Today, the world has many resources of heavy oil. For those that seek to tap into that oil, the challenge has always been extraction, the process of “mining” the heavy crude. Today’s producers have developed new technologies that allow them to get such oil to the market efficiently.
When the market is stable, heavy oil assets have the potential to generate many years of steady cash flow—wells can typically produce for more than 50 years. However, when oil hovers around $50 per barrel, as it was at the time this article was written, the economic feasibility of production comes into question. Still, heavy oil is an attractive solution to meet global energy needs and an excellent market for valves.
HOW HEAVY IS HEAVY?
Oil production falls basically into three categories. They are (in order of lightness): conventional, heavy oil and oil sands. Conventional most often means light crude that can easily be captured by simply tapping into a reservoir. It is the source for the images of gushers spraying oil that fueled the hopes of many a wildcatter in the early days of oil exploration.
Heavy oil is very different. It has high specific gravity (American Petroleum Institute gravities from 10 to 20 degrees), low hydrogen-to-carbon ratios, high carbon residues and high amounts of asphaltenes, heavy metal, sulphur and nitrogen. Its extremely viscous nature creates both technological and economic challenges, and the heavier the oil is, the more difficult it is to extract. Many different processes are involved, and they are both costly and complex.
The Heavy Oil Science Center in Lloydminster, Canada, which straddles the border between Alberta and Saskatchewan, is a valuable resource for information on the heavy oil industry. Franklin Foster, one of the founders, provided much of the information shared here about the characteristics of heavy oil, the methods of processing it and the challenges.
Bitumen is oil that is too heavy or thick to flow or be pumped without dilution or heating. At 52°F (11°C), bitumen, which is what is normally considered oil sands, is hard as a hockey puck. Such oil is recovered using two main methods: open-pit mining and in situ drilling. The chosen method depends on how deep the reserves are deposited.
Bitumen close to the surface is mined through the open-pit method, which is similar to many coal mining operations (Figure 1). Large shovels scoop the oil sand into trucks that take it to crushers where large clumps of earth are broken down. This mixture is then thinned out with water and transported to a plant, where the bitumen is separated from the other components and upgraded to create synthetic oil. About 20% of oil sands are recoverable through open-pit mining.
Most heavy oil production, however, is accomplished with other technologies, including cold heavy oil production with sand (CHOPS), vapor extraction (VAPEX) and thermal in situ methods (e.g., steam-assisted gravity drainage or SAGD and cyclic steam stimulation or CSS). The main oil-related challenges involved in production are gravity and the viscosity of heavy oil. The technologies used must be robust enough to withstand the challenges of abrasive solids as well as corrosive media.
The CHOPS method, which was pioneered in Canada, allows sand into the wellbore with the oil to improve well productivity. Wells that formerly produced only 20 barrels a day have been observed to produce more than 200 barrels a day using this method, according to Canada’s Centre for Energy.
VAPEX is a non-thermal recovery method that involves injecting vaporized solvents into heavy oil, creating a vapor-chamber that oil flows through because of gravity drainage. This method has lower greenhouse gas emissions and significantly less water consumption compared to other technologies currently in use. It also can be used to recover bitumen from zones too thin for traditional thermal recovery.
SAGD (Figure 2) is a thermal in situ recovery method that is based on two well-known and basic facts: Hot oil flows better than cold oil, and gravity pulls the densest materials to the bottom.
For SAGD, two or more wells are drilled into the pay zone of an oil-bearing reservoir. A horizontal production well is drilled into the lower part of the reservoir, and horizontal or vertical steam injection wells are drilled above and close to the production well. Steam is continuously injected through the upper wellbore. When enough steam is injected, a steam chamber rises to the top of the reservoir, while hot oil drains down to the producing well. That oil is then pumped to the surface. This system makes it possible to continuously recover bitumen from the play.
Another thermal in situ recovery method is CSS (Figure 3), which is also known as “huff and puff.” This is a three-stage process involving several weeks of steam injection, followed by several weeks of “soaking.” After these two phases, a production phase occurs where oil is produced by the same wells into which the steam was injected. As production declines, the injection phase is restarted. The high-pressure steam not only makes the oil easier to move, it also creates cracks and channels through which oil can flow to the wellbore.
While SAGD and the other steam injection methods sound similar to hydraulic fracturing, the two extractions are quite different. In the case of steam injection for heavy oil, the steam is not used to fracture the rock and provide pathways for gas or oil to escape the rock. It is simply heating the oil to make it softer, allowing it to flow easier.
According to Bill Patrick, regional manager for Velan, companies historically believed that the same valves and pressure classes would apply to heavy oil as conventional light oil applications. Hotter temperatures and other challenges, however, have made that impossible.
“In the early days of in situ steam injection, companies tried to use regular power plant valves,” he explains. “It was assumed that the applications would be easier than a power plant because the temperatures were lower.”
However, power plants generate super-heated steam that is very dry and generally less damaging to power plant components such as turbines.
“Power applications sound like a more difficult service because the temperatures are higher for the same relative pressures compared to an in situ steam injection application,” Patrick says. However, steam injection applications are more difficult for several reasons, including:
Because in situ steam injection uses lower temperatures, the flow is not necessarily pure saturated steam. There may be liquid in the steam that is not removed because hot water is still contributing to the heating effect on the oil. Therefore, sites for in situ steam injection rarely use steam traps and don’t usually have steam dryers. This two-phase flow (steam and condensate) is much more difficult to handle from an erosion point of view, and sometimes from a corrosion point of view, than the dry and pristine superheated steam of a power plant.
In a power plant, the same water typically is used over and over in a closed loop system. A tremendous emphasis is placed on water treatment because it must be a very clean environment. In an in situ application, the water is most often dumped down a hole into the ground so the water treatment is not extensive, and the steam quality is not high. This does not create a danger to the environment, but it can significantly damage the piping components that must handle it.
In a power plant, almost all valves are indoors in a controlled environment. In an in situ application, the valves are scattered inside and outside, and are exposed to rain, dust and ambient temperatures, which can create massive cycles of temperature swings.
The cyclical nature of the in situ process application creates a major challenge for valves. This is a problem that in situ valves share with their counterparts in combined-cycle power applications. In a base load plant, everything runs smooth and steady. But in a combined-cycle plant, operators have to deal with peak loads (starts and stops), low loads and sometimes latency, which is a challenge for piping system and valve designs. In situ steam injection for heavy oil is similar. It is fully “on” some days and shut off on others, creating thermal and pressure extremes that are tough on castings, welds, gaskets and packing.
Some oil sands steam generators are built in with a co-generation plant, which is a different set-up from straight steam production. In such a case, steam for power is generated at the same time as steam is required for the process. Some power may be used in the plant or it can be tied into the grid.
Experts consider corrosion one of the most costly problems plaguing the heavy oil industry, and according to Foster, it is not just the water from steam that contributes to corrosion of equipment, including valves.
“Salt water produced with oil is highly corrosive, and most crude oils contain varying amounts of hydrogen sulfide, which is also quite corrosive,” Foster says.
He goes on to explain that anticorrosive measures can be taken, including injecting a chemical corrosion inhibitor down the casing/tubing annulus; using plastic-coated tubing; and using special corrosion-resistant alloys and cement-lined pipe.
“Each of these methods has distinct advantages and disadvantages,” he says. Frequently, however, the cost of reducing the corrosion rate is so high, it cannot be justified, in which case no anticorrosion measures of any kind are taken and the equipment is replaced at the end of its useful life.1
The valves used in steam injection include gate, globe and check valves, along with some ball valves. Their function is for both on-off and throttling or modulating services.
“The base valves that are used for the steam injection might look the same as any other ball or gate valves,” Patrick says. “But the trim and packing materials are quite different from that used for cold production.”
For the internals, the trim is a vital design consideration, with hard materials used on the steam side, replaced by softer materials when used on sour applications on the production and plant side.
Most applications in situ can be handled with very basic materials like carbon steel for the body and bonnet, although sometimes stainless steel is required. “For the side of the piping producing the oil, those valves used for heavy oil are not that different from those used in conventional production.”
In mining operations, valves are used where oil and sand is mixed with water, then chemicals are used to separate the oil from the sand. Low-pressure slurry valves really take a beating in such operations, according to Patrick. “Generally, knife gate valves do the job, though some pinch valves are also used,” he says.
As far as valves for control within in situ facilities, “An amazing number of the valves in the field are manual control,” Patrick says.
This is because some valves cannot be remotely operated. “Production is cyclical, so operators may fire up one pad as another goes down; the valves are often simply opened and closed by hand,” he explains. On the plant and upgrader [the facility where the bitumen is upgraded into synthetic crude], there are many standard refinery valve types with the addition of metal-seated ball valves as well as many types of control valves.
The technologies for heavy oil extractions have evolved as this source of petroleum has become a bigger part of the market. Even if the market price for crude makes heavy oil production a little less attractive cost-wise, the growing demand in the world for energy translates into a growing need for the valves that are capable of handling the demanding applications in the process of extracting heavy oil and getting it into production.
1. Lloydminster Heavy Oil: www.lloydminsterheavyoil.com/workover.htmminsterheavyoil.com/workover.htm
CANADIAN INVESTMENT IN HEAVY OIL
Technological innovations and political policies friendly to the oil industry have brought unprecedented oil sands development in Alberta and Saskatchewan since the turn of the 21st century. Investments in Canada’s oil sands have grown by tens of billions of dollars since 2003 (with the exception of a recession in 2008/2009).
Until the recent plunge in oil prices, the Canadian Energy Research Institute (CERI) projected Alberta could expect to get $350 billion in Canadian dollars (about U.S. $278 billion) in royalties and $122 billion in Canadian dollars (about U.S. $97 billion) in provincial and municipal tax revenue from oil sands over the next 25 years.
The decrease by half (to about $50 per barrel at press time) in the price of oil since December 2014, however, has changed the outlook. The International Energy Administration cut Canada’s production growth forecast by 430,000 barrels per day by 2020, and Canadian oil and natural gas firms have announced capital expenditure cuts totaling $109 billion in Canadian dollars (about U.S. $86.4 billion) from their 2015 budgets. Experts at one of Canada’s largest banks, RBC, say exploration and production companies may reduce capital spending by 31%.
Existing projects by Canadian oil sands producers can operate profitably below this $50 per barrel price, according to financial data by Cenovus, Husky and others. Break-even points for long-operating projects such as Cenovus’ Christina Lake and Husky’s Lloydminster range from a low of $26 to a high of $42 per barrel, which makes them profitable even at today’s prices. However, Suncor, Canada’s largest oil company (by production volume), has joined many other North American energy producers in slashing its operating budget, saying it will shave $1 billion in Canadian dollars (U.S. $810 million) from its budget and lay off 1,000 contract workers.
Peter Hall, chief economist at Export Development Canada, does not believe these cuts are all bad news. “Crisis is the mother of transformation,” he said. “A full blown crisis is a huge motivator to rethink the model and to invent solutions that have not been thought about before.”
One area that needs such motivation is finding ways to reduce the amount of energy needed to extract and process the heavy oil. For thermal recovery, energy consumption amounts to 20% of the produced quantity, mostly to generate huge quantities of steam. For mining processes, it is equivalent to 10% of the bitumen produced. With the technologies and resources currently available, the price of crude oil must be around $80-90 dollars per barrel for oil sands development to be economically viable, according to oil experts.
This will mean many opportunities for creators of technologies that will lower costs and for innovative companies that can make them work.
Despite current prices, companies such as Suncor have pledged to move ahead with certain growth projects, though Alister Cowan, the company’s chief financial officer, says his company will consider slowing investment in large-scale projects if prices remain closer to $45 per barrel for the next two to three years.
Ironically, this is precisely when you want to build a major capital-intensive project “because nobody else is,” Cowan explains. Also, companies that know how to tap into skilled workers “are seeing a big increase in productivity. That’s precisely why we want to build now,” he says.