By R. Bruce Striegler

“I’m an engineer, and engineers build things”, says Alberta-born Neil Camarta, founder and Director of Enlighten Innovations Inc. One of the things Mr. Camarta has ‘built’ and which is currently occupying much of his time, is the development and commercialization of a new bitumen sulphur removal and upgrading technology called DSU, which can be used in upgrading Alberta bitumen. The proprietary technology is undergoing testing at a ten barrel per day, $30 million pilot plant in Fort Saskatchewan, Alberta and has been operational since the end of 2015. Camarta says, “Our pilot plant has confirmed our technology and we are now building a demonstration facility to produce 2500 barrels of finished low sulphur marine fuel from heavy oil stocks. We expect our CLEANSEAS plant to be ready in 2020.”

The CLEANSEAS project is a commercial scale of the technology and signifies a critical step towards full commercial rollout. Mr. Camarta says that the DSU technology reduces GHG emissions on a lifecycle basis by up to 40 per cent compared to alternative pathways for production of marine fuel, a market he is particularly targeting. New fuel standards for the international shipping industry with tighter pollution rules imposed by the International Maritime Organization, dubbed IMO 2020, are set to take effect Jan. 1, 2020. The new standards will see the sulphur content limit of “bunker” fuel on ships dropping from 3.5 per cent to just 0.5 per cent. The switch is expected to hit prices for heavy oil containing high levels of sulphur — exactly the kind of the raw bitumen that makes up about half of Canada’s 4.4 million barrels per day of crude oil production.

A lifetime of work in the petroleum industry yields new innovations

Camarta, with a degree in Chemical Engineering, clearly understands the need and the potential impact of his new development. His long history in the energy industry has given him a unique view of the Alberta resource and its opportunity. Camarta joined Shell Canada in 1975, holding senior positions in Canada and abroad. Most notably, he led the successful development, construction and start-up of Shell’s $6 billion Athabasca Oil Sands Project. Camarta’s resume includes time as Executive Vice-President, Natural Gas for Suncor Energy Inc., also as the Chief Executive Officer of Shell Albian Sands Inc., and Senior Vice President of Oil Sands at Petro-Canada and he served as its Vice-President of Corporate Planning and Communications.

Neil Camarta also served as the Chief Executive Officer of Western Hydrogen Ltd., and Executive Vice President of Natural Gas at Suncor Energy Inc. He has operated in senior executive positions or holds directorships with a number of other energy companies and is a director of ENMAX Corp. (an energy company owned by the City of Calgary). Camarta is also a director of MindFuel (formerly the Science Alberta Foundation) and FSHD Canada Foundation. He served on the Board of the Alberta Shock Trauma Air Rescue Society (STARS). Neil Camarta was inducted into the Canadian Petroleum Hall of Fame earlier this year. “I’ve spent my career with Shell, Petro-Canada and Suncor building mega projects at home and worldwide, but I have to say, the thing I’ve enjoyed the most in the last few years is working on developing this new technology, it’s as much fun as developing mega-projects.”

Alberta bitumen requires “upgrading” before transporting by pipeline

Bitumen extracted from oil sands is a heavy crude oil which contains a large fraction of complex long-chain hydrocarbon molecules. Depending on the extraction process used, bitumen product can sometimes contain as much as two percent water and solids, which does not meet pipeline specifications for transport over long distances. Pipeline specs can be met either by upgrading or dilution with a very light oil. Further, bitumen produced from the oil sands is not only heavy, but also contains heavy metals, corrosive salts and a significant amount of sulphur. These impurities pose processing challenges to the downstream refinery, limiting the marketability of the product and even the selling price. Currently, about 60 per cent of bitumen produced from the oil sands is diluted, typically with natural gas condensate, and sold directly to market as a heavy/sour blend. The remaining 40 percent is upgraded into a light/sweet synthetic crude before being sold to downstream refineries. All upgraded bitumen is currently sourced from oil sands mining operations, while most diluted bitumen is sourced from in-situ facilities.

It is worth noting that oil is recovered using two main methods: mining and in situ. The method employed depends on how deep the oil sands reserves are deposited. Eighty per cent of the oil sands reserves are too deep to be mined: reserves that are more than 70 meters (200 feet) below the surface will be recovered through drilling into the reserves, and injecting steam, combustion or other sources of heat into the reservoir. The heat warms the bitumen so it can be pumped to the surface through recovery wells. Advances in technology, such as directional drilling, enable in situ operations to drill multiple wells (sometimes more than 20) from a single location, further reducing surface disturbance. Due to the depth of the reserves, recovery rates for the methods of extracting bitumen vary. Drilling methods cannot be used in mining areas, and vice-versa.

Mining is used when deposits lie within 70 meters (200 feet) of the earth’s surface – about 20 per cent of oil sands reserves. Like most surface mining operations, oil sands are scooped by large shovels into trucks and taken to crushers where the large clumps of clay are broken down. The sands are then mixed with hot water so they can travel through a pipeline to a plant where the bitumen is separated from the other components. All upgraded bitumen is currently sourced from oil sands mining operations, while most diluted bitumen is sourced from in-situ facilities.

Targeting the demand created by changing marine fuel standards in 2020

“The largest single consumer of high-sulphur heavy oil is the marine industry,” says Camarta. “The ships that sail upon the sea burn about four million barrels a day of 3.5 per cent sulphur. In fact, the world’s 15 largest ships create more pollution in the form of sulphur dioxide than all the cars in the world put together. So that’s our market. We would take the sulphur out of heavy oil and then we would take it to tidewater and sell it into the shipping industry, because our oil fits the new sulphur regulations perfectly.”

The coming marine fuel emissions rules could well result in even lower demand for Canadian heavy oil, reducing its net price to producers even further. Most bunker fuel burned on ships is derived from the “residue” that remains after all of the more valuable light fuels such as gasoline and diesel have been removed from crude oil in a refinery. Following combustion in the engine, the sulphur in the fuel becomes sulphur oxides, a pollutant that causes respiratory symptoms and lung disease as well as acid rain, which can harm crops, forests and aquatic species, and contributes to the acidification of the oceans. IMO first began restricting emissions in 2005 and its limits on sulphur in bunker fuel have been progressively tightened. Four “emission control areas” in Europe and North America already have a 0.1 per cent limit.

Developing the DSU process and accelerating to commercialization

“After about my third retirement, I met up with a former associate, Guy Turcotte, also a chemical engineer, and posed the question, Can we develop cleaner and cheaper ways of producing oil from the oilsands? We put ourselves out there as a start-up knowing we could recognize good ideas; we would provide the capital to commercialize those ideas.” (Turcotte founded and worked as President and CEO of Western Oil Sands, which was sold to Marathon Oil for $6.5 billion in 2007) Mr. Camarta continued, noting that “We talked to a lot of people, some were crackpots, some not. This bunch came in from Golden, Colorado with the last name Coors.” It turns out that they were the beer folk and they were the ones with the good idea. “They had been talking with other oil majors, but the other companies were a bit slow to act. I recognized their ideas as a much simpler process than I’d been used to.” Camarta then describes how they licenced the technology from Coors, committed to scaling up the idea and began to figure out how to commercialize their process. “That’s the simple version of the beginning of the DSU idea.” He then describes the process of upgrading, explaining, “Conventional upgrading, and I’ve built several really big upgraders, take the hydrocarbon molecules and break them down into smaller molecules. That’s how you turn the oil from the oil sands into gasoline. The process uses a lot of temperature, pressure and energy, takes a lot of capital and produces a lot of emissions.”

In contrast, the DSU process has no direct SOx (sulphur oxides) or GHG emissions – and it does not leave big piles of coke or asphaltenes behind. The key to the process is sodium, a powerful reducing agent with a strong affinity for sulphur and metals atoms interspersed in the complex heavy oil molecules. “In our lab and in our pilot plant in Alberta, we have successfully demonstrated that we can produce vessel-ready IMO and ECA-compliant marine bunker fuels directly from vacuum residue and other heavy feedstocks – including some bottoms that are so heavy they are solid at room temperature.”

DSU proves out at approximately half the cost of conventional upgraders

“We mix sodium with oil, and sodium melts at 100 degrees centigrade. It has the same physical properties as oil, the same density, and it mixes well with the oil,” says Camarta. And what it does when it gets in the oil, it reacts specifically with the nasty stuff, exactly the stuff you want to get out of oil, the dirty stuff. You want to get out the acid, you want to get out the metals, you want to get out the sulphur. That’s what the sodium goes for and it’s the sodium that removes that stuff from the oil, so it cleans up the oil in one step.”

One key innovation is the system of recovering and recycling the elemental sodium, done by passing material through electrified ceramic plates. The process has no direct emissions of sulphur or nitrogen oxide, two serious forms of air pollution, and produces about half the greenhouse gases of conventional upgrading. “Building a 10,000 barrel-a-day plant would cost about $300 million, roughly half the budget for a conventional facility, and the $10-a-barrel operating cost is also half what it now takes to run such operations,” Camarta says, adding that upgraded Alberta bitumen could be sent by rail to coastal terminals and pumped directly into ships with no need to go through a refinery.

The CLEARSEAS demonstration plant is designed so the equipment rests on ten skids, each four metres by four metres by 16 metres. Future commercial upgraders would be a multiple of this size so they could be set up easily. “That building block is a good scale and allows us to roll out quickly, so we don’t have to build one big plant every five years,” notes Camarta.

Capital-intensive development secures public sector investment

In May of this year, the Alberta government, through its Emissions Reduction Alberta (ERA) initiative, announced up to $70.6 million in funding toward oilsands projects estimated to result in potential greenhouse gas emissions reductions of up to four megatonnes of annual CO2 equivalent reductions in Alberta by 2030. Nine companies made it into the finals, with Camarta’s Enlighten Innovations Inc. receiving $10 million for its CLEANSEAS Demonstration Project. The CLEANSEAS project is a commercial scale of the technology and signifies a critical step toward full commercial rollout. Commercial implementation of the technology will involve construction of modules at the same scale as the demonstration plant. The modules can be installed close to bitumen production facilities or refining facilities.

In July this year, Natural Resources Canada released the semi-finalists that will compete for their share of a $155 million investment prize later this year aimed at clean technology in energy, mining and forestry, and ten oilsands technologies are on the list, Camarta’s CLEANSEAS demonstration plant included. “About half the oilsands production is upgraded by conventional upgraders, but the other half isn’t upgraded, it goes directly into the market in the U.S. where big upgraders process it. Oilsands bitumen has about five per cent sulphur and a lot of heavy metals he notes. “As there’s more of a penalty put upon sulphur, that’s going to come back and haunt the oilsands. “

Come 2020 when the green industries stop buying and burning 3.5 per cent, they’re going to burn a lot less of this heavy sulphur stuff. That’s going to push back against the oilsands just like it’s going to push back against all heavy oil production. The net impact of this is going to be lower prices, but there’s such a discount already because of lack of pipeline capacity that the impacts of reduced sulphur content are being lost in the shadows” Camarta acknowledges that there is some action within the industry to reduce the sulphur, “The biggest thing right now is getting out the sulphur, and while we do that, there are others working on this too. If we can take the dirty out of dirty oil and create a fuel oil for shipping industry, clean up the oceans as well, there’s a lot of money in that.”