Photo credit: Flickr/Melissa
Posted on 07/20/2014 1:42:44 PM PDT by ckilmer
July 20, 2014 | Comments (0)
Photo credit: Flickr/Melissa
It is estimated that there are 160 billion barrels of oil still trapped underneath this country in what are considered depleted oil fields. That's a tremendous amount of oil given that America uses about seven billion barrels of it each year. In fact, if we could only find the key to unlock this trapped oil we could extend fleeting our reserves by more than 22 years.
That's why it probably comes as a surprise to learn that we've already found the key we need to unlock this oil. That key is none other than discarded carbon dioxide, with the primary source of this practically prized greenhouse gas coming from none other than coal emissions. It's a stunning turn of events to say the least.
Cleaner coal and more oil, too
America has actually been flooding depleting oil fields with carbon dioxide since the 1970's. Most of the carbon dioxide used has come from naturally occurring sources. The problem is that carbon is costly as getting it from those sources to spent oil fields requires pipelines. But thanks to technological advances in carbon capture and storage we're beginning to see new investments that are directed to cleaning coal and using the captured carbon to produce more oil. It's this combination that has the potential to breathe new life into some of America's long dormant oil fields.
A positive forward was taken when NRG Energy (NYSE: NRG ) announced earlier this week that it began construction on a billion dollar retrofit to its East Texas coal-fired power plant. While the project is being underwritten in part by $167 million from the Department of Energy, NRG Energy sees it being self-liquidating as the carbon dioxide that is captured will be used to yield a 30-fold increase in oil production from an aging oil field NRG Energy also co-owns.
The reason production will surge is because carbon dioxide, which is injected into an oil reservoir, mixes with oil droplets that are left behind after initial production and expands the oil so that it can move through producing wells. The following slide shows how the oil recovery process works.
Source: Denbury Resources Investor Presentation (link opens a PDF)
NRG Energy expects this process will improve the production at its West Ranch oilfield from a meager 500 barrels of oil per day to 15,000 barrels of oil per day at its peak. Put another way, at current oil prices that field will go from producing about $18.2 million worth of oil each year to well over half a billion dollars of black gold per year.
Meanwhile, the project will also substantially clean up the carbon emissions of NRG Energy's coal plant. About half of the flue gas that would typically be emitted into the atmosphere will go into the carbon capture facility, which will remove all of the sulfur as well as capture about 90% of the carbon. Because of that it will remove the equivalent of the exhaust of 336,000 cars each year.
Small steps
NRG Energy isn't the only company seeking to use captured carbon to clean up coal and fuel oil production. Denbury Resources (NYSE: DNR ) is building its business completely around the enhanced oil recovery process. So far the company has produced over a hundred million barrels of oil through carbon flooding. However, it is investing to build out the necessary carbon dioxide transportation infrastructure to revive even more nearly dead oil fields.
While most of Denbury Resources investments have been to take naturally occurring carbon dioxide to these fields, the company is beginning to use more industrially produced and captured carbon in its Gulf Coast operations as noted on the slide below.
Source: Denbury Resources Investor Presentation (link opens a PDF)
As that slide points out, Denbury Resources currently has three projects either currently producing or pending start-up. The most important is the upcoming Mississippi Power project from Southern Company (NYSE: SO ) . The $5.2 billion power plant is the first large-scale plant in America that will transform coal into a gas, capture the carbon, and then sell it to Denbury Resources for enhanced oil recovery. If successful, Southern Company's plant should supply Denbury Resources with about 115 MMcf/d of carbon dioxide. Overall it is expected that the carbon captured from Southern Company's plant will be used to boost oil output by two million barrels per year.
Investor takeaway
There is an incredible amount of oil stranded in America in what are currently thought to be depleted oil reservoirs. But by using carbon dioxide captured by coal power generation, the energy industry will could breathe new life into these oil fields and revive production. It's a stunning turn of events that can provide Americans with cheap and cleaner coal-fired electricity as well as enough oil to get our nation off of OPEC's oil.
I realize this is not about carbon credits which I’m also opposed to but it would be sweet irony if the energy companies were able to get some of the scam credits from this. Here in California we have a program already in operation.
Oil and refrigerant will almost make an additive volume as they are the same molecular weight but the pressure stays the same. CO2 is compressed to dissolve into the soda.
It would be neat if they put some catalysts into the CO2 so they could make more oil. There was a guy making fuel out of garbage by heating it and boosting the pressure to over 600 pounds. They could make fuel right in the ground.
Bookmark.
It could be worse, the improper use of hydrogenated hydroxyl radicals will drown us all and make our booze tepid.
The CO2 dissolves in the water in the reservoir, much like the methane, ethane, butane, and propane dissolved in the oil. Increasing the pressure in the pore spaces by injecting the CO2 will cause Methane, ethane, propane, and butane to dissolve in the oil again, and the oil can move.
In a stratified reservoir, where the top part of the reservoir is rich in natural gas, the lower parts of the reservoir progressively richer in oil, then water farther down, producing the gas off the top lowers reservoir pressure, and there is nothing to push the oil out (the gas expands as the pressure drops, but for all practical purposes, the oil does not--it just gives up dissolved gas).
Injecting CO2 in the formerly gas rich upper part will increase the pressure down there and give something to push the oil out.
A lot depends on the geology of the field, the rock structure (folded, a dome, etc), and the type of rock involved as well.
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.
That is not the process. It is not expanding the oil, it is releasing more oil.
Denbury has talking about doing the same thing in Louisiana. I think at Delhi Field.
There are three major carbon dioxide accumulations in North America. One is north of Jackson, Mississippi. One is in northeastern New Mexico. The other is in southern Colorado. I believe tertiary recovery has been going on from those fields, primarily in the Permian Basin and Mississippi, since the 1970’s. The problem is that they are running out of CO2. This is talking about capturing the byproducts from the power plants. Now that I think about it, the deep Madden Field in Wyoming has a lot of CO2. Usually, it is a nuisance in natural gas fields and has to be removed before transmission.
That is not the process. It is not expanding the oil, it is releasing more oil.
To quote the article in the little green box at the bottom of the diagrams. “CO2 moves through the formation mixing with oil droplets, EXPANDING them and moving them to producing wells.”
In effect the CO2 is absorbed into the oil reducing its viscosity so it can flow easier.
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.
Okay, I see where the “expanding” thingy came from. It is in one of the text boxes in the graphic, and unfortunately, not exactly correct, imho.
Would not some older vertically-drilled fields regain productivity with horizontal drilling?
I'll stick my neck out, even and say the more stratigraphically complex the reservoir the more likely there can be significant improvements made in oil recovery. Existing well data can be used to map the structure in the area, and staying within a stratigraphic target is a matter of execution from there.
I have had the privilege of being able to use infield well data on a couple of wells and it made my job significantly easier.
Some of the early horizontal wells I worked were in a field with 160 acre spacing, and we cut a window in existing production casing to drill laterals out of the old wellbores.
This was in a field which had had production for over 30 years and many of the wells had declined to stripper status.
Our first 1500 ft. lateral took a well which had declined below 20 BOPD to 250 BOPD, we came back a year later and drilled another lateral at 90 degrees to the first (after production had declined to about 50 BOPD) and raised production to 200 BOPD and roughly 500 MCF of gas/day.
This was in the early '90s and proved two things:
First, even on a 160 acre spacing, there was plenty of oil left after thirty years...
and Second: the reservoir was anisotropic--that is, the properties in the reservoir were significantly different depending on which direction you drilled through it.
This was a carbonate (limestone) reservoir and proved out a couple of theories a few of us had with respect to carbonates.
The field was subsequently fairly extensively drilled horizontally, with many new wellbores drilled instead of using the 30 year-old wellbores.
CO2 miscible flood in optimal conditions can recover additional oil comprising around 11% of the original oil in place.
http://petrowiki.org/Miscible_flooding
The oil industry has been CO2 flooding oilfields since the mid-1970s.
The assertion of a 30 fold increase in oil production is a misleading and meaningless number. I am an officer in a public oil and gas production company. I see articles by this DeLillo all the time, and he is always making rash, brash and unsubstantiated assertions. DeLillo has a penchant for hyperbole and wildly erroneous information, that is often put into the public domain as “journalism” opining on relative values and upside in portfolio of certain oil and gas companies, in which his hedge fund controllers have taken either long or short positions. He does no basic research and is not an oil and gas production expert, nor is he a real energy analyst.
CO2 miscible flood in optimal conditions can recover additional oil comprising around 11% of the original oil in place.
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you understand that this statement is not out of variance with DeLillo statement that CO2 enhancement can deliver up to a 30 fold increase in well production.
Why?
Because “11% of the original oil IN PLACE.” is many orders of magnitude higher than commercially accessible oil. In the Baaken/Three Forks formation for example Continental has recently doubled their estimates of oil IN PLACE to over 900 billion barrels of which as much as 45 billion barrels is commercially accessible.
Now consider again your statement that “CO2 miscible flood in optimal conditions can recover additional oil comprising around 11% of the original oil IN PLACE.”
So you take 11% of 900 billion barrels and what is that? 95 billion barrels? suddenly you’re getting a number that looks like what DeLillo is talking about.
I could be completely wrong here. All I’m doing is following your logic.
Heck some of the biggest cheapest coal fields in the world are in north east wyoming. You could turn that coal into electricity and then use the CO2 for enhanced oil recovery in the neighborhood.
Heck some of the biggest cheapest coal fields in the world are in north east wyoming. You could turn that coal into electricity and then use the CO2 for enhanced oil recovery in the neighborhood.
Much of the Wyoming coal is shipped out on unit trains to be used to generate power. The other part of the equation for power generation is water supply.
The Great Plains Coal Gassification Project is one such, the CO2 is currently being pipelined to Canada for tertiary recovery efforts there. North Dakota has significant lignite reserves as well, and is an energy exporter.
Wyoming and Eastern Montana contain quite a bit of coal (and oilfields as well), so yes, the potential exists to recover CO2 and use it relatively locally for oil recovery enhancement.
The Great Plains Coal Gassification Project is one such, the CO2 is currently being pipelined to Canada for tertiary recovery efforts there. North Dakota has significant lignite reserves as well, and is an energy exporter.
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It may be that coal gassification is better than burning coal for electricity if the plant is sited in Montana, wyoming or ND. Why? It may be that natural gas transports better/cheaper/ via pipeline than electricity via power lines over long distances. I don’t know the details there.
“I would strongly caution anyone in this business that “carbon capture” is the pure invention of progressive government seeking ecological Utopia. As such, it grossly distorts the market price of the things its touches. If you are in this business, you are not serving your creditors or shareholders well unless and until you have a contingent plan for when (not if) the case for carbon capture collapses and the price of CO2 returns to a more truthful value.”
How true. I recall attending a presentation by Shell who drank the KoolAid years ago about carbon capture. Shell says it was a great thing for the environment, blah blah.
Truth is I found later on that their capturing effort increased capital costs on their large projects by 25%.
The presentation was a sales(or snow) job that was an attempt to convince everyone else in industry to do the same so Shell would stay competitive.
Needless to say, no one drank Shell’s Kool Aid.
“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.
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