May 16, 2013 / 5:05 PM / 7 years ago

COLUMN-Enhanced recovery will anchor oil prices below $100: Kemp

By John Kemp

LONDON, May 16 (Reuters) - Enhanced oil recovery (EOR) techniques could boost U.S. domestic oil production by 4 million barrels per day for 50 years, while storing all the emissions from 93 large coal-fired power plants, at a price of just $85 per barrel, according to an estimate published by the U.S. Department of Energy.

By injecting carbon dioxide (CO2) into depleted oil fields, the United States could recover an extra 67 billion barrels of oil and simultaneously trap 18 billion tonnes of manmade greenhouse gases safely underground. (“Improving domestic energy security and lowering CO2 emissions with ‘next generation’ CO2-enhanced oil recovery” June 2011)

EOR is more expensive than conventional oil production. Interest in EOR has followed the price cycle, peaking in the late 1970s and early 1980s along with the two oil shocks, and again as prices climbed between 2004 and 2008.

Its potential has recently been overshadowed by the surging output from shale, which has pushed up domestic production at the fastest rate on record. As a result, EOR has slipped down the agenda for both policymakers and the industry.

But the estimates are a reminder that shale is not the only game-changing technology capable of boosting oil output. EOR guarantees the United States will remain a major oil producer and should anchor long-term oil prices well below $100 per barrel.


Like horizontal drilling and hydraulic fracturing, techniques that underpinned the shale revolution, EOR is not new. Chevron first injected CO2 into a depleted oil field in Scurry County, Texas, in 1972.

During the 1970s and 1980s an extensive network of pipelines was built across west Texas, New Mexico and Colorado to link natural sources of CO2 with the aging oil fields in the Permian Basin. Smaller pipeline systems have been built in Mississippi-Louisiana and Wyoming.

By 2010, EOR projects were producing an extra 281,000 barrels of oil a day, about 6 percent of total U.S. output, according to the National Enhanced Oil Recovery Initiative, which lobbies on behalf of the industry. (“Carbon dioxide enhanced oil recovery: a critical domestic, economic and environmental opportunity” Feb 2012)

Nearly 4,000 miles of pipelines carry 70 million tonnes of liquid CO2 every year, mostly for injection into oil fields in west Texas, Louisiana and Wyoming.

Among the largest EOR operators are Occidental, Hess and Kinder Morgan in west Texas and New Mexico. Chevron operates in Colorado. Denbury Resources dominates EOR in Mississippi and Louisiana.


EOR is applied to oil and gas fields in an advanced stage of decline after primary and secondary production techniques have hit diminishing returns.

During a field’s primary production phase, oil is expelled under natural pressure or brought to the surface by pumping. Primary production typically recovers about 20 percent of the total amount of oil originally in place (OOIP) in the field.

As output declines, operators may resort to waterflooding, known as secondary recovery, injecting water to sweep some of the oil left behind towards the wells. Waterflooding typically recovers another 18 to 20 percent of the OOIP.

Once the water starts to break through to the wells, the operator may decide to commence a tertiary recovery phase by injecting the reservoir with CO2.

Unlike water, CO2 will dissolve into crude oil. Injected CO2 moves through the pores in the rock, encounters residual droplets of crude oil, dissolves with them and forms a concentrated oil bank that is swept towards the wells.

Tertiary recovery can add another 5 to 15 percent to ultimate recovery depending on the reservoir pressure, temperature and depth, as well as the density and viscosity of the oil. EOR works best with light oils in permeable rock formations and in re-pressurised reservoirs that have already been waterflooded. (“Carbon dioxide enhanced oil recovery: untapped domestic energy supply and long term carbon storage solution” Mar 2010)


“Implementing a CO2 EOR project is a capital-intensive undertaking,” according to the Department of Energy.

“It involves drilling or reworking wells to serve as both injectors and producers, installing a CO2 recycle plant and corrosion-resistant field production infrastructure (CO2 is highly corrosive), and laying CO2 gathering and transportation pipelines.”

The biggest single cost is purchasing the CO2. “Total CO2 costs (both purchase price and recycle costs) can amount to 25 to 50 percent of the cost per barrel of oil produced,” the department found.

EOR projects have been held back by shortages of CO2, which is ironic given the concerns about the global warming potential of releasing so much CO2 into the atmosphere.

So far, most of the CO2 employed in EOR projects has come from naturally occurring sources. The first CO2 was recovered from natural gas processing plants. As demand outstripped that source, operators targeted naturally occurring underground CO2 reservoirs such as Sheep Mountain and McElmo Dome in Colorado, Bravo Dome in New Mexico, and Jackson Dome in Mississippi.


Most EOR projects have been located in west Texas, Louisiana and Wyoming because of their proximity to naturally occurring CO2 sources. But there is nowhere near enough naturally occurring underground CO2 to support all the possible expansions of EOR.

The Energy Department estimates 20 billion tonnes of CO2 would have to be injected to recover all the 67 billion barrels of oil technically and economically recoverable from oil fields at a price of $85 a barrel. At most, 2 billion would come from natural sources. The remaining 18 billion would need to come from manmade or anthropogenic sources.

Denbury has been repositioning itself to become a pure EOR company. It has already signed agreements with six industrial facilities producing relatively concentrated streams of CO2 near the U.S. Gulf Coast to support its CO2 pipeline and injection operations.

In 2013, the company took receipt of the first CO2 from a hydrogen plant operated by Air Products at Port Arthur, Texas, and a PCS Nitrogen facility producing ammonia at Geismar, Louisiana. It will take CO2 from the new integrated gasification combined cycle (IGCC) power plant under construction by Southern Company at Kemper County in Mississippi.

The company has additional agreements to take waste CO2 from a cogeneration facility, as well as ammonia and chemical plants, planned or proposed in the region.


EOR projects involve large outlays up front and have relatively long payback periods. The first additional oil may not be produced for a year after CO2 injection begins. It can take up to five years for production to peak. Thereafter, output tends to plateau for another five years, before beginning a gradual decline.

“The return on investment for CO2 EOR tends to be low, with a gradual long-term payout,” the Energy Department reported. EOR projects remain sensitive to assumptions about interest rates as well as current and forecast oil prices.

Most projects are nonetheless viable at prices well below current levels. Denbury estimates operating costs (including the cost of buying CO2) are only around $25 per barrel at a variety of projects (“Corporate presentation” May 2013). Federal tax credits are available to EOR operators if crude oil prices fall below about $49 per barrel.

The Energy Department calculates a 20 percent rate of return on capital based on best practices currently employed in west Texas. The “next generation” of EOR techniques might be able to double the efficiency of the process, sweeping 120 billion barrels from depleted reservoirs using the same amount of CO2, according to the department.

It remains unclear how much oil will eventually be produced using CO2 EOR. The technique must compete for investment with shale as well as conventional onshore and offshore production. But it is clear the United States has plenty of recoverable resources beyond shale formations at prices below $100 a barrel.

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