Friday, October 24, 2008

The Carbonate Question


This article appears in the November, 2008 issue of Oilsands Review. Graphic shows Alberta oilsands in yellow, major heavy oil deposits in blue, Grosmont bitumen carbonate formation in red and bitumen triangle within dashed line. Source of map here.
By Peter McKenzie-Brown

According to one view, planet Earth has two energy super-provinces – one in the Old World, the other in the New. The Old World super-province stretches from North Africa through the Middle East into Siberia. Rich with conventional oil, it’s the source of most of the petroleum traded on global markets.

The New World super-province reaches from northern Alaska and the Beaufort Sea through Alberta’s oil sands down to Venezuela’s Orinoco heavy oil belt, and continues south between the Atlantic coast and the eastern Andes. Richer in oil than its Old World sibling, its conventional resources are mostly in decline. However, this vast region has great volumes of untapped unconventional resources – notably Alberta’s oilsands, Venezuela’s Orinoco heavy oil belt and America’s oil shales.

This article focuses on the least known of those unconventional resources. Bitumen carbonates are common reservoir rocks totally saturated with very heavy oil. They are also the hydrocarbon resource in which Canada leads the world by an almost incomprehensible margin.

Canadian deposits contain 96% of the entire world’s supply of this black, barely mobile oil. That would be just a statistical oddity if not for the volumes of hydrocarbons involved. There are nearly 450 billion barrels in the ground in Alberta. Seventy-one percent of that total (318 billion barrels) is in the Grosmont formation – a massive structure underlying much of the Athabasca oilsands deposit. Another 65 billion barrels of bitumen can be found in the Nisku carbonate, which is associated with the Grosmont. In Peace Country, the bitumen-saturated carbonates contain as much oil as the Peace River oilsands deposit – once again, about 65 billion barrels.

Here’s another way to put those numbers in perspective. Alberta’s bitumen deposits comprise the largest petroleum resource in the world. One fourth of that resource is in carbonate reservoirs.

There is a catch, of course. Like the oilsands many years ago, there are no economic ways to produce oil from these deposits yet. However, in early 2006 a numbered company shelled out C$465 million for oilsands leases in the Grosmont. When the owner of that mystery company turned out to be Shell – not known for taking high risks when large amounts of cash are at stake – many previously skeptical observers began to see these carbonates as a resource whose time was nigh. Is that optimism justified?

Nature of the resource: Carbonates are minerals that contain the carbonate ion, CO3. Probably most of the world’s conventional oil resources are in traps made of these rocks. While the most common reservoir carbonates are limestone (a calcium carbonate) and dolomite (a magnesium and calcium carbonate), reservoirs typically include many other carbonate minerals.

On the surface, Alberta’s bitumen carbonates have the makings of an oil producer’s nightmare. The rocks themselves are full to saturation with huge volumes of highly viscous, heavily biodegraded bitumen – the most viscous bitumen carbonate in the world, in fact. The resource is thicker than molasses. In general, the carbonates have little permeability so the bitumen is in a reservoir that won’t easily let it escape, and for other reasons the reservoir rocks can yield as much trouble as oil. The resource is in the middle of the bush. Once you get the bitumen out of the rock, it isn’t transportable without lots of diluent, and it isn’t commercial without extensive upgrading. For all this Shell paid nearly half a billion dollars?!

What Shell paid for was the potential. The volumes in the ground are so huge that a relatively small amount of production from a sweet spot in the Grosmont could be hugely profitable. In a number of cases worldwide, some bitumen carbonates have gone on production with reasonable results – notably Iran’s offshore Zaqeh field (no longer producing) and France’s Lacq Superieur. As we shall see, Shell’s ace in the hole is technology.

In the 1970s and 1980s, a number of companies conducted experiments on the Grosmont formation, mostly in cooperation with the long-defunct Alberta Oil Sands Recovery and Technology Authority (AOSTRA). Although no commercial oil resulted from these experiments (production was pumped back underground), the technical community began to understand the resource, and to dream about bringing it into production.

According to Roy Coates of the Alberta Research Council (ARC), bitumen carbonates are now at the place where non-mineable oilsands were some decades ago. Commercial development is in the future – maybe 20 years. “That’s when carbonates will be at the stage where SAGD developments are now,” he said. “I don’t consider SAGD really commercial yet. (Producers) are still trying to optimize the process.”

Coates is program manager for the Carbonate Research Program, a 3-year, $2.3 million per year initiative of major companies plus two agencies of the Alberta government. He seems fascinated by the challenges of the Grosmont bitumen carbonate, beginning with the matter of where the stuff came from. “That’s something we’re looking at. I would venture to say that it is the same oil as in the oil sands. We don’t know where the bitumen originated. It could have originated in the carbonates and flowed to the oilsands or vice versa. We don’t know the answer to that. But the properties are so similar that you should consider them to be the same oil.”

Matrix, vugs and fractures:
The fact that it is the same oil as the oilsands is one of many problems presented by this resource. Its viscosity is such that it doesn’t flow naturally. Like bitumen from the oilsands, you have to make it thinner to make it flow. That is only the beginning of the problems, however. For example, the bitumen formations are 200 to 1,000 metres deep, which means they are not mineable. Gas drive in the reservoirs is insignificant. The problems get even worse when you consider reservoir permeability and porosity.

According to Coates, the Grosmont carbonate “almost has three systems of permeability and porosity.” The matrix of carbonate rock is very tight, with low permeability. Yet over eons it has somehow become saturated with bitumen. That’s the first system: low-permeability, low porosity rock full of bitumen so viscous it won’t flow without treatment.

The second system harbours other problems. Within those carbonate rocks are large cavities, called vugs – often the diameter of your arm or bigger. For the most part, these structures are leftovers from eras when water ran through the rock, dissolving caverns and other crevasses in it. They fill with rock debris (often overburden), but they also fill with bitumen. These structures can have good permeability and porosity, but they do not always form good producing reservoirs and they cause drilling problems. According to one report, during drilling “the drill bit has been observed to drop several feet as it passed through a large tunnel filled with bitumen...and these irregular tunnels...lead to a loss of mud circulation during drilling.”

The third permeability/porosity system consists of long fractures in the rock. “When you try to heat a reservoir or inject a fluid into it,” said Coates, “because of the fractures you can’t be sure where the steam is going to go.”

These difficulties notwithstanding, in the early years of experimentation on the Grosmont, there were some great successes. According to an AOSTRA report, in the late 1970s Unocal (since absorbed into Chevron) and Canadian Superior (absorbed into Exxon Mobil) conducted a series of field tests to assess steam stimulation, steam drive and combustion on the structure. In one instance, “results were spectacular. Bitumen production rates from a single steam stimulation well of up to 550 barrels per day were obtained”.

Despite these results and those from further trials, the companies abandoned these pilots in the mid-1980s, for two reasons. One was the problem of logistics-related high costs (the Grosmont is in a remote area, without roads and other infrastructure). More importantly, the companies had serious technical concerns about the viability of production – especially in the lower-price environment that followed the oil price shock of 1986.

In situ refining: Of course, that was then and this is now – a world of high prices and improved technologies. In recent years, other companies have been testing Alberta’s bitumen carbonates. One notable player is Husky Energy, which has accumulated substantial holdings in the Grosmont, for relatively small amounts of cash. Husky estimates its Saleski bitumen carbonate properties contain 19.5 billion barrels of original oil in place. You don’t need to coax a large percentage of that oil from the rock to find yourself with a valuable asset. Husky’s tests so far have used technologies that are advances on the methods tested long ago by Unocal and Canadian Superior, but similar in concept.

Shell, however, is different. When Shell made its startling $465 million bid for part of the Grosmont, the company clearly had in mind substantial production volumes. The industry wondered what was going on, until a hint of company thinking came out in a recent interview with Jan van der Eijk, Royal Dutch Shell’s chief technology officer (CTO). The occasion was a wide-ranging discussion of technology, but largely centred on Shell tests at a bitumen carbonate deposit in the Peace River area. New Technology magazine reported the story.

According to journalist Pat Roche, “In what could lead to one of the most revolutionary innovations in the history of the oil and gas industry, Shell has been testing a way to upgrade bitumen in the reservoir for more than two years. Electric heaters raise the subsurface temperature to the point where the reservoir, in effect, acts as a refinery. ‘The product that you produce is almost water white, and it is as mobile as water,’ says van der Eijk.”

This “in situ upgrading process”, as the company calls it, has been more than a decade in the making. It began with tests on oil shale in Colorado. In its oil shale tests, Shell recovered 1,700 barrels of light oil from a 10 by 13 metre area at its Mahogany test site. The company used underground electric heaters like those introduced at Peace River to induce chemical pyrolysis underground. This “in situ conversion process” distilled shale-bound kerogen (a precursor to oil) into synthetic crude oil. A by-product of the tests was shale gas.

The Peace River test was the first to use electric heaters to upgrade oil in the ground.

Journalist Pat Roche continued, “As happens in a refinery, the lighter products are boiled off, leaving the heavier components behind in the reservoir. The upgraded oil can be further refined into products such as gasoline and jet fuel. ‘The product is really impressive,’ [says van der Eijk].

“‘In a refinery,’ he explains, ‘you need to have a certain throughput through a vessel. And that drives you to a certain reaction rate; otherwise, you just don't have enough productivity.’ But in the subsurface, the reservoir serves as a gigantic vessel. ‘And in that sense you can allow much lower reaction rates. The vessel is much larger and you can let it go for a year rather than a minute throughput [in a refinery].’”

Late last year, Shell filed a regulatory application to test its in situ upgrading process in the Grosmont bitumen carbonates. Perhaps its tests in that massive formation will help transform Alberta’s bitumen carbonates from vast stores of puzzling gunk to one of the hydrocarbon jewels of the New World. You can never tell.
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