GHG Reduction Technologies Monitor Vol. 9 No. 4
Visit Archives | Return to Issue
GHG Reduction Technologies Monitor
Article 9 of 13
March 17, 2014


By ExchangeMonitor

The following interview with Advanced Resources International President Vello Kuuskraa was conducted by ExchangeMonitor Publications President and Publisher Ed Helminski and GHG Monitor Reporter Karen Frantz.

To start things off, Vello, can you take us a little bit through the history and evolution of enhanced oil recovery and CO2 utilization?

ARI’s first enhanced oil recovery (EOR) study was back in 1975. It was done for the group that was set up by President Nixon to regulate oil prices. It was a unit within the Federal Energy Administration (FEA) that became the Department of Energy. The industry had been saying that the cost to produce oil is not all the same—we have old oil, we have new oil and we have higher cost oil from EOR. And so the purpose of our study was to better understand the topic of enhanced oil recovery and what its economics and resource potential might be. Based on our study and the subsequent FEA hearings, oil produced by EOR was released from price controls.

Then President Carter came in and deregulated oil prices, removing the financial incentives for EOR. So the question became, given the potential of enhanced oil recovery to improve domestic energy security, should the nation establish a research and technology program in enhanced oil recovery?  Based on this, the Energy Research and Development Administration (ERDA) came to me and said, we read your earlier report. Would you assemble a team of people and take a look at what a research and technology program might look like in enhanced oil recovery?  The scope of work included all forms of enhanced oil recovery—steam in-situ combustion, chemicals, as well as CO2. This study, published in 1977, set the foundation for the joint Federal/private industry R&D program for EOR, particularly for CO2-enhanced oil recovery. In those early days there was a lot of skepticism that CO2 could actually displace residual oil and significantly increase oil recovery.

A second concern was that CO2-EOR was not economic. The joint Federal/Private Industry R&D Program and its core flood studies, reservoir modeling and pilot field projects provided information that CO2-EOR actually did work and could be economically viable.

With rising oil prices and successful results from a handful of CO2-EOR field pilot tests, industry made major investments in CO2-EOR, including building high volume, long distance CO2 pipelines connecting natural sources of CO2 with oil fields in the Permian Basin. However, when oil prices crashed in 1982-‘83, the companies that had become interested in CO2-EOR—notably Shell, Amoco, Arco and Chevron—had a change in priorities and begun to exit the onshore U.S. oil business, moving offshore and overseas. Shell sold the Jackson Dome CO2 field and its Mississippi oil fields to Denbury. It sold its West Texas CO2 pipelines and supply to KinderMorgan. BP, who had acquired Amoco and ARCO, sold off CO2 supplies and CO2 projects in the Permian Basin to Occidental.

With the “big boys” gone, the market for CO2 supplies was limited and KinderMorgan’s CO2 pipelines were half-empty. So KinderMorgan started promoting the development of CO2-EOR by saying to producers, we’ll give you the CO2 if you give us a piece of the action. They also said, we’ll do your front-end reservoir engineering studies, particularly to help smaller producers get started. But they finally got tired of that and said, you know, let’s just buy the damn fields. They bought the SACROC and the Yates fields, plus a few others since then.

Where does Exxon Mobil fit in all this?

Exxon Mobil has a CO2-rich methane and helium reservoir on the LaBarge Platform of Western Wyoming. It was mostly venting the CO2 to produce the higher value methane and helium. Chevron took a little bit of the CO2 to their Rangely Field and Amoco purchased a portion of the CO2 for their EOR projects in Wyoming.  Then the state steps in and says, hey, wait a minute, this is a commodity, it has value and we want you to start getting serious about not wasting it. So Exxon began to capture the CO2 and started selling more of it to new EOR projects in the Rockies. With new supplies of CO2, now a second geological setting, the sandstone reservoirs of the Rockies, showed that CO2-EOR could be attractive in other settings beyond the carbonate reservoirs of the Permian Basin.

So what has restimulated the recent interest in CO2-EOR?

At Advanced Resources, with support from the DOE and National Energy Technology Laboratory (NETL), we began to analyze the potential of using and storing anthropogenic CO2 with EOR rather than just injecting the captured CO2 emissions in saline aquifers. The major hurdle we faced was the view that yes, it’s all very nice, but CO2-EOR is a small, niche opportunity. While we were claiming that CO2-EOR was a “Bridge to CO2 Sequestration,” others, believing that the opportunities for CO2 utilization by EOR were very small, called it a “Bridge to Nowhere.”

When did some in the industry start looking at anthropogenic CO2 as a potential commodity?

Well, some companies were already having that view. Chaparral had always looked at anthropogenic CO2 captured from ammonia, chemical plants and fertilizer plants as their future. But it’s a modest-size company.

The more favorable view of using and storing anthropogenic CO2 with enhanced oil recovery was stimulated by a conference at MIT held by Ernie Moniz and Scott Tinker. They invited a series of papers—I wrote one, Steve Melzer wrote another—that argued that CO2-EOR actually offered a large market for utilizing and storing CO2 with EOR. At this same conference, Steve Melzer introduced the concept of Residual Oil Zones (ROZ) and how CO2-EOR could be used to recover this oil resource while also storing CO2.

Can you explain a bit about ROZs?

What we call “conventional oil” is trapped in geological structures, with high concentration oil “floating” above a column of water. However, below the oil/water contact is much lower concentration oil called residual oil or ROZ. In the past, companies had drilled into the ROZ and discovered it was immobile, would not flow. As a result, they moved back into the higher concentration oil zone above the water/oil contact, into what we call the “the main pay zone.” However, Steve Melzer said, hey, I want to look at this deeper section with lower concentration oil. Melzer did the “ground breaking” investigation and now is “the father of the ROZ.”

In the paper you presented at the Midland Conference back in December, you estimated that oil in ROZs is quite large, on the order of 31 billion barrels below oil fields in the Permian Basin, another 11 billion barrels below oil fields in the Big Horn and Williston basins, plus a much larger volume of oil in the ROZ “fairways” surrounding these oil fields. What are you doing to quantify these projections?

We at Advanced Resources are currently working with Steve Melzer to address this very topic. He has obtained funding from Research Partnerships For Energy Security, a Section 999, Federal R&D program as well as from a [Department of Energy]/[National Energy Technology Laboratory] grant, through the University of Texas Permian Basin, to study the ROZ resource. One objective is to determine how much ROZ resource is in place below oil fields as well as in the ROZ “fairways” beyond the oil fields. 

In your paper, you are estimating a huge amount of oil could be obtained from these ROZs and associated fairways.

Based on preliminary work by our company and Steven Melzer in 2006, we estimated that 16 billion barrels of the 42 billion barrels underneath oil fields in the Permian, Big Horn and Williston basins could be technically recoverable. Given the extensive ROZ “fairways,” the resource in the fairways could be several times larger.

What is it going to take to refine your estimates and get more concrete numbers?

Well, in my view, this would be an ideal project for funding by the Department of Energy and NETL. Advanced Resources and Melzer Consulting would work jointly with the state geological associations  to more rigorously define how much ROZ resource is in-place and how much could be recoverable. Then industry could use this information to go after the portions of the resource that they deem are economically viable.

What would this mean for oil production in the U.S.?

In the U.S., except in the deep waters of the Gulf of Mexico, new oil discoveries have been few and far between. There are opportunities in Alaska but this will be costly and challenging. Then there is shale oil from the Bakken, Eagle Ford and the Permian basins that has helped boost U.S. oil production to new highs. Finally, there is CO2-enhanced oil recovery that would further add to domestic oil production, particularly after shale oil hits its peak.

Beyond oil production, you and Melzer contend that deploying EOR techniques using CO2 to recover oil from ROZs provides an answer to dealing with CO2 emissions—not just a small fraction, as was thought a few years ago, but a lot.

Correct. As I presented in my paper, CO2-EOR offers a large CO2 utilization and storage opportunity. With current CO2-EOR technology, the size of the economically viable CO2 utilization and storage opportunity is 15 billion metric tons (Gt) equal to 40 years of CO2 emissions captured from 126 one GW size coal-fired power plants. (The total U.S. coal-fired power plant capacity is slightly above 300 GWs.)  With “Next Generation” CO2-EOR technology, the CO2 utilization and storage opportunity doubles—to 28 Gt (231 one GW size coal-fired power plants).

With just the CO2-EOR projects already on the books, a billion metric tons of anthropogenic CO2 could be utilized and stored with CO2-EOR in the next seven years, with increasing volumes after that.

And sequestering or storing CO2—in essence, replacing the oil drawn from the oil fields and ROZ’s with CO2—is as good as storing in a saline reservoir?
Yes. From a confinement point of view, from an assurance of a competent seal, from the much higher volumes of CO2 that you can store in a confined area, CO2-EOR is as good or better than using a saline reservoir.

Your paper focuses on recovering oil from the ROZs using anthropogenic CO2. What about using it as a vehicle for oil recovery from shale? Should we be exploring that potential?

We should. The recovery efficiencies from shale oil formations, like the Bakken or Eagle Ford, are low, on the order of 5 to 6 percent. So you leave behind a tremendous volume of oil. Using CO2 to recover more of the oil would be ideal. And the space in the shale vacated with the removal of the oil would be a perfect place to store CO2. Storing CO2 in shale formations is more challenging than in a conventional reservoir, and would be a new exciting topic to explore. Shale oil wells decline very fast; after 3 or 4 years, the wells are down to only 10 to 20 percent of their initial production and are looking for help.

And you are saying that only 5 to 6 percent of the shale oil is being recovered?

Yes. The formations are tight and fractured. The combined use of horizontal wells and CO2 injection, while challenging, offers considerable promise for doubling the amount of oil recoverable from shale.

So you and others, Melzer being one, see an evolving new market for EOR that increases oil production in the U.S. along with providing a solution for reducing emissions of anthropogenic CO2 to the atmosphere?

Yes, there is a growing market for using anthropogenic CO2 with EOR. It is a question of getting the costs of capturing CO2 emissions down so that the CO2 is affordable to the EOR industry.

What, other than the cost of anthropogenic CO2, is presenting a challenge to moving ahead with utilizing it for EOR?

Other than the cost of CO2, we will need new CO2 pipelines and more efficient, advanced CO2-EOR technologies.

Based on what you mentioned earlier about the role for DOE, NETL and State governments, do you believe that there is a need for a government/industry working partnership to move forward?

A government/industry R&D partnership on CO2-enhanced oil recovery, particularly to pursue advanced versions of CO2-EOR, would be of great benefit. If you ask me the question, what are the most important things to do to get CCUS going, my view is the following:

  • First, is to bring down the cost of CO2 capture from power plants, from the $80 to $100 a metric ton of CO2 today;
  • Second, is to pursue advanced, we call it Next Generation, CO2-EOR technology. By making the CO2-EOR process more efficient, the size of the CO2 market doubles and industry would be able to pay more for CO2;
  • Third, is to pursue policy options that would close the gap between the cost of CO2 capture and the EOR industry’s affordable market price for CO2; and
  • Finally, the opportunities for CO2 utilization and storage by EOR overseas are likely several-fold larger than in the U.S.

To read presentation slides of Kuuskraa’s paper from the Midland Conference click here.

Comments are closed.

Partner Content
Social Feed

Tweets by @EMPublications