EOR's Quiet Revolution

A bad reputation is hard to shake, but it can happen.

In the 1970s and 1980s, many producers injected chemicals such as polymers into wells to improve oil production. As can happen with any new technology, the field trials were a flop.

The situation wasn’t helped by a well-intentioned fiscal incentive to spur chemically enhanced oil recovery (EOR) in the United States. Tonnes of chemicals were dumped down wells without much to show for it except a lasting belief that chemical floods don’t work.

But that was then.

Technology is always improving. Everyone familiar with the oil and gas industry knows improvements in seismic data acquisition and processing have been game changers, as have advances in horizontal drilling and hydraulic fracturing. But the first horizontal wells, for example, were failures.

“What people don’t realize is we need those failures to learn,” says Richard Baker, chief technical officer with the reservoir development services division of Baker Hughes Incorporated.

While oilfield chemistry may never be as sexy as long horizontal wells with multiple frac stages, that business has nonetheless undergone a quiet revolution. Polymer flooding was being tried as far back as the 1960s, but it wasn’t very successful as an EOR method until about five to 10 years ago, says Baker, a veteran reservoir engineer and international EOR consultant.

What’s changed, says Baker, is that the chemical formulation has improved dramatically. A problem with a lot of the early chemical floods was that iron or particulates in the reservoir—or just reservoir temperatures and pressures—would degrade the polymer molecules. But now the polymers are much more durable to field conditions.

On top of that, the industry’s understanding of reservoir mechanics has dramatically improved in the past 30 years. Horizontal wells are longer and can be drilled with greater accuracy, accessing much more of the reservoir from a single wellbore.

Comparing today’s chemical floods with those used in the 1970s and 1980s is like comparing a computer today with a computer from 20 years ago, or comparing 2-D seismic to 3-D seismic—there’s been that much of an improvement, Baker says.

Results to date speak for themselves.

Canada’s biggest oil and gas producer, Canadian Natural Resources Limited (CNRL), has implemented what it says it the biggest polymer flood in North America at Pelican Lake, a large, shallow heavy oil pool in northeast Alberta.

CNRL says it has had “great success” with polymer flooding at Pelican Lake. The company began testing the EOR technique in 2005 and continues to expand the flood. Converting from primary production to polymer flooding requires re-pressurizing the reservoir with the polymer solution, and CNRL says the full oil-production response at Pelican typically takes nine to 24 months.

Last year, CNRL’s Pelican production averaged about 38,000 barrels of lucrative heavy oil per day and the company is forecasting average 2012 output of 38,000–40,000 barrels per day. In the longer term, the company expects output to peak in 2015 and to plateau at about 80,000 barrels per day.

Polymer flooding boosted CNRL’s proved oil reserves at Pelican Lake to 276 million barrels exiting 2011, up 15 per cent from year-end 2010. The company attributed the increase to continued expansion of the polymer flood as well as optimized well configurations and injection strategies.

CNRL’s 2012 capital budget for Pelican Lake is $470 million, up from $426 million last year. The company said this year’s focus is on optimization with the construction of a new 25,000-barrel-per-day battery and the drilling of 63 polymer injector wells and 13 oil producers.

More than 90 per cent of CNRL’s Pelican produced water is recycled, and the company has begun using brackish water to mix with the polymer.

The company is piloting the use of polymer flooding at two other locations. In 2006, the first patterns were flooded at Horsetail in the Brintnell field, about 25 kilometres northeast of the northern Alberta hamlet of Wabasca-Demarais. CNRL says the oil response at Horsetail takes about nine months. At South Brintnell, where polymer flooding was tested in 2009, the oil response takes about 17 months.

The other big player in the Pelican Lake field is Cenovus Energy Inc.

Cenovus, which is best known as a steam-assisted bitumen producer, began injecting at its own Pelican Lake polymer pilot in 2004. Today the company has more than 170 wells injecting polymer and it says the results are “extremely positive.”

Last year, Cenovus’s Pelican Lake production averaged 20,424 barrels of oil per day, down from 22,966 in 2010. Wildfires reduced 2011 output by about 500 barrels per day, a scheduled maintenance turnaround shaved off another 300 barrels per day and natural declines also contributed to the decrease.


Cenovus’s Pelican Lake capital spending tripled to $317 million last year from $104 million in 2010. Last year’s spending was on infill drilling to advance the polymer flood, the drilling of stratigraphic test wells, facilities expansions and maintenance. Cenovus drilled 31 production wells at Pelican Lake last year, up from 12 in 2010.

This year Cenovus expects to spend between $525 million and $575 million—or about 17 per cent of its total capital budget—at Pelican. Production in 2012 is expected to average between 23,000 and 26,000 barrels of oil per day.

Based on the polymer flood’s strong performance, Cenovus embarked on a multi-year plan to boost its Pelican output to 55,000 barrels of oil per day by the end of 2016. A spokeswoman says the company plans to drill 1,300–1,400 Pelican wells in the next five to seven years. To support the expansion, a new battery is in the planning stages with construction slated to start in 2013.

Cenovus is also “working on” expanding its alkaline surfactant polymer (ASP) flood at Suffield, which began as a pilot in 2007, a spokeswoman says. Currently, there are two injector wells and seven producers at that project in southeastern Alberta.

Cenovus believes the ASP flood could extend the life of the Suffield heavy oil field by at least 10 years. Original oil in place in numerous pools on Cenovus’s Suffield lands has been estimated at more than a billion barrels. Without the polymer flood, the company estimates it would produce 25 per cent of that oil. With the polymer flood, it expects to boost the recovery rate to 40–45 per cent.

Another company that has gone the ASP route is Husky Energy Inc., one of Canada’s biggest heavy oil producers.

Husky already has ASP floods at Gull Lake in southwestern Saskatchewan and at the Warner and Crowsnest fields near Taber in southern Alberta. A spokesman says production has been “in line with expectations.” The company is developing another ASP flood at Fosterton in southern Saskatchewan. Fosterton pipeline construction is finished and ASP injection is planned for the second half of 2012.

Other polymer players include Pengrowth Energy Corporation. In 2011, Pengrowth kicked off the first year of a multi-year drilling program at its Bodo heavy oil properties, which straddle the Alberta-Saskatchewan border. Pengrowth has been running a polymer pilot in the area since 2006. Based on the results of the pilot, the company has said polymer flooding could improve the ultimate recovery of oil from these pools to 25 per cent (from five per cent).

In 2011, Pengrowth drilled 34 wells, including 26 producers, at East Bodo. Similar drilling programs are planned over the next few years.

In southern Alberta, Zargon Oil & Gas Ltd. consolidated its oil resource base at its Little Bow property through several acquisitions, and is developing an ASP flood. Earlier this year, the company said it had completed the project design studies and was proceeding with detailed engineering and the procurement of long-lead-time equipment.

Zargon estimates chemical injection into the Little Bow Upper Mannville I oil pool will start in July 2013 and a significant oil production response will occur by January 2014. The combined capital cost of the first two phases of Zargon’s Little Bow ASP project is estimated at $48 million with $21 million to be spent in 2012. The rest is to be spent in 2013­­­–2015.

On a smaller scale, Enerplus Corp. began a polymer flood at Giltedge last year, and a pilot in the Medicine Hat area of southeastern Alberta is to start injection this year. According to Enerplus’s 2011 annual information form filed in March, production results from the Giltedge project area are “better than anticipated” and the company expects to expand the polymer flood by adding three injection wells in 2012. Combined spending on both projects is expected to total $7 million this year.

Still more chemical floods have been launched or are being planned in western Canada. Some of the Alberta projects have been approved for royalty relief under the Alberta government’s Innovative Energy Technology Program.


The upsurge in chemical flooding hasn’t been confined to North America. According to a July 2011 report prepared by Calgary-based Premier Reservoir Engineering Services Ltd. for the Alberta Department of Energy, the world’s largest polymer flood is at Daqing, China. By 2004, Daqing had 31 commercial-scale projects involving 2,427 injection wells and 2,916 production wells, the report says. It says the Daqing and Shengli fields—both under polymer flood—contributed about 250,000 barrels of oil per day in 2004.

Worldwide interest in chemical EOR skyrocketed in recent years as an increasing number of fields matured and rising oil prices improved returns, says Denver-based TIORCO LLC. Formed in 1977, TIORCO describes itself as a global leader in EOR technologies.

TIORCO says the Canadian oilpatch is among the most aggressive at implementing chemical injection to boost both secondary and tertiary recoveries.

“In just the past five years, we have engaged in one or more aspects of 15 chemical EOR projects in Canada, making it our most active market outside the United States,” says Charles King, TIORCO’s district account manager for Canadian EOR solutions.


After high oil prices, the biggest driver of chemical EOR in Canada is the size of the prize. Low recovery rates for heavy oil in many fields puts Canada’s typical remaining oil-in-place at well above 50 per cent—even after waterflooding—which represents billions of dollars that can be tapped with the right technology matched with reservoir conditions, King said in a written analysis of the factors fuelling chemical EOR interest in Canada.

TIORCO says the third factor driving chemical EOR in Canada is the large number of independent operators concentrating on conventional oil. “While the major multinational producers have focused on developing the oilsands regions, many independents still work the more traditional fields,” King says. “In our experience, these smaller operators tend to make faster decisions to try new technologies compared with their larger competitors. As a result, they move through the critical reservoir and risk analysis phases more rapidly and pull the trigger on field projects sooner than many of the big players.”


Like Baker Hughes, TIORCO also cites better chemistry.

“Chemical EOR today is far more efficient and cost-effective than it was 20 or 30 years ago, primarily due to significant improvements in reservoir simulation or modelling and the introduction of customized EOR-specific chemicals which can be used in lower amounts,” King says. “These technological advances help with better understanding of the risk factors as well as the improvement of overall project economics.”

Unlike 20 years ago, chemical floods today are being considered for reservoirs hotter than 250 degrees Fahrenheit and salinities exceeding 200,000 parts per million total dissolved solids, thanks to better surfactants and polymers, says TIORCO.

“With today’s advanced chemical formulations, polymer floods and gel treatments are boosting the recovery from waterflooding by five to 20 per cent,” King says. “Surfactant-polymer floods applied as a tertiary method can improve overall production by 20–35 per cent.”

He says other factors making western Canada attractive for chemical flooding include the region’s long history of chemical EOR and the gold mine of data available from the Alberta Energy Resources Conservation Board.

“Few, if any, countries or states have a similar organization that maintains meticulous records on the production performance of fields, reservoirs and formations dating back for decades,” King says in his analysis. “Included in the archives are reports detailing the success—and failure—of every project implemented in Alberta. Access to this vital information gives EOR planners in that province an enormous head start in the pre-pilot analysis phase because it provides insights as to which technology may work or not.”


While most of this article has focused on polymer or ASP floods—long-term EOR schemes that cost millions of dollars—operators may also be able to improve their economics greatly through a polymer gel treatment—a one-time affair that may cost only $100,000 or $200,000 per treatment to reduce water production.

And water production is a huge issue. Baker, who has consulted on EOR all over the world, says about 80 per cent of global oil reserves bookings are from fields more than 20 years old. In other words, 80 per cent of the worldwide new reserves booked every year are added from mature fields. In North America that number is about 95 per cent.

“And when you look at those fields, you produce a water/oil ratio of about 20 to one,” says Baker. “Let’s say Canada produces about 2.6–2.7 million barrels of oil per day; we could produce 20 times the water.”

So it’s hard to overstate the importance of water—from an economic as well as an environmental standpoint. For example, if an operator can go from a 20-to-one water/oil ratio down to a 10-to-one ratio, operating costs may be reduced by $10 per barrel.

One way to cut water production is to plug off cement channels or natural fractures that, in a waterflood, may allow water to flow from injection wells to oil production wells.

So how many reservoirs in western Canada could benefit from the use of polymer gel treatments to achieve water shutoff?

To find out, Gaffney Cline and Associates, a unit of Baker Hughes, came up with screening criteria for Alberta and Saskatchewan oil pools, using public data. The reservoirs had to have high water cuts, very low recovery factors and oil wells being shut in due to uneconomic water production.

In addition to poorly performing waterfloods, each oil pool had to have at least five million barrels of remaining oil-in-place to ensure there’s enough incremental oil left to make a gel treatment economic.

The result? The screening found 193 oil pools in southeastern Saskatchewan and 163 in Alberta that may be good candidates for a gel treatment water shutoff, says Kerry Sandhu, Gaffney Cline’s general manager.


  • Although most chemical EOR (chemically enhanced oil recovery) projects now use “designer molecules,” the basic concept behind the technology has remained the same for many years.
  • Polymer flooding is a continuous injection of low-concentration polymers during waterfloods to bring the viscosity of the injected water closer to that of the oil, thereby improving sweep efficiency in the reservoir. Like waterfloods and CO2-based EOR schemes, polymer floods are multi-year projects.
  • Polymer gel treatments are a one-shot deal. Injected polymers and crosslinking agents are pumped into fractures and high-permeability “thief zones” where they harden and reduce water production. This diverts injected water into previously unswept low-permeability layers.
  • Alkaline surfactant polymer (ASP) floods: In a straight polymer flood, polymer powder is mixed with injected water to produce a viscous fluid that will push more oil out of the pore spaces, improving sweep efficiency. Surfactant is essentially detergent. It changes the “wettability” of the rock, reducing the interfacial tension between water and oil. So besides the physical sweeping mechanism of a straight polymer flood, a surfactant polymer also washes oil from the rock. An ASP flood includes an alkaline chemical. In the case of Cenovus’s Suffield flood, the alkaline injectant reacts with the acids in the oil to create a natural surfactant. Organic acids in the oil reduce the amount of surfactant that needs to be purchased, thereby lowering operating costs.

—Sources: TIORCO, Baker Hughes, NTM archives

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