<p>S.G. is specific gravity - density relative to the density of some other material - which in this case is water - the dominant pore fluid in terrestrial rocks, (On Titan, the relevant comparison fluid might be liquid methane.)</p>
<p>As you say, this &quot;volumetric consistency&quot; idea is &quot;naive&quot;. It really does depend on what the chemical state of the originally extracted carbon was. Methane has a different proportion of carbon (12-16ths = 0.75, for the dominant isotopes) to say a decane (in the middle range for a diesel ; 120-142nds = 0.85) or a toluene (84-92nds = 0.91).</p>
<p>At low pressures - in the undergraduate lab - you can approximate that the number of molecules of any two gases in equal volumes are equal. That's the ideal gas law. And as your undergraduate chemistry course goes through, you'll derive the ideal gas laws from raw theory, assuming molecules of negligible volume and bouncing off each other elasticly.</p>
<p>Unfortunately, when the pressure is increased, the volume (and shape, and charge distribution) of the individual molecules really starts to matter ; also the interactions between the molecules starts to become significant. Bluntly, no real gases follow ideal gas laws at high pressure, because the assumptions of the ideal gas laws aren't met.
Which leaves the much more complex question of what empirical laws do the pressure and density (volume per unit mass / number of molecules) of the gas follow. And that is different for every gas, and for every <em>combination</em> of gases.</p>
<p>Personally, I've never even attempted to calculate such a &quot;volumetric consistency&quot; parameter, because I can't see the value to it.</p>
<p>If you want to do such a calculation yourself, you'll need the Van Der Waals parameters for the gases you're trying to compare (Van der Walls worked out the next-better approximation to explain gas behaviour ; to get better than that, you need to measure your particular gas at hundreds of pressures and temperatures.) <strong>If</strong> those values have <strong>ever</strong> been measured and published. (Companies may have that data, if processing gasses is their business, but I doubt it - they'd be much more interested in managing reactions to control the <strong>pressure</strong> in their pipework rather than the mass flow rates - it's excess pressure that ruptures pipes, kills staff and destroys refineries. Regardless, their empirical &quot;gas tables&quot; may well be commercially confidential. Enjoy asking.)</p>
<p>If you're comparing liquid hydrocarbons with compressed CO2, the only way I suspect that you're going to approach some sort of &quot;1g C in for 1g C out&quot; parity is where you've got rapid mineralisation. Which means injecting your CO2 below the water surface (strictly, oil-water or gas-water contact) so it bubbles up through the &quot;water leg&quot;, <strong>and</strong> for the water to have sufficient cations (specifically calcium or magnesium) to precipitate the CO2 as carbonate minerals very rapidly (months to years, not years to decades).</p>
<p>But I'm still struggling to understand <em>why</em> calculate this parameter.</p>
<blockquote>
<p>Is EOR performed on nat. gas wells?</p>
</blockquote>
<p>&quot;EOR&quot; stands (in the oilfield) for &quot;Enhanced Oil Recovery&quot;. Natural gas wells produce natural gas - methane, several % ethane, sometimes a few % of &quot;condensate&quot; (propane and butanes) ; variable amounts of CO2 are common (we'll come back to that in a bit). There is no oil to enhance the recovery of. But whether a well is &quot;gas&quot; or oil&quot; is a moveable feast.</p>
<p>Some &quot;natural gas&quot; wells and fields have a gas mix that has migrated thousands of metres vertically and maybe 10s of kilometres (sub-)horizontally (along particular permeable rock beds). That process very <em>effectively</em> separates the gases (with low viscosity) from the liquid (under underground conditions of pressure and temperature) components - &quot;higher&quot; hydrocarbons (larger number of carbon atoms per molecule - 5, 6, upwards into the low 20s, above which you're into low-mobility &quot;tars&quot;) so you get a natural gas with only a few % by volume (say, 25% by weight) of &quot;condensate&quot;.</p>
<p>But at the other end, in &quot;oil wells&quot;, it isn't at all so simple. If you're looking at <em>oil</em> generation from a source rock, it will almost always be generated along with large volumes of the &quot;lower&quot; hydrocarbons (methane - &quot;C1&quot;, ethane - &quot;C2&quot;, propane - &quot;C3&quot;, butanes - different shapes of &quot;C4&quot; molecules, some pentanes, even more variable than the butanes, and only gases at surface in the tropics), and these will be dissolved in the &quot;oil&quot;, stably for geological time - at <em>underground</em> conditions of temperature and pressure.</p>
<p>But as you bring the &quot;oil&quot; to surface, it depressurises and it cools in a matter of minutes. Which leads to the &quot;lower&quot; hydrocarbons coming out of solution, forming bubbles. Those bubbles make it <em>very</em> difficult to pump, and rapidly erode the valve gear, pipe bends, chokes, etc (and for governments, this &quot;multi-phase flow&quot; is more difficult to measure - and so difficult to tax). Normally, the flow rates (and so pressures and temperatures throughout the production string, from reservoir to surface) are managed to prevent formation of bubbles. Which is a <em>very</em> empirical thing - people don't seriously try to predict it in exploring for new fields, but measure it when they have a discovery well - with <em>that</em> field's unique mixture of hydrocarbons - to test.</p>
<p>Then, at surface, the produced fluids are depressurised in a piece of equipment called a &quot;separator&quot;, where the liquids go off into one set of processing equipment and eventual sale as &quot;oil&quot;, while the gases go off to be treated separately.</p>
<p>Sometimes the gas is just flared off - which nobody likes, but can be cheaper than doing anything else with it. <em>(Don't confuse this production flaring with the safety flares most production platforms carry - these are kept lit so that, in the event of a major problem in the equipment, the wells can be shut in, and the thousands of tonnes of flammable material in the surface pipework can be pumped into the flare and burned off, reducing the stresses on the pipework while the other problem is dealt with. <em>Those</em> flares save lives ; production flaring just saves money.)</em></p>
<p>But other times ... well, do you have a separate pipeline for putting the gas into, and sending it to market? Is there enough gas to justify the several billion dollars that <em>another</em> pipeline may cost? (It is taken as read that the oil pipeline (or tankers) is worth the effort ; otherwise you'd never have gone past the discovery well.)</p>
<p>No?</p>
<p>Well, one option is to <em>re-inject</em> the gas back into the reservoir, to restore (some) of the pressure lost by the reservoir as the oil was drained to surface. This may (if you get it right ; much experimentation in the labs, producing highly confidential pressure- temperature- bubble point data for this <em>specific</em> oil composition ; I refer you back to where I wished you enjoyment on getting gas &quot;equation of state&quot; data from companies in this business. This is <em>valuable</em> data.) also help you control the bubble behaviour in your producing wells, because <em>that</em> changes as the confining pressure (from below) changes.</p>
<p>Do you start to see now why the &quot;volumetric consistency&quot; concept is very ... naive? Don't worry, there are more considerations. (Note : I'm not a reservoir engineer, just a geologist. I just find the stuff. <b>They</b> can then need half a decade to work out (and experiment) how to optimally exploit a discovery after I've done my job and moved onto the next exploration site.
Then the  reservoir engineers can put the <em>design</em> of the production platform out to tender.)</p>
<p>Another option (further complicating the &quot;volumetric consistency&quot; concept) which is not mutually exclusive with the &quot;gas re-injection&quot; described above, is to burn some of the &quot;produced&quot; gas in the rig's power plant. (When I worked on production platforms, the power plant of choice was a <a href="https://en.wikipedia.org/wiki/Rolls-Royce_RB211#Industrial_RB211" rel="nofollow noreferrer">RB-211 engine</a>, as used on Concorde ; change the fuel spray nozzles and they will run for 30 years on &quot;wet&quot; natural gas perfectly happily.) Inject that exhaust gas (78% N2, 21% CO2, 1% Ar - maybe diluted with air) into the reservoir, again to manage the reservoir pressure.</p>
<p>How to incorporate that CO2 into a &quot;volumetric consistency&quot; concept ... ?</p>
<p>Then there is the entire topic of waterflooding - to flush the hydrocarbon liquids from the &quot;water injector&quot; wells (drilled a good few dozen of those myself) around the margins of the field towards &quot;producer&quot; wells normally near the centre of the field structure.</p>
<p>How to incorporate <em>those</em> EOR technique (where the water going down isn't even volumetrically counted beyond surface pressure and pump running hours) into calculating a &quot;volumetric consistency&quot; ? ... Well I'm not the one interested in the concept.</p>
<p>(Some people think &quot;EOR&quot; is a new thing. It has been a subject of experimentation since the 1920s, if not earlier.)</p>
<p>Remember the &quot;co-produced gas&quot; that bubbled out of the oil in the &quot;separator&quot;? And how it went back &quot;down the hole&quot;, for pressure support? Well, once you've squeezed all the oil you can out of a field (30~50% of the oil in the reservoir is a <em>really</em> good extraction rate!), and you've no more oil coming out of the ground to put into your expensive pipeline. Wouldn't it be wonderful if you could then extract that gas from the reservoir, and put that into the pipeline. After, of course, building a gas refinery at the shore end? Well, that was <em>exactly</em> the strategy being implemented on one of the UK North Sea's biggest oilfields (the Brent ; drilled a couple of dozen wells there, over the years) when I moved out of North Sea operations. I expect a lot of other fields have been following the same strategy.</p>
<p>Essentially, your wells turn from &quot;oil&quot; wells to &quot;gas&quot; wells, with a relatively minor &quot;workover&quot; changing in-hole pipes, valves and control lines. (<strong>Every</strong> well has multiple workovers through it's life - if for no reason other than the water co-produced with the oil normally leaves &quot;scale&quot; deposits, which eventually make valves leak. Leaking valves is not good, in an expensively fatal sense of &quot;not good&quot;.)</p>
<p>How to include that in your &quot;volumetric consistency&quot; calculation ?</p>
<p>I've forgotten something ... Oh yes, <a href="https://en.wikipedia.org/wiki/Sleipner_gas_field#Carbon_capture_and_storage_project" rel="nofollow noreferrer">Sleipnir</a>, and why you wouldn't be restricted to injecting into the <strong>original</strong> oil-producing horizons.</p>
<p>Remember when I said you can have CO2 as a component of natural gas - as it is produced? The Sleipnir gas field's product initially contained about 9% CO2 (nothing terribly unusual about that). So the platform was built with standard CO2 scrubbing equipment. Which all worked swimmingly until the Norwegian government <strong>chose</strong>  to impose a tax on those CO2 emissions. So the bean-counters and process-plant engineers came up with a scheme to avoid that tax - don't vent the CO2 to air, pump it underground! They had to re-jig the surface plant a little, and workover the wells. But it was worth the effort.</p>
<p>Now - this is the important bit - the formation into which the CO2 is injected - the &quot;Utsira Sands&quot; is around 1000m shallower than the reservoir formation from which the gas was originally extracted (&quot;Andrew&quot;  or &quot;Forties&quot; Sands ; the names change by year, country and company). Shallower depth means lower pressure, means smaller &amp; cheaper pumps means lower operating costs.</p>
<p>TTBOMK, Sleipnir is the only significant CCS scheme in the world. It's the product of a unique set of circumstances.</p>
<p>But the general point still applies : in the event of designing a &quot;back-fill&quot; CCS project, to re-use an existing oil (or gas) field, you'd start with injecting CO2 into the <em>deepest</em> reservoir section. (Did I mention that multiple-level oilfields, and even multiple-level oil wells, are nothing unusual? No? Well that's another complication for &quot;volumetric consistency&quot;.) When that is &quot;full&quot; (a complex question in itself ; amongst other things, how fast the CO2 mineralises to solid carbonate minerals is <strong>really</strong> important), you pump cement across the well(s) reservoir section, pressure test it (yes, we did know to do that <strong>decades</strong> before the Deepwater Horizon ; no, I don't understand why BP's staff did what they did), put a second cement plug over the top of that, then (this is the important bit) work the well over to inject CO2 into the <em>next</em> suitable permeable formation in well, going upwards.
Lather, rinse and repeat, until you're at the highest suitable formation in the well.</p>
<p>You can have multiple permeable sections in one well. Actually, in one field. [Footnote without link.] And since most of those sections have never produced any hydrocarbons (at least, not yet), how to incorporate that into a &quot;volumetric consistency&quot; calculation becomes a very thorny problem.</p>
<p>A career of drilling experience tells me that a real-world CCS project will work in the same way. I can't think of any reason at all to not do it that way.</p>
<p>Also, given two &quot;depleted&quot; oilfields with equally suitable surface equipment, the one with <em>more</em> separate intervals of permeable injectable formations will be the one to choose to work-over because you get more CO2 storage for the same investment of energy. Which is what it is all about really.</p>
<p>Personally, I wouldn't bother even trying to calculate a &quot;volumetric consistency&quot; parameter.
The real world of oilfields is too complex for that.</p>
<p>[Footnote] You can also get &quot;stacked&quot; oilfields in the same way that you can get - and frequently do get - &quot;stacked&quot; sets of permeable non-reservoir intervals. I've done 5 or 6 exploration wells on different structures (in different countries) where we <em>know</em> (from seismic data) that we have gas- and oil- containing sequences at different levels in the ground (as a geologist, I have to make sure the higher-frequency sample collection, and the more detailed petrophysical assessment are done on <strong>all</strong> hydrocarbon-containing sections (that's what my contracts say!), not just the ones expected in the pre-drilling plans).</p>
<p>Because the pipework for higher-pressure production is more expensive than for lower-pressure production, almost(!) always the exploitation sequence is from bottom (deepest, highest pressure) to top (shallowest, lowest pressure).</p>

CC BY-SA 4.0
2024-10-28T13:51:38.070Z
Really appreciate the effort you put into this elaborate answer! The interest in "volumetric consistency" comes from the gas and oil industry's promotion of the CCS concept and evaluating the plausibility of this being unrealistic greenwashing or not. The inspection of volumetric consistency comes from the fear that in reality, IF IPCC emission targets are not treated with contempt or neglected, the fossil fuel industry would have to build additional expensive CCS installations on geological formations where no fossil fuel extraction can or is to be done.
5th decile
CC BY-SA 4.0
2024-10-28T13:55:39.173Z
If such a global industry configuration were actually implemented, maybe it would be an unprofitable one. But so the fear is that the industry cunningly and disingenuously uses CCS rhetoric to get more allowances for profitable fossil fuel extraction TODAY and TOMORROW it reneges on its promise to build the additional expensive CCS installations.
5th decile
CC BY-SA 4.0
2024-10-15T19:21:11.207Z
2024-10-15T19:21:11.207Z
Rockdoctor
<blockquote>
<p>(a priori one might think not, but CO2 compress into liquid state relatively easily, or mineralize into carbonate, so...?)</p>
</blockquote>
<p>What's the critical temperature for CO2 (above which it doesn't have a liquid phase, just gases of increasing density, until it condenses into a solid)? Wiki tells me &quot;304 K (31 °C)&quot;. So in any realistic geological scenario, CO2 isn't going to liquify.</p>
<p>But your point about it mineralising into carbonate is certainly important. I've had to drill through sandstones into which production platform engine fumes and CO2 &quot;washed&quot; from produced gas had been injected for decades (we were exploring for a proposed deeper level of reservoirs), and the sandstones had up to 15% w/w carbonate (calcium carbonate, from the speed of reaction) which was simply not mentioned when the exploration and appraisal wells were drilled. That mineralisation obviously depends on the pore fluids having sufficient cations floating around to precipitate as carbonates, but that didn't seem to be a big problem.</p>
<p>That said ... I'm not sure quite what you mean by &quot;volumetrically self-consistent&quot;. It's going to depend quite critically on the mass-density of the originally produced hydrocarbons, and that can vary by a factor of &quot;several&quot;, between a heavy oil leg (pressure gradient indicating a S.G. order of 0.85) versus a methane (natural gas) leg (S.G. below 0.4 (0.3 or lower in shallow wells).</p>
<p>I'm not entirely sure you would expect it to be &quot;volumetrically self consistent&quot;, because you're very likely changing the density of the materials in consideration, and even more likely, the pressure they're stored under. And that's before you get involved in mineralising the CO2.</p>
<p>Maybe your idea needs closer specification.</p>

CC BY-SA 4.0
2024-10-07T10:08:57.470Z
Thanks for the answer! As an answer to yr first paragraph: for the sake of having a benchmark I consulted an online table and found for P=200 bar, T=30°C a CO2 density of 890 kg / m³. Thank you fr yr 2nd paragraph. Concerning yr 3rd paragraph: "volumetrically self-consistent" was explained in the question. It means a naive practical notion of the type "you can get as much C in as you got C out". In terms of "affordable IPPC-consistent pathways" this seems a critical question to me. What do you mean with the shorthand S.G. in that paragraph? Is EOR performed on nat. gas wells?
5th decile
CC BY-SA 4.0
2024-10-06T21:23:04.510Z
2024-10-06T21:23:04.510Z
Rockdoctor
<p>In the latest <a href="https://en.wikipedia.org/wiki/2023_United_Nations_Climate_Change_Conference" rel="nofollow noreferrer">COP</a> and also more broadly elsewhere, <a href="https://en.wikipedia.org/wiki/Carbon_capture_and_storage" rel="nofollow noreferrer">CCS</a> is heavily promoted as a method to prevent too much introduction of CO2 into the atmosphere / fast carbon cycle.</p>
<p>That brings about understandable criticism. One line of attack of the criticisms is that future CCS will most naturally be implemented in the form of Enhanced Oil Recovery (EOR projects were already the most successful implementations of CCS in the past). The criticisms quickly skip to the conclusion that the extra oil recovered from an oil well, because of the implementation of a EOR scheme, will undo the climate savings obtained from the CCS. To me, this begs the question: can an average oil well sequester as much carbon in the form of CO2 as the amount of carbon extracted from it in the form of crude oil?</p>
<p>(a priori one might think not, but CO2 compress into liquid state relatively easily, or mineralize into carbonate, so...?)</p>

<geochemistry><co2><carbon-cycle><carbon-capture>
Is Enhanced Oil Recovery (EOR) volumetrically self-consistent?
5th decile
# Is Enhanced Oil Recovery (EOR) volumetrically self-consistent?

(Asked by: username_0 on 2024-10-04)

In the latest [COP](https://en.wikipedia.org/wiki/2023_United_Nations_Climate_Change_Conference) and also more broadly elsewhere, [CCS](https://en.wikipedia.org/wiki/Carbon_capture_and_storage) is heavily promoted as a method to prevent too much introduction of CO2 into the atmosphere / fast carbon cycle.

That brings about understandable criticism. One line of attack of the criticisms is that future CCS will most naturally be implemented in the form of Enhanced Oil Recovery (EOR projects were already the most successful implementations of CCS in the past). The criticisms quickly skip to the conclusion that the extra oil recovered from an oil well, because of the implementation of a EOR scheme, will undo the climate savings obtained from the CCS. To me, this begs the question: can an average oil well sequester as much carbon in the form of CO2 as the amount of carbon extracted from it in the form of crude oil?

(a priori one might think not, but CO2 compress into liquid state relatively easily, or mineralize into carbonate, so...?)

**Tags:** geochemistry, co2, carbon-cycle, carbon-capture


---

## 2 answers

### Answer by username_1 on 2024-10-15. Score: 1

S.G. is specific gravity - density relative to the density of some other material - which in this case is water - the dominant pore fluid in terrestrial rocks, (On Titan, the relevant comparison fluid might be liquid methane.)

As you say, this "volumetric consistency" idea is "naive". It really does depend on what the chemical state of the originally extracted carbon was. Methane has a different proportion of carbon (12-16ths = 0.75, for the dominant isotopes) to say a decane (in the middle range for a diesel ; 120-142nds = 0.85) or a toluene (84-92nds = 0.91).

At low pressures - in the undergraduate lab - you can approximate that the number of molecules of any two gases in equal volumes are equal. That's the ideal gas law. And as your undergraduate chemistry course goes through, you'll derive the ideal gas laws from raw theory, assuming molecules of negligible volume and bouncing off each other elasticly.

Unfortunately, when the pressure is increased, the volume (and shape, and charge distribution) of the individual molecules really starts to matter ; also the interactions between the molecules starts to become significant. Bluntly, no real gases follow ideal gas laws at high pressure, because the assumptions of the ideal gas laws aren't met.
Which leaves the much more complex question of what empirical laws do the pressure and density (volume per unit mass / number of molecules) of the gas follow. And that is different for every gas, and for every *combination* of gases.

Personally, I've never even attempted to calculate such a "volumetric consistency" parameter, because I can't see the value to it.

If you want to do such a calculation yourself, you'll need the Van Der Waals parameters for the gases you're trying to compare (Van der Walls worked out the next-better approximation to explain gas behaviour ; to get better than that, you need to measure your particular gas at hundreds of pressures and temperatures.) **If** those values have **ever** been measured and published. (Companies may have that data, if processing gasses is their business, but I doubt it - they'd be much more interested in managing reactions to control the **pressure** in their pipework rather than the mass flow rates - it's excess pressure that ruptures pipes, kills staff and destroys refineries. Regardless, their empirical "gas tables" may well be commercially confidential. Enjoy asking.)

If you're comparing liquid hydrocarbons with compressed CO2, the only way I suspect that you're going to approach some sort of "1g C in for 1g C out" parity is where you've got rapid mineralisation. Which means injecting your CO2 below the water surface (strictly, oil-water or gas-water contact) so it bubbles up through the "water leg", **and** for the water to have sufficient cations (specifically calcium or magnesium) to precipitate the CO2 as carbonate minerals very rapidly (months to years, not years to decades).

But I'm still struggling to understand *why* calculate this parameter.

> Is EOR performed on nat. gas wells?

"EOR" stands (in the oilfield) for "Enhanced Oil Recovery". Natural gas wells produce natural gas - methane, several % ethane, sometimes a few % of "condensate" (propane and butanes) ; variable amounts of CO2 are common (we'll come back to that in a bit). There is no oil to enhance the recovery of. But whether a well is "gas" or oil" is a moveable feast.

Some "natural gas" wells and fields have a gas mix that has migrated thousands of metres vertically and maybe 10s of kilometres (sub-)horizontally (along particular permeable rock beds). That process very *effectively* separates the gases (with low viscosity) from the liquid (under underground conditions of pressure and temperature) components - "higher" hydrocarbons (larger number of carbon atoms per molecule - 5, 6, upwards into the low 20s, above which you're into low-mobility "tars") so you get a natural gas with only a few % by volume (say, 25% by weight) of "condensate".

But at the other end, in "oil wells", it isn't at all so simple. If you're looking at *oil* generation from a source rock, it will almost always be generated along with large volumes of the "lower" hydrocarbons (methane - "C1", ethane - "C2", propane - "C3", butanes - different shapes of "C4" molecules, some pentanes, even more variable than the butanes, and only gases at surface in the tropics), and these will be dissolved in the "oil", stably for geological time - at *underground* conditions of temperature and pressure.

But as you bring the "oil" to surface, it depressurises and it cools in a matter of minutes. Which leads to the "lower" hydrocarbons coming out of solution, forming bubbles. Those bubbles make it *very* difficult to pump, and rapidly erode the valve gear, pipe bends, chokes, etc (and for governments, this "multi-phase flow" is more difficult to measure - and so difficult to tax). Normally, the flow rates (and so pressures and temperatures throughout the production string, from reservoir to surface) are managed to prevent formation of bubbles. Which is a *very* empirical thing - people don't seriously try to predict it in exploring for new fields, but measure it when they have a discovery well - with *that* field's unique mixture of hydrocarbons - to test.

Then, at surface, the produced fluids are depressurised in a piece of equipment called a "separator", where the liquids go off into one set of processing equipment and eventual sale as "oil", while the gases go off to be treated separately.

Sometimes the gas is just flared off - which nobody likes, but can be cheaper than doing anything else with it. *(Don't confuse this production flaring with the safety flares most production platforms carry - these are kept lit so that, in the event of a major problem in the equipment, the wells can be shut in, and the thousands of tonnes of flammable material in the surface pipework can be pumped into the flare and burned off, reducing the stresses on the pipework while the other problem is dealt with. *Those* flares save lives ; production flaring just saves money.)*

But other times ... well, do you have a separate pipeline for putting the gas into, and sending it to market? Is there enough gas to justify the several billion dollars that *another* pipeline may cost? (It is taken as read that the oil pipeline (or tankers) is worth the effort ; otherwise you'd never have gone past the discovery well.)

No?

Well, one option is to *re-inject* the gas back into the reservoir, to restore (some) of the pressure lost by the reservoir as the oil was drained to surface. This may (if you get it right ; much experimentation in the labs, producing highly confidential pressure- temperature- bubble point data for this *specific* oil composition ; I refer you back to where I wished you enjoyment on getting gas "equation of state" data from companies in this business. This is *valuable* data.) also help you control the bubble behaviour in your producing wells, because *that* changes as the confining pressure (from below) changes.

Do you start to see now why the "volumetric consistency" concept is very ... naive? Don't worry, there are more considerations. (Note : I'm not a reservoir engineer, just a geologist. I just find the stuff. **They** can then need half a decade to work out (and experiment) how to optimally exploit a discovery after I've done my job and moved onto the next exploration site.
Then the reservoir engineers can put the *design* of the production platform out to tender.)

Another option (further complicating the "volumetric consistency" concept) which is not mutually exclusive with the "gas re-injection" described above, is to burn some of the "produced" gas in the rig's power plant. (When I worked on production platforms, the power plant of choice was a [RB-211 engine](https://en.wikipedia.org/wiki/Rolls-Royce_RB211#Industrial_RB211), as used on Concorde ; change the fuel spray nozzles and they will run for 30 years on "wet" natural gas perfectly happily.) Inject that exhaust gas (78% N2, 21% CO2, 1% Ar - maybe diluted with air) into the reservoir, again to manage the reservoir pressure.

How to incorporate that CO2 into a "volumetric consistency" concept ... ?

Then there is the entire topic of waterflooding - to flush the hydrocarbon liquids from the "water injector" wells (drilled a good few dozen of those myself) around the margins of the field towards "producer" wells normally near the centre of the field structure.

How to incorporate *those* EOR technique (where the water going down isn't even volumetrically counted beyond surface pressure and pump running hours) into calculating a "volumetric consistency" ? ... Well I'm not the one interested in the concept.

(Some people think "EOR" is a new thing. It has been a subject of experimentation since the 1920s, if not earlier.)

Remember the "co-produced gas" that bubbled out of the oil in the "separator"? And how it went back "down the hole", for pressure support? Well, once you've squeezed all the oil you can out of a field (30~50% of the oil in the reservoir is a *really* good extraction rate!), and you've no more oil coming out of the ground to put into your expensive pipeline. Wouldn't it be wonderful if you could then extract that gas from the reservoir, and put that into the pipeline. After, of course, building a gas refinery at the shore end? Well, that was *exactly* the strategy being implemented on one of the UK North Sea's biggest oilfields (the Brent ; drilled a couple of dozen wells there, over the years) when I moved out of North Sea operations. I expect a lot of other fields have been following the same strategy.

Essentially, your wells turn from "oil" wells to "gas" wells, with a relatively minor "workover" changing in-hole pipes, valves and control lines. (**Every** well has multiple workovers through it's life - if for no reason other than the water co-produced with the oil normally leaves "scale" deposits, which eventually make valves leak. Leaking valves is not good, in an expensively fatal sense of "not good".)

How to include that in your "volumetric consistency" calculation ?

I've forgotten something ... Oh yes, [Sleipnir](https://en.wikipedia.org/wiki/Sleipner_gas_field#Carbon_capture_and_storage_project), and why you wouldn't be restricted to injecting into the **original** oil-producing horizons.

Remember when I said you can have CO2 as a component of natural gas - as it is produced? The Sleipnir gas field's product initially contained about 9% CO2 (nothing terribly unusual about that). So the platform was built with standard CO2 scrubbing equipment. Which all worked swimmingly until the Norwegian government **chose** to impose a tax on those CO2 emissions. So the bean-counters and process-plant engineers came up with a scheme to avoid that tax - don't vent the CO2 to air, pump it underground! They had to re-jig the surface plant a little, and workover the wells. But it was worth the effort.

Now - this is the important bit - the formation into which the CO2 is injected - the "Utsira Sands" is around 1000m shallower than the reservoir formation from which the gas was originally extracted ("Andrew" or "Forties" Sands ; the names change by year, country and company). Shallower depth means lower pressure, means smaller & cheaper pumps means lower operating costs.

TTBOMK, Sleipnir is the only significant CCS scheme in the world. It's the product of a unique set of circumstances.

But the general point still applies : in the event of designing a "back-fill" CCS project, to re-use an existing oil (or gas) field, you'd start with injecting CO2 into the *deepest* reservoir section. (Did I mention that multiple-level oilfields, and even multiple-level oil wells, are nothing unusual? No? Well that's another complication for "volumetric consistency".) When that is "full" (a complex question in itself ; amongst other things, how fast the CO2 mineralises to solid carbonate minerals is **really** important), you pump cement across the well(s) reservoir section, pressure test it (yes, we did know to do that **decades** before the Deepwater Horizon ; no, I don't understand why BP's staff did what they did), put a second cement plug over the top of that, then (this is the important bit) work the well over to inject CO2 into the *next* suitable permeable formation in well, going upwards.
Lather, rinse and repeat, until you're at the highest suitable formation in the well.

You can have multiple permeable sections in one well. Actually, in one field. [Footnote without link.] And since most of those sections have never produced any hydrocarbons (at least, not yet), how to incorporate that into a "volumetric consistency" calculation becomes a very thorny problem.

A career of drilling experience tells me that a real-world CCS project will work in the same way. I can't think of any reason at all to not do it that way.

Also, given two "depleted" oilfields with equally suitable surface equipment, the one with *more* separate intervals of permeable injectable formations will be the one to choose to work-over because you get more CO2 storage for the same investment of energy. Which is what it is all about really.

Personally, I wouldn't bother even trying to calculate a "volumetric consistency" parameter.
The real world of oilfields is too complex for that.

[Footnote] You can also get "stacked" oilfields in the same way that you can get - and frequently do get - "stacked" sets of permeable non-reservoir intervals. I've done 5 or 6 exploration wells on different structures (in different countries) where we *know* (from seismic data) that we have gas- and oil- containing sequences at different levels in the ground (as a geologist, I have to make sure the higher-frequency sample collection, and the more detailed petrophysical assessment are done on **all** hydrocarbon-containing sections (that's what my contracts say!), not just the ones expected in the pre-drilling plans).

Because the pipework for higher-pressure production is more expensive than for lower-pressure production, almost(!) always the exploitation sequence is from bottom (deepest, highest pressure) to top (shallowest, lowest pressure).

> **Comments:**
> **username_0**: Really appreciate the effort you put into this elaborate answer! The interest in "volumetric consistency" comes from the gas and oil industry's promotion of the CCS concept and evaluating the plausibility of this being unrealistic greenwashing or not. The inspection of volumetric consistency comes from the fear that in reality, IF IPCC emission targets are not treated with contempt or neglected, the fossil fuel industry would have to build additional expensive CCS installations on geological formations where no fossil fuel extraction can or is to be done.  
> **username_0**: If such a global industry configuration were actually implemented, maybe it would be an unprofitable one. But so the fear is that the industry cunningly and disingenuously uses CCS rhetoric to get more allowances for profitable fossil fuel extraction TODAY and TOMORROW it reneges on its promise to build the additional expensive CCS installations.  

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### Answer by username_1 on 2024-10-06. Score: 0

> (a priori one might think not, but CO2 compress into liquid state relatively easily, or mineralize into carbonate, so...?)

What's the critical temperature for CO2 (above which it doesn't have a liquid phase, just gases of increasing density, until it condenses into a solid)? Wiki tells me "304 K (31 °C)". So in any realistic geological scenario, CO2 isn't going to liquify.

But your point about it mineralising into carbonate is certainly important. I've had to drill through sandstones into which production platform engine fumes and CO2 "washed" from produced gas had been injected for decades (we were exploring for a proposed deeper level of reservoirs), and the sandstones had up to 15% w/w carbonate (calcium carbonate, from the speed of reaction) which was simply not mentioned when the exploration and appraisal wells were drilled. That mineralisation obviously depends on the pore fluids having sufficient cations floating around to precipitate as carbonates, but that didn't seem to be a big problem.

That said ... I'm not sure quite what you mean by "volumetrically self-consistent". It's going to depend quite critically on the mass-density of the originally produced hydrocarbons, and that can vary by a factor of "several", between a heavy oil leg (pressure gradient indicating a S.G. order of 0.85) versus a methane (natural gas) leg (S.G. below 0.4 (0.3 or lower in shallow wells).

I'm not entirely sure you would expect it to be "volumetrically self consistent", because you're very likely changing the density of the materials in consideration, and even more likely, the pressure they're stored under. And that's before you get involved in mineralising the CO2.

Maybe your idea needs closer specification.

> **Comments:**
> **username_0**: Thanks for the answer! As an answer to yr first paragraph: for the sake of having a benchmark I consulted an online table and found for P=200 bar, T=30°C a CO2 density of 890 kg / m³. Thank you fr yr 2nd paragraph. Concerning yr 3rd paragraph: "volumetrically self-consistent" was explained in the question. It means a naive practical notion of the type "you can get as much C in as you got C out". In terms of "affordable IPPC-consistent pathways" this seems a critical question to me. What do you mean with the shorthand S.G. in that paragraph? Is EOR performed on nat. gas wells?  

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