Research organizations around the world look for double gains as they try to get rid of unwanted CO2 and raise energy security by increasing economic production from domestic oil and gas fields.

So far, the only systems that work well occur in places where CO2 occurs in large quantities

A gravity-stable CO2 enhanced recovery project injects gas from the top to force water below the horizontal production well and oil down to the horizontal leg. (Graphic courtesy of Dandina Rao, Louisiana State University)
close enough to large enough large fields that the cost of producing and piping the CO2 becomes economical or in demonstration products where the government puts up part of the cost of the project.

More and more research is being conducted either to make CO2 injection useful in more applications or to have techniques available when prices rise, costs fall or governments feel the need to lend a monetary hand.

A study titled “Undeveloped Domestic Oil Sources,” prepared for the Office of Fossil Energy for the US Department of Energy (DOE) by Advanced Resources International, concluded 205 billion bbl of stranded oil remains in already discovered fields in six US basins.

It also noted state-of-the-art CO2 enhanced oil recovery could technically (not necessarily economically) recover 43.3 billion additional barrels of oil from those fields. That estimate counted only the technology available at the time, CO2 floods and water-alternating-gas (WAG) floods using CO2.

Vertical flood
Research teams at Louisiana State University (LSU) believe they have come up with something better, and they’ve applied for patents on the technique, according to Dandina Rao, an LSU professor working on the gas-assisted gravity drainage (GAGD) project with the help of US $650,000 from the DOE and $200,000 from industry participants.

Speaking at the Hart Energy Publishing Brownfields: Optimizing Mature Assets (BOMA) conference in Houston, Rao said the standard sweep technique for a CO2 flood or WAG floods asks the operator to inject gas or gas and water into injection wells and sweep the oil in the producing formation ahead of a front to production wells. Sometimes the gas may break through toward the top of the formation or water may break through toward the bottom of the formation. In addition, heterogeneous materials within the formation can lower the efficiency of the sweep.

Typically, WAG injection gets an additional 5% to 10% of the oil out of the ground.

The GAGD method takes a page from Canada’s steam-assisted gravity drainage technique in which steam from a higher horizontal well heats heavy oil and allows gravity to let it flow to a lower horizontal producing well.

In the GAGD process, the operator drills a horizontal production well with the horizontal leg near the bottom of the producing formation. It then uses existing vertical wells or drills new vertical injection wells to the top of the producing formation.

Then it injects CO2 into the formation to miscible pressure, effectively building a gas cap. The gas pressure pushes the water contact below the producing well and drives the oil-CO2 mix down to the producing well with the help of gravity.

Since gas naturally stays on top of oil, the injected gas would not compete with oil flowing to the production well, and breakthrough is avoided or delayed. The horizontal producing well can produce at high rates with a low drawdown.

It’s a simple, common-sense solution, and, according to Rao, if the operator doesn’t need a miscible flood, it can simply inject nitrogen from air down the vertical wells.

Where reservoir heterogeneity decreases the efficiency of a standard flood, it might even enhance a GAGD flood, Rao said.

The study group is setting up a test on an existing Louisiana field now, but laboratory tests point to promising results. In one laboratory test, an immiscible flood produced 70.4% of the oil in place, and an miscible flood reached 90.6% of the oil in the rock.

In other tests, GAGD got 65% of the original oil in place in water-wet rock and 78% recovery in oil-wet rock. In addition, vertical fractures improve recoveries by an average 7.8%.
“GAGD can potentially outperform all other modes of gas injection,” Rao added.

Hydrate production
Another project combining hydrocarbon production with CO2 sequestration appeared in the Oct. 30, 2007, issue of the Norwegian Petroleum Directorate’s “Norwegian Continental Shelf” magazine.

It began when scientists at the University of Bergen discovered CO2 storage also could offer a method of recovering methane from hydrates. “This is a win-win solution,” said Bjørn Kvamme, who — along with colleague Arne Graue and ConocoPhillips — patented the technique.

“Several production methods are available based on the fact that the stability of gas hydrates is a function of pressure and temperature,” he said in an article authored by Kristin Gjengedal.

“Adding heat or reducing the pressure can make them unstable and thereby allow the gas to be captured. But these methods also present drawbacks,” he added.

Heat releases large amounts of water with the gas, and it would have to be pumped off. Both heating and pumping costs would be high.

Also, when the methane and water are freed, the resulting void could cause subsidence of the overlying sediments. Since hydrates often are found in connection with traditional oil and gas production, the collapse of an uphole formation could cause problems in producing the oil or gas well.

“Our solution involves injecting carbon dioxide. Under constant pressure, the thermal stability of the ice-like crystals will then be greater than with methane,” Kvamme said. The injected CO2 would replace the methane.

“The system runs automatically, a fact we’ve demonstrated experimentally, and (we) are planning to do the same with cores taken from the sub-surface,” he said.

According to the patent, the process requires a releasing agent that will release the methane from the hydrate. That agent is liquid CO2. When it contacts the methane hydrate, it releases and replaces the methane with CO2 without melting the hydrate. The result is a more stable compound than the methane hydrate, and the whole process doesn’t require any significant changes in temperature, pressure or the volume of the hydrates.

For example, the temperature of the liquid CO2 should be within 10% of the temperature of the methane hydrate.

Although the procedure can be used on an untouched methane hydrate zone, the patent describes the technique that might be used in an existing oil and gas well.

First, the operator would produce the well through its economic limit. At the completion of production, it would install a plug above the perforations and a plug immediately below the methane hydrate zone.

At that point, it could perforate the hydrate zone and inject liquid CO2. The CO2 molecules would spontaneously substitute for the methane molecules in the hydrate. The released methane would flow back to the well bore for recovery at the surface.

In a thick hydrate section, the process could be repeated as far up the formation as necessary. The injected CO2 would remain permanently sequestered behind plugged casing in the abandoned well.

Other solutions
Additional research is continuing in the same areas. For example, in a paper title “Stranded Oil in the Residual Oil Zone,” written by L. Stephen Melzer of Melzer Consulting for Advanced Resources International in a DOE project, Melzer said many oil fields have a zone as much as 300 ft (92 m) below the oil that contains both oil and water. Attempts to tap oil from those residual oil zones in the Permian Basin of West Texas using CO2 have been successful, yielding approximately as much oil as a standard waterflood later swept with CO2.

Another study by Melzer and Advance Resources showed a multitude of problems with traditional CO2 floods, including fingering of CO2 to the well bore, loss of miscibility from inadequate pressure control, improper placement of CO2 and simply not enough CO2 injected into the producing formation.

For example, in a computer simulation of a deep, light-oil field with 2.365 billion bbl of original oil in place, the team raised CO2 concentration from 0.4 hydrocarbon pore volume to 2.0. That added 539 million bbl of recovery from the field and raised recovery efficiency to 67%.
Under that efficient plan, the field would recover 1.106 billion bbl of oil in 37 years with a 47% recovery compared with 234 million bbl of oil in 19 years with 10% recovery using traditional techniques. Life-of-field cost would climb from $1.93 billion in the traditional field to $6.93 billion in the next-generation field.

The studies and the new inventions coming on stream show the industry still has a lot of learn about optimizing production, but those lessons will be important contributors to future supplies.