Nobody Is Announcing New CO2 EOR Projects—Here Are Some Reasons To Consider One Anyway
A big jump in the tax incentives offered for putting CO2 in the ground, hopefully forever, has set off a mad rush to sequester CO2. But is that really the best option?
Well pads in the Permian Basin of Texas.
Source: Stephen Rassenfoss.
There are two ways to inject CO2 in the ground and make money. One is to put it into storage—hopefully forever. The other is to inject the gas for enhanced oil recovery (EOR), which leaves a lot of injected CO2 in the ground.
Vladimir Vikalo is an engineer who has done it both ways. When asked which he likes doing more, he answered, “I’m an old fashioned guy, I like making money.”
The senior staff engineer for Whitecap Resources explained that he preferred engineering projects that profitably added production from old fields, rather than getting paid to create and manage a CO2 waste disposal site.
The fact that he works for a Canadian company that operates a storage hub at Weyburn —which it says is the world’s largest—and is developing two more sites for CO2 sequestration shows he is open to going with the current cash flow, which is mostly moving into CO2 sequestration projects.
Talk about storage also loomed large at the recent CO2 Conference in Midland, Texas, where the agenda was so dominated by the topic that the conference organizers dedicated a day to presentations highlighting the pros and cons of storage vs. EOR—where operators that recycle the CO2 need to keep buying gas to make up for the CO2 that remains in the ground.
For now, the spending is on the storage side. EOR has suffered because carbon emissions have been driving an energy policy that provides larger incentives for storage. Also in the Permian, EOR has been in a deep funk since the shale boom took over a decade ago.
“Nobody is initiating CO2 EOR projects today because of the long-term nature of investment” compared to the quick payoff for drilling and fracturing horizontal wells, said Steve Melzer, a co-founder of the conference and owner of Melzer Consulting.
While EOR wells can steadily produce oil for many years after a shale well is played out, the ultimate payoff for EOR is subject to the vagaries of long-term oil prices.
In the US, the recent sharp increase in tax credits paid to those capturing CO2 from industrial waste streams has reinforced that trend by offering more money if the captured CO2 goes into storage—$85 per ton—than if it is used for EOR—$60 per ton. This has brought in new money.
“The incentives energized people who are really brand new to the game,” said Melzer, who is certain it is just not that simple.
“There is a huge void when it comes to laying out the advantages and disadvantages, and risks associated with deep saline storage,” he said.
Source: Michael Godec, Advanced Resources International.
Pros and Cons
To fill that void at the CO2 Conference, Michael Godec,a vice president at Advanced Resources International, offered a presentation contrasting the tradeoffs between storage and EOR.
Based on the tax incentive program, the choice looks obvious—the storage credit is $25 higher than the EOR credit. The downside of that is the income is all paid as the gas is injected, like a water disposal site. That revenue stops when the injection ends. But the risk of costly problems in the future lingers.
The credit paid for EOR is lower, based on both the amount paid per ton and the lower volume of gas stored in projects where the goal is to limit the gas used to the level offering a good return on the investment.
However, over time, an EOR project can generate income that narrows the initial credit gap. Doing so requires that those in charge pick the right reservoir and design and execute a profitable project. There is a limited supply of CO2, good geology, and talented professionals—many of whom are reaching retirement age.
Either CO2 injection option depends on careful reservoir evaluation to ensure the injected gas is contained at high pressure levels. Those doing CO2 EOR have a significant advantage when evaluating, planning, and permitting a project because they know the reservoir based on years of production and they are working with regulators with long experience judging if a formation is suitable for EOR.
“EOR can go a little more quickly because you have been operating the field,” Godec said. In contrast, injection experience with long-term sequestration is extremely limited.
As a result, the average review for the Class 2 permit required for EOR takes about 1 to 3 months, compared to from 1 to 3 years for a Class 6 permit for long-term storage, according to a slide in Godec’s presentation.
The time required for review of storage applications is longer and less certain because the regulatory system for it is under development. The flood of permit applications for storage could swamp federal regulators who have been struggling to reduce review times and also work through proposals from states to determine if they could regulate storage as well.
Also, many proposed storage sites are in saline aquifers which have rarely been drilled because there is nothing in them worth producing.
Source: Michael Godec, Advanced Resources International.
Tax Law of Capture
A petroleum engineer looking at Godec’s comparison chart may well prefer trying to make some money with EOR.
Those with subsurface experience know it is not easy to prove a reservoir has the seals above and below to provide “secure geologic storage,” to identify all the old wells to ensure they will not provide leak paths, and to predict how the plume of stored gas will grow in the ground, among other concerns.
It is not as if EOR has gone away. There are companies doing under-the-radar EOR projects. Riley Exploration Permian, a small independent, reported at the CO2 Conference on a project to develop a marginal conventional prospect using unconventional ideas, like horizontal wells drilled in a wine-rack formation and fracturing producing wells.
Those in the EOR business have long dreamed of the day when gas capture provides large supplies of cheap CO2. But that will require deals with those capturing the gas.
The US law gives the company capturing the CO2 the loudest voice in where it goes. Many of those are chemical makers with no desire to get into the oil business. They are likely to choose sequestration if it can cover the cost of installing a CO2 capture system and also pay third parties to transport and dispose of the CO2.
Those plans offer the added benefit of potentially increasing a company’s environmental ratings, which are increasingly important when dealing with lenders and the public. Disposal also opens the door to using hydrocarbons to create low-carbon products. Big oil companies may also favor storage for the same reasons.
All of which makes CO2 EOR a tough sell but in Melzer’s mind not an impossible one.
EOR project planners will need to emphasize the CO2 storage potential in these fields and put together creative deals where the rewards are shared by all the parties, including the suppliers, and risks are tightly managed.
The big reason: There are huge EOR targets out there. Melzer has long been an advocate for the residual oil zone in the Permian.
Significant oil production is possible with CO2 injection from the low concentrations of crude in these flooded carbonate formations that are as much as 300 ft thick and can hold a huge amount of CO2.
The tax credit paid for those doing EOR is based on the tons of injected CO2 that remain in the ground. That is roughly equivalent to the amount of gas purchased to maintain the level of gas injections. The actual accounting is more complex as explained by Michael Godec, a vice president at Advanced Resources International:
The injectors must make the case that they are storing the CO2, which is not as complicated as it may seem at first glance. It requires keeping track of the mass balance of what is injected, recycled, and any losses.
The losses are usually the documented and reported times that the electricity goes offline to the compressors, consequently requiring flaring of the recycle. A reason why it seems complicated is that the total injected volumes include the recycle (closed loop) volumes.
But the purchased volumes are the net volumes (gross being all the injected volumes) and that is what is stored, minus (hopefully) the small volumes lost at the surface.
Advanced Resources International has done some studies and even included the carbon that is burned in the form of the oil produced and the numbers are larger than 95% when the CO2 injection for flood is operated well.
What folks are thinking now, with the revenue stream from storage (or a discounted price of CO2), is that they will upgrade the recycle uptimes and build in redundancy on compressors to maintain everything online and the numbers will approach very closely the purchased CO2 volumes.
