[Smokin' Joe]

Using carbon dioxide for reservoir pressure maintenance/tertiary recovery can be a viable option (being done in Canada, using CO2 from the Great Plains Coal Gassification Plant). First, just using the pop bottle analogy, If you drilled a hole in the cap and sealed a tube in place that reached into the gas above the liquid, shake it a little, and you produce all the foam off the top of the bottle, there is nothing to push the liquids out. If you drilled a hole in the cap and sealed a tube in place that reached into the liquid, then shook the bottle a little, the gas will push the liquid out. If the gas has been produced out of the reservoir, repressurizing it with CO2 can help move oil out--otherwise, it is like trying to suck the coke out of the sealed pop bottle--you'll get some, but no where near the optimum flow.

Another pressure depletion problem can occur when pressures drop to what is known at the 'bubble point' for the reservoir fluids.

The theory: Once a reservoir reaches bubble point (the temperature/pressure where gas bubbles out of the liquids), natural gas can come out of solution in the reservoir, effectively blocking liquid flow through pore throats with bubbles. Pore throats are the paces which connect the pores, often smaller or complex connections.

If the CO2 can be used to restore reservoir pressure, the bubbles can be forced back into solution, the pore throats relieved of obstruction, and remaining liquids recovered--enhanced production of oil, or water, or both.

A lot depends on the variables present in the field, reservoir pressure, rock type, pore geometry, permeability, structural and stratigraphic controls, to name a few.

[ckilmer]

A lot depends on the variables present in the field, reservoir pressure, rock type, pore geometry, permeability, structural and stratigraphic controls, to name a few

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Can petroleum geologists pretty much tell in advance as to whether CO2 injection will work? Such that without doing actual CO2 injection they can run tests on 20 aged fields and determine which one is optimal for C02 injection.

The article claims that the old wells will at their peak enjoy a 30 fold increase in oil production as a result of CO2 injection. This number seems so high that there must be a catch. Maybe it is too overhyped. But on the other hand the cost of CO2 may be so high that you need a 30 fold increase in oil production to justify the added expense. Or is it the case that oil fields that will yield 30 fold increases as a result of Co2 injection are very rare birds indeed and the oil geologists have to do considerable expensive testing to find even one. The costs of finding the one jewel in the crown are so high that you need a 30 fold increase in production to justify the cost.

I’m just trying to understand here how to weigh the claims of the author that the oil field will enjoy a 30 fold increase in oil production at its peak as a consequence of CO2 injection as it appears only a certain percentage of oil wells are eligible for these flow rates byo CO2 injection.

For example, what percentage of wells are eligible for these flow rates would you hazard to say. Or is this a function of the oil fields so that in Eagle Ford maybe 5% of already fracked oil wells will yield high flow rates with CO2 injection but in the Permian Basin maybe 10% of already fracked oil wells will yield high flow rates with CO2 injection. And of already fracked wells in the Bakken — maybe only one percent will yield high flow rates with CO2 injection. I don’t know what the percentages actually are. I’m just making the numbers up to illustrate the question.

[American Constitutionalist]

I wonder if Dupont could come up with some chemical that acts like carbon dioxide when you need it, turns to bubbles, but when you either need to extract it it turns into either a solvent or harmless water ?