Introduction
Gasification will make Alberta’s oilsands industry more competitive with global oil producers and help it produce 4 million b/d of high-quality synthetic crude oil (SCO) to boost the world’s crude supply. Crude oil originating from a safe, politically stable source such as Canada is the hallmark of energy security and will go along way to meet North American oil demand.
The bitumen mining and upgrading industry’s energy needs are steadily increasing with more natural gas-fired facilities generating steam for steam-assisted gravity drainage (SAGD) and providing process heat for bitumen recovery, extraction and upgrading. Syngas must replace expensive natural gas to provide fuel to operate steam generators for SAGD and also provide hydrogen for hydroprocessing and hydrocracking in the upgrading process.
The Canadian natural gas production profile has flattened and is expected to remain around 16.80 bcfd. Natural gas demand grew to a total in Canada and the US to 69.92 Bcfd. The most significant growth in Canada’s natural gas demand is from the oilsands operations that reached 1.01 bcfd.
About 80% of oilsands are buried too deep for surface mining and bitumen must be recovered by in situ techniques. Injecting steam to heat the oilsand lowers the bitumen’s viscosity and hot bitumen flows to the surface production wells. SAGD is an in-situ process that uses horizontal drilling to produce bitumen. In situ production rivals surface mining and may replace mining as the main bitumen production source.
It takes 1000 cubic feet of natural gas to produce one barrel of bitumen. Current natural gas demand for upgrader hydrogen is 400 cf/b and future hydrogen additions for upgrading into higher-quality SCO may reach another 250 cf/b. If no coke burning takes place, another 80 cf/b for upgrader fuel has to be added. A future barrel of in situ-produced high-quality SCO may require more than 1,700 cf of natural gas.
Conference attendees will learn about oilsands and heavy-oil upgrading projects ranging from the processing of refinery residual oil streams to upgrading wellhead bitumen and the heaviest mined oilsands feedstocks. They will be the forefront of gasification technology with plant designs that are integrated into a refinery and produce both electricity and other byproducts. Find out more about planning, engineering and construction of gasification units in the oilsands upgrader projects as well as CO2 recovery in the process and the latest sequestration concepts.
Asphaltenes will be separated at projects during the upgrading of bitumen to syncrude and will be converted into syngas. Gasification of asphaltenes uses materials that would otherwise be a low-value product and reduces the facility's reliance on external energy sources. Gasification provides projects with a hydrogen source. Oilsands projects consume 900 MMscfd of hydrogen that can be derived from asphaltenes. Converting asphaltenes to syngas to produce hydrogen will save an enormous amount of natural gas and reduce operating costs significantly. As little as seven barrels of asphaltenes can yield 100,000 scf of hydrogen.
Progress will be updated in the development of North West's heavy-oil upgrader project located 45 km northeast of Edmonton, Alberta as well as the integration and operation of the Lurgi multi-purpose gasification (MPG) process block to produce hydrogen from refinery bottoms. MPG is a process for the partial oxidation of hydrocarbons that significantly increases feedstock flexibility for the production of syngas and hydrogen. The upgrader will produce light, low-sulfur products and diluent with a total capacity of 231,000 b/d of blended feedstock (150,000 b/d of crude bitumen) over three phases. Hydrocracker bottoms will be gasified in the Lurgi MPG unit to produce the hydrogen for use in the hydrotreating and hydrocracking units.
Manufacturing high-quality low-sulfur products requires significant amounts of hydrogen, typically sourced from natural gas. Converting the hydrocracker's heavy residue bottoms to hydrogen for use in the process avoids the use of considerable amounts of high-value, high-cost natural gas.
Developers need to know how Alberta oilsands and upgrader projects can be planned to integrate gasification and congeneration. Syngas can fuel process and cogeneration plants as well as provide a basis for CO2 capture and storage. Cogen and gasification systems have an overall energy efficiency of between 65 and 85%, and offer more than a 60% decrease in CO2 emissions versus generation from coal-fired power plants, and more than 20% versus gas-fired combined-cycle gas turbines.
Alberta's first coal gasification project will provide syngas to the bitumen upgrader projects. This pioneering project represents the first real effort to develop the province's extensive coal reserves for gasification and meet the fuel and hydrogen needs in an environmentally responsible manner. The project developer will partner with a Canadian power producer to include an IGCC configuration that will use the country's low-rank coals.
EPCOR is pursuing the commercialization of coal gasification, committing $11 million to the Canadian Clean Power Coalition's FEED of a utility-scale IGCC plant. The project focuses on: adapting the technology to Alberta coal; removing emissions of concern; commercial-scale geological storage of CO2; and cost competitiveness and cost certainty. IGCC also allows for a relatively pure CO2 stream for enhanced oil recovery.
These developments and more will be discussed at the conference, August 16, 2007 in Calgary. |
