenovus has been testing the process at Christina Lake since 2004 and will implement it at the company's newly approved Narrows Lake project, slated to start producing oil in 2017. Using such solvents "can drop the energy consumption by as much as 50 percent," says chemical engineer Murray Gray, scientific director of the Center for Oil Sands Innovation at the University of Alberta.
Such new technology means more cost to develop and produce what is already among the most costly forms of oil, Gray notes. At present, Cenovus spokesman Harris says that the company needs to earn at least $35 per barrel of oil. With West Texas Intermediate grade oil at $85, that is not a problem, except for the atmospheric warming. And it's not as if in situ development has no impact on the land: there's the industrial plant for producing steam and processing bitumen, tank farms to hold the final product, and big, boxy clearings for well pads kitted out with machinery like an elongated caterpillar with wells for legs that also connects to multiple pipelines snaking through the boreal forest. So do row after row of clear-cut lines for the seismic testingthat reveals where the tar sand deposits lie, cuts that take a long time to heal given the slow growth rate of trees this far north.
But the technology for melting bitumen out of the ground is still developing. The first commercial steam-assisted gravity drainage facility only started up in 2001. Already experiments have started with potential advances such as microwaving the ground to loosen the oil, as attempted in tests by U.S. defense contractor Harris Corp. this year. "This industry is so young," says Scott Wenger, manager of government relations at original oil sands company Suncor, which hosted Harris's electromagnetic sand-heating effort. "Who knows what will happen with new technology?"
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