Oil from Sand

In these hard economic times, people working in troubled businesses may well envy the situation of Alberta’s oil sands industry. The Canadian Association of Petroleum Producers (CAPP, Calgary, Alberta; www.capp.ca) predicts that the production of synthetic crude from oil sands will reach 3.3-million bbl/d by 2020, up from 1.2-million bbl/d in 2007. Much of this oil will be sent to the U.S. via an expanding network of pipelines (CE, May 2008, p. 22).

As it happens, though, the industry has been impacted by the current business recession causing a number of companies to delay their expansion plans. For example, Suncor Energy (Calgary; www.suncor.com) announced a $20.6 billion* expansion program a year ago, with the goal of expanding production from 350,000 bbl/d to 550,000 bbl/d by 2012. More recently, the completion date has been pushed back to 2013 and the company has scaled back its capital spending plans for 2009 by more than one-third. Similarly, Fort Hills Energy L.P., a new venture, has deferred a final investment decision on mining operations and delayed indefinitely a decision to build an upgrader (delayed coker). Petro-Canada (Calgary; www.petro-canada.ca), the majority partner in Fort Hills, has reduced its capital and exploration expenditures to about $4 billion this year, down from about $6 billion in 2008. Petro-Canada’s investment in oil sands in 2009 is expected to be about $985 million, down from about $1.4 billion in 2008.

Alberta’s recoverable reserves of oil sands total about 175-billion bbl, says Greg Stringham, CAPP’s vice-president for oil sands and markets. Currently, about half the production is done by surface-mining the sand and its associated bitumen, then separating and upgrading the bitumen to obtain a synthetic crude (syncrude) for refining. However, only about 20% of the reserves are amenable to surface mining, so the trend is toward increased use of in situ processing to exploit deposits 200 ft or more below the surface.
Process technology
The main drivers for technology innovations in oil sands production are a desire to reduce costs and environmental impacts. Operating costs vary widely, but are currently in the range of US$30–35/bbl, says Stringham. Syncrude Canada Ltd. (Fort McMurray, Alta; www.syncrude.ca) reported operating costs, including purchased energy costs, of $24.64/bbl for 2007, down from $26.46/bbl in 2006.

In a surface-mining operation, oil sand is scooped up by huge shovels, trucked to a crusher, then slurried with warm water and piped to an extraction plant. There, hot water (40–50°C) is added, air and process aids are injected into the stream, and the mixture is fed to a conical primary separation vessel. Sand settles to the bottom of the vessel and the overflow is a froth that contains about 60% bitumen, 30% water and 10% clay.

Naphtha is typically mixed with the froth to lower the viscosity of the bitumen, making it easier to separate it from the water and clay by centrifuging or settling. Finally, the bitumen and naphtha are separated by distillation. The naphtha is recycled and the bitumen, whose specific gravity is about 10 API, is upgraded by delayed- or fluid-coking to obtain a synthetic crude of 25–30 API for refining.
The downside of these operations is that they use large volumes of water and have created huge tailings ponds that contain toxic residues. Air pollution is also a concern, and emissions of carbon dioxide are a major issue (see sidebar). In their defense, spokespersons for industry point out that they recycle at least 90% of the water they use, with zero discharge, and the net water use averages roughly 4 barrels per barrel of produced oil.

The popular process for in situ mining is steam-assisted gravity drainage (SAGD). A horizontal well is drilled into the oil formation, and a second, producer well is drilled parallel to it at a lower level. Steam is injected into the upper well to liberate the bitumen, which is pumped out from the producer well.

Benefits of in situ mining are that the produced bitumen is “clean”, there are no tailings, and water use is much lower than those of operations based on surface mining. Petro-Canada says its net water use for SAGD (including 90% water recycling) is about 1/3 barrel of water per barrel of product.

On the other hand, energy use is high and there are air emissions from the steam boilers. Several new technologies are being developed and implemented to alleviate these problems and to cut costs (see below).

Companies whose operations start with mining are striving to improve efficiency throughout the process train. At the beginning of the train, Suncor has been using a mobile crusher at the mine face for more than a year. Built to Suncor’s specifications by MMD (Summercotes, England), the tracked unit can process 5,000 metric tons per hour (m.t./h) and is linked to a mobile slurry unit, thus reducing the cost of truck haulage and reducing air emissions. Suncor expects to have two more mobile crushers operating within three years.

Syncrude has designed a compact slurrying unit for use with a mobile crusher at the mine face and field-tested a 4,000-m.t./h prototype, which is about half the size of a commercial unit. The company is now doing engineering design for a commercial system, says Alan Fair, manager of research and development. The equipment will be moved every few weeks by commercially available crawler transports. Fair notes that haulage trucks cost about $5 million each, “so it’s a costly way to move ore.”
An improved froth treatment process, for separating bitumen from the froth after primary separation, has been developed by Shell Canada Ltd. (Calgary; www.shell.com). Naphtha is normally mixed with the froth to lower the viscosity of the bitumen and ease the separation, as noted earlier. Shell, in contrast, has for several years used paraffinic technology developed in cooperation with Natural Resources Canada’s CanmetEnergy (Devon, Alta.; www.nrcan.gc.ca).

Shell has now developed an improved paraffinic process, called Shell Enhance, and plans to start up a commercial plant at its Muskeg River Mine in 2010–2011. The new process operates at above 60°C, versus 25–35°C for the earlier process. The advantages of paraffin over naphtha, according to Shell, are that the bitumen product has a lower solids and water content and there is partial deasphalting of the bitumen. Shell Enhance is an improvement over the earlier process in that it improves energy efficiency by 10%, uses 10% less water and requires less space.
Coking
In contrast with the situation in a conventional petroleum refinery, coking is an important unit operation in oil sands processing. “Most petroleum refiners use the coker as a garbage can to process the bottoms and heavy oil, but in our case most of our feed goes through a coker,” says Alan Fair, manager of research and development for Syncrude. The company has three fluidized-bed cokers — two older ones with nameplate capacities of 107,000 bbl/d and a 95,000-bbl/d unit that started up in 2006. “These are the largest fluid cokers in the world,” says Fair.

Syncrude has installed baffles in the reactor product-recovery section of one of the cokers to improve product fractionation. The company plans to make similar modifications to the other cokers during future scheduled shutdowns. The cost is about $1 million for each project, but Syncrude says the potential savings could reach $9 million/yr through longer run times and improved product quality. The baffle was developed by the company’s R&D department, with help from ExxonMobil (Fairfax, Va.; www.exxonmobil.com), licensor of the fluid coking technology.
Syncrude is also investing $1.6 billion to retrofit lime spray dryers on the two older cokers for sulfur emissions control. Scheduled for startup in 2010 or 2011, the project is expected to reduce emissions from the two units by about 60%, reducing the total sulfur emissions at the site to less than 100 m.t./d.

The newer coker uses an aqueous ammonia scrubbing process from Marsulex Inc. (Toronto; www.marsulex.com). The NH3 reacts with SO2 to form an ammonium-sulfite slurry, then air is bubbled through the slurry to obtain ammonium sulfate, which is sold to the fertilizer industry.

Syncrude chose this process because ammonia is generated as a byproduct in the hydrotreating plant, says Paul Ibbotson, a process engineer. However, trace compounds in the gas caused an odor, so the company has been buying NH3 until it finds a way to deal with the offending compounds.

Suncor will install three trains of paired delayed cokers for its planned 200,000-bbl/d expansion. The project, dubbed Voyageur, will process bitumen from a combination of surface- and in situ-mined sources (Figure 2). The company has been using some SAGD for about five years, says a company spokesman, “but in the next 5–7 years we expect it to account for about 50% of our bitumen recovery.”

Tailings treatment
Surface-mining operations produce tailings that are a mixture of water, clay, sand, residual bitumen and naphthenic acids. The problem is that the clay stays suspended, settling to a maximum of only 30–40% solids content after 3–5 yr, says Randy Mikula, team leader for the extraction and tailings group with Canmet.
Indeed, Suncor is only now reclaiming its first tailings pond after decades of operation. Suncor pioneered the use of consolidated tailings technology, developed in association with Canmet, in which tailings are consolidated by chemical treatment. In Suncor’s case, gypsum (from SO2 scrubbing) is added to the tailings to accelerate the release of water. Suncor’s Pond 1 is now being infilled with sand, after which the company will contour the surface and plant vegetation.

A process in which CO2 is injected into the tailings pipeline is being commercialized by Canadian Natural Resources Ltd. (CNRL, Calgary; www.cnrl.com). CNRL developed the process in collaboration with Canmet. The injected CO2 forms carbonic acid, which changes the pH and coagulates the clay, thereby increasing the settling rate of the tailings, says Theo Paradis, lead operations engineer. CNRL is using the process to treat the tailings from its new 110,000-bbl/d oil sands plant, now starting up. Paradis expects it will permit settlement of the tailings within weeks, rather than years.

An improved process will be used in the project’s second stage, when the plant will increase oil production to 232,000 bbl/d. The tailings volume will be reduced by thickeners and cyclones. Warm water will be recycled to the process from the thickener, and waste heat from the coker will be used to heat the process water, eliminating the use of natural gas. About 26 m.t./h of CO2 will be obtained from the onsite H2 plant. The deposited tailings may be trafficable “almost immediately,” says Paradis.

In another process, developed by Syncrude in collaboration with Canmet, organic polymers are added to tailings, which are then centrifuged to separate the clay from the water. Syncrude has tested the process at a scale of 20 m.t./h and increased the solids content of the tailings from 17–20% to 55–60%. The separated water was returned to the bitumen-extraction process.

As an alternative to consolidating tailings, Syncrude has piloted a water capping method, in which lakes have been built in former mines, with soft tailings forming sedimentary bottoms. Syncrude says its research indicates that the lakes will, over time, support plant and wildlife.
In situ processes
The conventional in situ mining process is SAGD, as noted earlier, but this method uses large volumes of natural gas to raise steam, and there are air emissions from the steam boilers. A number of companies are working on new technologies that reduce or avoid these problems.

Petrobank Energy and Resources Ltd. (Calgary; www.petrobank.com) is piloting a process called THAI (Toe-to-Heel Air Injection). A horizontal producer well with a slotted liner is drilled at the base of the oil sands formation, which may be 20–30 m thick, then a vertical injector well is drilled to the end (toe) of the producer well. Steam is injected for 2–3 months to raise the reservoir temperature to about 100°C. Finally, air is injected at 450–550 psi, initiating a combustion front that moves along the axis of the producer well, causing oil to flow into the well.

“The oil just rises to the surface by gas lift, without pumping,” says Barry Noble, a management adviser with Petrobank. Asphaltenes remain in the sand to provide fuel, he says, so the produced bitumen has an API gravity “in the middle teens,” versus eight for raw bitumen. Compared with SAGD, there are substantial savings in capital costs and water and energy, he adds, because steam is used only at the beginning of the cycle. Petrobank has piloted the process and plans to build a 10,000-bbl/d demonstration plant.

Shell is developing an In situ Upgrading Process (IUP) in which the oil is heated by electrical resistance heaters that are inserted in wells. The heat upgrades the bitumen into a lighter crude and gas that can be recovered, leaving coke in the ground. Shell has been field-testing IUP for several years, using 18 heaters and three producer wells. So far, more than 100,000 bbl of light oil has been produced at the site, but Shell says further work is necessary before the process can be commercialized.

Oil Sands and the Environment
Toward mid-year, Alberta Energy (Edmonton, Alta.; www.gov.ab.ca) the provincial government’s energy department, will award three to five contracts for pilot projects for carbon capture and storage (CCS). Total funding is $2 billion (Canadian) and the goal is to capture 5 m.t./yr of CO2 and develop a pipeline network to transport the gas for use in enhanced oil recovery (EOR) or injection deep underground.
The CO2 initiative is welcomed by Stephen Kaufman, chairman of ICO2N (Calgary), a group of some 20 industrial companies that studies CCS. In a recent report ICO2N outlined a scheme for a CCS system to reduce CO2 emissions by 20 million m.t./yr, at an estimated cost of more than $100/ton.

Last year was the first full year of an Alberta regulation that requires companies emitting more than 100,000 m.t./yr of CO2 to reduce their emissions by 12%. Those that don’t meet their targets may buy offsets or pay $15 for each ton over the limit. The Alberta government was the first in North America to issue such a regulation.
Environmentalists complain that the regulation is based on intensity (for example, per barrel or kWh), rather than placing a cap on plant emissions. “The oil sands industry produces about 4% of Canada’s greenhouse gas emissions and this is set to triple to 12% by 2020,” says Simon Dyer, director for oil sands with the Pembina Institute (Calgary; www.pembina.org), a sustainable energy think tank. He adds that the regulation does not encourage polluters to use CCS. “Paying $15 a ton, when CCS may cost around $100/ton, is a perverse incentive not to use CCS,” he says.
Dyer notes that current oil sands operations cover about 600 km2 of land in northeastern Alberta and have the highest environmental impact of any oil production in the world. As for land reclamation, he says that so far virtually no land has been certified as reclaimed, nor any tailings ponds, which comprise “about 130 km2 of toxic liquids.”
Article Source : http://www.che.com