Technology Profile: Oilsands producers are ramping up their pursuit of water-free processing
Oilsands companies are spending billions of dollars in research and development to noticeably decrease their carbon emissions and dispel the “dirty oil” label affixed to bitumen-based crude oil producers. Much of that research focuses on improving the use of steam in SAGD (steam-assisted gravity drainage) and related steam-based processing. Not only is there a great deal of research taking place in that area, but various pilot projects all already underway.
The industry is also investing considerable resources into technology that eliminates the use of water, including the replacement of water with solvent and a less-conventional potential technology involving the use of electromagnetic heating. Imperial Oil Ltd. has been at the forefront of oilsands processing and has played a chief role in the development of technology that is now widely used in sector. The company invented and holds patents on SAGD and cyclic steam stimulation (CSS), two key processes used in heavy oil recovery production today.
SAGD technology consists of a pair of wells drilled horizontally about four to six metres underneath each other in a bitumen field. From a nearby boiler plant, steam is generated and piped to the wells. It flows into the top well, called the injection well, where the steam heats the surrounding bitumen, decreases its viscosity and allowing it to flow downward into the production well (gravity drainage). As the steam condenses into water coming into contact with the cold bitumen, the bitumen-water mixture is pumped to the surface where it’s separated. The steam injection and oil production happen continuously and simultaneously. In CSS, high-pressure steam is injected into a single well for several weeks at a time.
As in SAGD, the steam heats and softens the bitumen, while the water helps to dilute and separate the bitumen from the sand. The softened bitumen and water is then pumped to the surface. One of Imperial’s most successful water reduction projects is located at the company’s Cold Lake, Alta., field where it piloted a steamflooding technology that promises to improve resource recovery and reduce greenhouse gas emissions by up to 30 per cent.
The Cold Lake in-situ operation is one of the largest thermal in-situ heavy oil operations in the world, recovering bitumen from more than 400 metres below the surface, notes Pius Rolheiser with Imperial Oil Public and Government Affairs. “It’s a massive recycling operation where we inject more than 600,000 barrels of steam into the oilsands formation daily to thin the heavy bitumen enabling it to flow to the surface through well bores,” says Rolheiser. “More than 95 per cent of the water used for the steam is recycled and re-injected. We started up commercial operation at that site in 1985. Since then, we’ve reduced the amount of fresh water used to produce each barrel of bitumen by 80 per cent.” Rolheiser says the re-use of water in CSS is just one technique that Imperial is using to reduce the amount of water in its bitumen processing. “The two most critical factors determining the amount of reduction in water use are not only the treatment technologies for the recycled water, but also the methods to purify the brackish or saline water from deep aquifers at the well bore sites,” he says. “It’s two to three times the salinity of ocean 1ater and is not potable.”
The brackish water is considered “make-up” water — that is, water added to make up for the water which remains in the reservoir during the recycling process. “At Cold Lake, we’ve developed a number of technologies to purify and soften the brackish water to make it suitable to run through our steam boilers. So our three major plants at Cold Lake no longer require any fresh water to generate steam and use only the recycled water (a smaller, older plant called Leming still requires some fresh water for steam injection.) That’s because of our own advances in treatment and recycling by our Calgary research centre.”
The move away from water The oilsands sector as a whole has, and is, exerting massive effort and resources toward reducing the amount of fresh water consumed for processing by using SAGD, steam flooding and cyclic steam stimulation, a variation of steam based processing. However, those methods have a downside: the amount of energy it takes to generate the steam by natural gas-fired boilers. According to Alberta Innovates — Energy and Environment Solutions, greenhouse gas emissions for SAGD projects produce about 0.06 tonnes of carbon dioxide equivalent per barrel of bitumen produced. This is why operators such as Imperial are searching for alternative technologies to increase water recycle rates while minimizing the amount of energy consumed in the water treatment process.
“The solvent technology that we call LASER, or liquid addition to steam to enhance recovery, adds a small of amount of light hydrocarbon solvent or diluent to the steam that’s injected into the well,” Rolheiser says. “By adding the diluent, more bitumen can be recovered from mature wells for the same amount of steam injected.” In 2009, Imperial completed solvent and steam injection at 10 well pads, and bitumen production has since started. The technology was patented in 2010 and has been applied commercially for a number of new pads at Cold Lake. “This is still in the early stages, but production is meeting expectations,” says Rolheiser. In the cyclic solvent process (CSP), meanwhile, steam is replaced by the injection of solvent to reduce the viscosity of the bitumen. Rolheiser says the use of solvent could be applied to both SAGD and steam-flooding methods and has several variations. “It’s been proven successful in the research lab and on very small pilot scale,” he says.
“Now we’ve started a $100-million pilot project this summer consisting of three wells at Cold Lake that we’ll operate for a couple of years to evaluate the effectiveness of the technology — specifically, to evaluate factors like what percentage of solvent can be recycled in comparison to how much remains in the reservoir.” If successful, CSP would virtually eliminate water because operators such as Imperial would be injecting only hydrocarbon solvent in liquid form. The only change required from steam injection would be some modification for the aboveground storage tanks, says Rolheiser. Otherwise, the basic technology could be applied to wells currently using steam technique, of which there are about 4,000 for Imperial. “CSP would eliminate the use of water completely from the equation and results in two major benefits,” says Rolheiser. “First of all, we will not require any water; and secondly, since we don’t have to heat any water to generate steam, the greenhouse gas reduction potential is enormous. We estimate that the direct GHG emissions could be reduced by 95 per cent.”
Suncor Energy Inc. is similarly investing in the development of viable processing alternatives for use in the oilsands. The company began operating a pilot plant in spring 2014 at its Dover lease at the Athabasca oilsands area about 45 kilometres northeast of Fort McMurray, to field test Bitumen Extraction Solvent Technology (BEST), a proprietary technology developed by N-Solv Corp., which uses propane or butane in a SAGD-type setting. The solvents in BEST are able to dilute underground bitumen at temperatures below 80 C, greatly reducing the amount of energy (by up to 85 per cent) needed. The solvent is injected as a vapour, which condenses underground and dissolves the bitumen. The valuable components of the bitumen are extracted, while the coke-forming asphaltenes are safely sequestered in the reservoir. BEST incorporates the proven horizontal well technology developed for SAGD.
Yet because, a water treatment plant and boilers are not needed, capital costs and overall operating costs are substantially lower. In addition, the process produces a lighter, more valuable oil. In October 2014, N-Solv announced the pilot plant reached a milestone of 25,000 barrels of oil production since its start-up.
N-Solv is a Calgary-based company founded in 2003 and owned by Hatch Ltd., Enbridge Inc. and Nenniger Inc. The pilot is the result of collaboration between N-Solv Corp. and Suncor, with support from Sustainable Development Technology Canada and Alberta’s Climate Change and Emissions Management Corp. N-Solv CEO Jon Nenniger points out that reaching 25,000 barrels of production not only demonstrates that the technology works, but that there were no significant interruptions along the way. He says N-Solv has been fielding requests for scaled-up projects, which are being reviewed on a reservoir by reservoir basis.
The BEST technique is not perfect, however. The vapour formed by heating the solvent has a low heat of vapourization, and therefore requires large volumes of solvent to be condensed during condensation to effectively raise the temperature of the bitumen. Dover is also the site for the testing of another innovative extraction technique known as Effective Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH), a joint project between Suncor, Nexen Inc., Devon Canada Corp. and the developer of the technology, Harris Corp. of Melbourne, Fl. The $33-million program is supported by the Climate Change and Emissions Management Corp. The ESEIEH™ technology utilizes Harris’s proven radio frequency system and antenna technologies, called HeatWave, to heat reservoir fluids. It operates much like a SAGD installation by using an injection well and a production well underneath.
The Heat Wave system consists of a generator and transmitter located on the surface along with a dipole antenna that is lowered into the injection well through the intermediate casing. The antennas are available in a variety of configurations, depending on the pay zone depth. The antenna transmits the low-frequency alternating electrical current (about one kHz to one GHz), which causes molecules in the surrounding pay zone to vibrate, inducing molecular friction, which generates heat (about 40 to 70 C). Once this preheating has taken place, a solvent is injected into the reservoir to dilute the bitumen, which flows downward into the production well and is transported to the surface — the same as in a SAGD process.
The Harris technology was first evaluated and tested in Florida. It then underwent a successful initial proof-of-concept test in 2012 at Suncor’s Steepbank mine facility north of Fort McMurray with the approval of the Energy Resources Conservation Board (now known as Alberta Energy Regulator). That test took place at a shallow mine face where the antenna was inserted horizontally into the face. The test confirmed the ability to successfully generate and distribute electromagnetic heat in an oilsands formation. It also validated the analytical tools and methods used to predict the performance of the process. This led to the decision by the consortium to move to the next phase — an in situ field pilot test using a 200-metre horizontal well. That pilot is under construction, but a start-up date hasn’t been announced.
While preliminary results are encouraging, consortium members emphasize additional work remains before the commercial viability of the process can be determined. Devon technology development manager Bryan Helfenbaum says the next field pilot will be a scaled-up version of the current pilot, eventually leading up to commercial deployment. “The scale of this pilot is quite large,” Helfenbaum says, “A project on this scale can take a year and a half to design and build, plus a year or more of production before you can confirm you have a viable technology. Then, you can multiply development time for scaling up to commercial production.” ESEIEH, BEST and CSP are only a sample of the many extraction technologies currently being explored. Many are being developed through the auspices of Canada’s Oil Sands Innovation Alliance (COSIA).
The alliance formed in 2012 to speed up advances in environmentally improved extraction technologies through collaboration and the exchange of information in the areas of tailings, water, land and greenhouse gas emissions. Current COSIA members include BP Canada Energy Group ULC, Canadian Natural Resources Ltd., Cenovus Energy Inc., ConocoPhillips Canada Resources Corp., Devon, Imperial, Nexen Canada, Shell Canada Energy, Statoil Canada Ltd., Suncor, Syncrude Canada Ltd., Teck Resources Ltd and Total E & P Canada Ltd.
A major step to meet the objectives of COSIA members took place last summer with the announcement that Suncor and five industry partners (Canadian Natural, Devon, Husky, Nexen and Shell) had committed an estimated $165 million toward the construction of a dedicated Water Technology Development Centre (WTDC). The WTDC will focus on developing technologies that will be capable of minimizing fresh water use and maximizing reliability for SAGD production. The test centre is unique in that it will be physically joined to Suncor’s Firebag SAGD facility, located about 120 kilometres north of Fort McMurray, As a dedicated test facility, the centre is expected to overcome the barriers that are common to field testing at commercial production facilities, which are not typically designed to accommodate simultaneous testing of water treatment technologies. It should reduce the eight years it now typically takes for a technology to go through the field test process to commercial application.
Suncor will own, construct and operate the WTDC while collaborating with the other partners on design, construction and operations — including specific tests.
Ernest Granson is a Calgary-based writer and editor, and a contributor to PROCESSWest.