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.
Open hole (and cased hole) logs can provide data which give a reasonable estimate of oil saturation, but there are variables there which can enhance the apparent oil saturation or even mask it, so that approach without drill stem test or production water data from the formation has its possible problems as well.
The more information, the better.
No method is perfect, there is only a body of information which, properly interpreted, indicates increasing or decreasing probability of production.
There is a danger in assuming that the porosity in any given reservoir remains constant over a larger area (primarily because it usually doesn't) but the attempt is to get baseline data which will allow an estimate of maximum amount of oil present, a minimum amount of oil present, and from that total recoverable oil depends on how efficiently that oil can be recovered.
In the early Bakken wells (Elm Coulee), for instance, the estimated likely recoverable oil was a small fraction of the oil estimated to be in the formation--something on the order of <5%, because of the low permeability of the rock. Not long after that, recoveries for individual wells had eclipsed that number, reached 10% of the estimated oil in place, and were continuing to produce.
Knowing the production history of a field can help with the estimates of what the recovery should be, and what should enhance it. The latter can get pretty wrapped up in the mineralogy of the formation, the pore fluids, and fluid dynamics.
Now we're getting complicated, but was the early production mostly gas? Did the reservoir pressures decline with gas production to the point wells went on pump quickly (no longer flowing to the surface)? Did the wells seem to 'nail up' when the reservoir pressure dropped below a certain pressure?
Did core data indicate there should have been a lot more oil recovered?
All of these bits of information will indicate a probability that production can be enhanced and that there is more oil to recover--sometimes a lot more, but they do not guarantee it can be recovered by any specific means--or at all, just that it should be there.
Note that this will not apply to every oilfield--no two are exactly alike and while some will respond to this sort of enhanced recovery, many will not, sometimes because the initial production strategies were spot on and maximized the recovery.
Most of the targets for this sort of enhanced recovery are fields drilled with vertical wells.
Although converting every other well in a series of parallel laterals might cause enhanced production in a horizontally drilled field, I know so far of no one who has done so in North America.
The evaluation of potential would have to be carried out on a case-by-case basis, as the variables of lithology, pore geometry, geological structure, fluid content, reservoir continuity, and production history all factor in.
“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.”
Petroleum Geologists cannot do this. It is why Petroleum Engineers are hired. They understand the way hydrocarbon liquids and gases as well as other gases and fluids move through a reservoir.
Basically, lab testing of the extracted fluids can discern its theoretical applicability. For CO2, the tests mainly discern whether the injection can sustain miscibility of CO2 into the oil. Miscibility means the ability of CO2 to become absorbed into the hydrocarbons at reservoir temperatures and pressure. Just like Smokin Joe’s analogy on earlier post.
after that, there is the practical matter of whether it will work in the field in pilot testing to potentially be commercial. This entails understanding of the geology and a whole lot of other factors.