Science is proven, but scale-up is unknown

Carbon capture and sequestration (CCS) works.  In a technical support document released in January 2014, the EPA noted that industry has been separating out carbon dioxide (CO2) from gas streams since the 1930s.  Even those who are devotedly opposed to any federal regulation imposing a CCS standard on new power plants would be hard pressed to deny that assertion given the many instances of CCS successfully in action. 

Moreover, several CCS endeavors are quite large.  For example, since 1996, the Norwegian company Statoil has been capturing CO2 from natural gas extracted from the Sleipner field in the North Sea.  The natural gas contains about 9 percent CO2 that Statoil has been injecting into a saline reservoir 2,600 to 3,300 feet below the sea floor.  About 1 million tons of CO2 is sequestered annually at a cost of about $17 per ton. 

Currently, the project has stored approximately 14 million tons of CO2, with an anticipated cap of 17 million tons.  It is estimated that the formation has the capacity to store about 600 billion tons of CO2.  A 1,000 MW coal-fired generating unit will produce approximately 7.8 million metric tons of CO2 per year.  Under EPA’s proposed New Source Performance Standards (NSPS) for coal-fired power plants, the operator of such a unit would be required to store about 3.1 million metric tons of that amount. 

The Statoil example presents promising possibilities for CCS in the United States, and, in its proposal, the EPA listed the project as an example of why CCS is the best system of emissions reduction (BSER) for CO2 control that has been adequately demonstrated.  The Agency has noted that underground saline formations offer the largest potential storage repository for captured CO2. 

But industry advocates are wary.  They emphasize that while there are many successful CCS endeavors, nothing remotely comparable to the scope of CCS envisioned for U.S. power plants has ever occurred.  This issue of scale-up is a core aspect of scientific feasibility, and it just hasn’t happened with CCS and power plants.

Saline aquifers

The scientific uncertainty is strong when it comes to sequestration.  According to Robert C. Trautz, a senior technical leader with the Electric Power Research Institute (EPRI), there has been little economic incentive to explore saline reservoirs and so little is known about them.  He notes that the Department of Energy (DOE) estimates that there are 2,102 to 20,043 billion metric tons of storage capacity in saline formations in the U.S. and Canada.  “The range of values provided for saline storage capacities reflects the fact that geologists don’t know as much about these types of reservoirs and, therefore, the capacity values have greater uncertainty,” said Trautz at a March 12, 2014, hearing of the House Committee on Science, Space and Technology. 

Another unknown about saline formations is their ability to store CO2 under intense pressure for hundreds and perhaps thousands of years.  This is an “entirely novel” concept, noted Theresa Pugh, director of Environmental Services for the American Public Power Association (APPA), in a December 2013 letter to the EPA.  For example, says Pugh, deep saline aquifers have not been geologically assessed on a granular level to an extent that would demonstrate that there are consistent caprock type formations to hold the CO2 under pressure.  (Caprock is a relatively impermeable rock that forms a barrier or seal above and around reservoir rock so that fluids cannot migrate beyond the reservoir.)

Far more is known about depleted oil and gas fields, which offer another option for CO2 storage.  While that may seem like a more feasible alternative, the DOE estimates that these fields would store up to 226 billion metric tons of CO2, which would fail to accommodate the anticipated output of a fleet of new coal-fired power plants.  Further, power plants are generally not conveniently located next to oil and gas fields, which would necessitate complex and costly pipeline projects that would be burdened with immense permitting requirements.

Trautz adds that unlike depleted oil and gas reservoirs, which have undergone production and decline in reservoir pressure, saline reservoirs have relatively high starting pressures.  This means that injection pressures and rates may need to be lower to prevent over-pressuring the reservoir and fracturing the caprock, potentially requiring more wells and infrastructure costs.  In addition, saline water extraction and management may be required to lower pressures in the reservoir, adding to the cost of storage. 

Working projects

EPA’s position on CCS relies a great deal on non-electric generating unit (EGU) examples of the technology.  In a CCS technical support document (TSD), the Agency cites data from the Global CCS Institute, listing 12 “large-scale integrated projects in operation.”  Seven of these projects are in the U.S.—four natural gas processing facilities, two fertilizer production facilities, and one hydrogen production facility.  All the U.S. projects sequester CO2 as part of enhanced oil recovery (EOR).  Also listed by the EPA are a U.S./Canada synthetic natural gas project and a natural gas processing project in Brazil, both also utilizing EOR for storage.  In addition to the Sleipner project, two additional natural gas projects in Europe and Africa inject CO2 into deep saline formations. 

“While none of these plants are EGUs, they are demonstrating the core components of CCS that could be directly applicable to a new fossil fuel-fired EGU—the capture, the compression and transportation, and the injection and storage,” says the EPA.

 EPRI’s Trautz acknowledges the success of the Sleipner CO2 project, but says the results of the other two deep saline injection endeavors have been somewhat less successful.  Specifically:

• The Snohvit natural gas project in Norway’s Barents Sea, also operated by Statoil, started injecting CO2 in 2008.  However, the project immediately found that the permeability of the target formation was too low and pressures climbed rapidly, requiring mitigation.  “Fortunately,” says Trautz, “multiple stacked reservoirs gave Statoil the flexibility to select another injection interval, allowing the project to continue injecting at a sustained rate of about 820,000 metric tons per year.”
• The Salah onshore natural gas project in central Algeria is operated by British Petroleum.  Starting in 2008, approximately 1 million metric tons of CO2 were injected per year into three wells.  The project suspended injection in 2011 after monitoring data indicated that the lower 650 feet of the 3,120-foot-thick caprock above the storage reservoir had likely fractured due to CO2 injection pressures.

Pilot projects

In both its proposal and TSD, the EPA also cited several pilot-scale CCS projects as evidence that CCS is heading toward larger commercial application at EGUs.  “The EPA proposes to find that partial CCS is feasible because each step in the process has been demonstrated to be feasible through an extensive literature record, fossil fuel-fired industrial plants currently in commercial operation and pilot-scale fossil fuel-fired EGUs currently in operation, and progress towards completion of construction of fossil fuel-fired EGUs implementing CCS at commercial scale,” the Agency stated in the proposal. 

But industry is concerned about the value the EPA assigns to pilot projects in developing a final NSPS that could alter the U.S. energy landscape.  “None of the four pilot projects described in the NPRM actively capture CO2 from plant exhausts or sequester CO2 in the ground,” said Scott Miller on behalf of the APPA at the House hearing.  “Of the four, two are in the process of being constructed and two are in development.  Of the two being constructed, the Kemper plant [Southern Company’s Kemper County Energy Facility] faces development costs in excess of $1 billion and is dependent on a technology development for a lignite coal not available in any other place in the country. The second plant under construction, in Canada, is a post-combustion CCS operation at a small research facility boiler that is not scalable.”

CCS vendor

Perhaps the most interesting testimony at the hearing came from the representative for Alstom, a company that provides equipment needed for CCS at both coal- and gas-generation power plants.   According to Robert Hilton, an Alstom vice president, Alstom has completed work on four CCS pilot-scale plants and 10 pilots and validation and commercial-scale demonstration plants in operation, design, or construction worldwide.  Hilton says specific CCS technologies developed by Alstom include first generation chilled ammonia post-combustion capture, advanced amine post-combustion capture, and oxy-firing combustion technology.   He added that development is progressing on second-generation technologies like chemical looping and regenerative calcium cycle.

Hilton notes that CCS is no different from any other technology under development.  It must move through progressive stages of development at consistently larger scale or size.  He affirms that his company has taken several of its technologies through the validation-scale demonstration, but emphasizes that no carbon capture technologies have been deployed at commercial scale.  Hilton states:

“The final stage to reach commercial status is to perform a demonstration at full commercial scale. There are several reasons for this requirement.  It is critical to be at commercial scale to define the risk of offering the technology.  This cannot be defined until the technology can be shown to work at full scale.  This is the first opportunity that we have to work with the exact equipment in the exact operating conditions that will become the subject of contractual conditions when the technology is declared commercial and is offered under standard commercial terms including performance and other contractual guarantees. 

“This also becomes the first opportunity to optimize the process and equipment to effect best performance and, very importantly, seek cost reduction.  These too are required to define commercial contractual conditions.  Finally, our customers would be reluctant to invest in carbon capture technologies that have not been demonstrated to full commercial scale.  Based on these criteria, Alstom does not currently deem its technologies for carbon capture commercial and, to my knowledge, there are no other technology suppliers globally that can meet this criteria or are willing to make a normal commercial contract for CCS at commercial scale.  I emphasize, however, that the technologies being developed by Alstom and others work successfully.”

As the EPA has long argued, CAA Section 111, under which the NSPS for coal-fired power plants is being developed, is technology-forcing.  This means that a technology does not have to meet the commercial level of performance described by Hilton to serve as a basis for a final NSPS.  That position has been affirmed by the judiciary.  But mandatory CCS may affect the economy in ways the courts had not previously considered.  The bottom line is that any EPA rule that requires CCS will certainly be subjected to judicial review.

House testimony on the science of CCS

William C. Schillaci
BSchillaci@blr.com