Carbon Sequestration Rules Emerge

Just a few years ago uttering the words “carbon sequestration” at a party would result in raised eyebrows and puzzled looks: “Carbon what?”

Today, however, the term rolls smoothly off politicians’ tongues: Al Gore gave it positive mention in his film “An Inconvenient Truth,” and the Bush administration’s energy strategy depends on it to harness the energy in the nation’s vast coal resources while minimizing carbon emissions to the atmosphere.

A primary focus of the U.S. government’s current research effort is the long-term storage of carbon in geologic formations, including depleted oil and gas reservoirs, unmineable coal seams and deep saline formations. President Bush’s fiscal year 2009 budget request for carbon sequestration programs within the U.S. Department of Energy (DOE) is $149 million.

There are other methods of carbon sequestration: Increasing soil carbon content by changing crop tilling practices, for example, is currently in use with good results. Injecting CO2 into the oceans is being studied, but faces both technological and public acceptance hurdles. Geologic sequestration provides the greatest hope for storing large volumes of CO2 close to the point sources producing it.

However, geologic sequestration also faces technological challenges – after all, the current goal of DOE’s Regional Carbon Sequestration Partnerships’ (RCSP) large-scale, multi-year demonstrations is to inject in a single well up to one million tons of CO2 annually.

That is roughly equivalent to the volume of the Empire State Building – and a commercial plant would emit several times this amount.

Talk about that at a party and eyebrows will really pop up. Even if we can solve the technical challenges, public acceptance remains an issue.

Fortunately, the petroleum industry’s long experience of safely injecting CO2 into the subsurface for enhanced oil recovery (EOR) is helping solve both the technological and public acceptance challenges facing geologic sequestration.

Recognizing this fact, the Interstate Oil and Gas Compact Commission (IOGCC) formed a “Geological CO2 Sequestration Task Force” in 2002 to investigate the technical, policy and regulatory issues surrounding safe and effective geologic sequestration.

The Phase I study was funded by DOE through its National Energy Technology Laboratory. The task force included members from IOGCC member states and affiliates, state oil and gas regulators, DOE, the RCSPs, state geologists and other experts.

The principal result of Phase I was recognition that states that regulate oil and natural gas production and the sub-surface storage of natural gas have both the requisite knowledge and experience to safely regulate geologic sequestration.

They also have regulatory frameworks in place that, with some modification, could apply to geologic sequestration.

In 2006 the task force resumed work on Phase II, again funded by DOE. Representatives of the U.S. Environmental Protection Agency, U.S. Bureau of Land Management and an environmental group joined the task force for this study.

Phase II’s goal was to prepare a guidance document for states wanting to create a geologic sequestration regulatory framework. The report includes a model statute, model rules and regulations with explanatory text to implement the statute, and a report addressing legal questions on subsurface ownership and injection rights. The guidance document is available at the IOGCC Web site.

At the federal level the U.S. Environmental Protection Agency (EPA) also is reviewing the regulatory needs for carbon sequestration. Specifically, its focus is ensuring that injecting large volumes of CO2 into the subsurface does not damage drinking water sources.

The Safe Drinking Water Act places this responsibility with EPA, and is implemented through the Underground Injection Control (UIC) program. In many states the local regulatory bodies implement the UIC program on behalf of EPA. This is known as having “primacy.”

In other states this responsibility is shared by state regulators and EPA, or handled exclusively by the federal agency.

The UIC program has several well classes with different regulations for each class:

  • Class I – hazardous waste.
  • Class II – oil and gas operations, including CO2-based EOR and enhanced gas recovery, EGR.
  • Class III – mining.
  • Class IV (no longer used).
  • Class V – experimental, non-hazardous.

In March 2007 EPA issued guidance to states with primacy to permit geologic sequestration demonstration projects as Class V experimental wells. This facilitated permitting for the RCSP demonstration projects.

Shortly thereafter EPA launched a formal rule-making process to regulate long-term geologic sequestration. The agency formed a working group consisting of EPA, DOE and state officials, and fast-tracked their activities. EPA expects to issue a rule proposal for public comment this summer.

It is important to note that the current EPA process has nothing to do with regulating carbon emissions – it’s about how to safely store them. Assuming we can solve the technical and public acceptance challenges, the question of whether large-scale carbon sequestration becomes reality is something lawmakers must still decide.

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Washington Watch

Washington Watch - David Curtiss

David Curtiss served as the Director of AAPG’s Geoscience and Energy Office in Washington, D.C. from 2008-11.

Policy Watch

Policy Watch is a monthly column of the EXPLORER written by the director of AAPG's  Geoscience and Energy Office in Washington, D.C. *The first article appeared in February 2006 under the name "Washington Watch" and the column name was changed to "Policy Watch" in January 2013 to broaden the subject matter to a more global view.

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Editor's Note:

David Curtiss will be a presenter in the DPA forum “Energy Resources, Reserves and the Future Workforce: Policy and Labor in the Geosciences” at the AAPG Annual Convention and Exhibition in San Antonio.

The session will be held from 8-11:30 a.m. Tuesday, April 22.Curtiss’ topic will be the current initiatives in work force development in the geosciences.

Curtiss also will be available during the convention at the DPA booth located in the AAPG Center in the exhibits hall.

For more information on carbon sequestration-related reports and activity:

Interstate Oil and Gas Compact Commission report.

EPA overview of UIC program.

EPA overview of carbon sequestration rule making.

See Also: Book

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See Also: Bulletin Article

Estimation of the dimensions of fluvial geobodies from core data is a notoriously difficult problem in reservoir modeling. To try and improve such estimates and, hence, reduce uncertainty in geomodels, data on dunes, unit bars, cross-bar channels, and compound bars and their associated deposits are presented herein from the sand-bed braided South Saskatchewan River, Canada. These data are used to test models that relate the scale of the formative bed forms to the dimensions of the preserved deposits and, therefore, provide an insight as to how such deposits may be preserved over geologic time. The preservation of bed-form geometry is quantified by comparing the alluvial architecture above and below the maximum erosion depth of the modern channel deposits. This comparison shows that there is no significant difference in the mean set thickness of dune cross-strata above and below the basal erosion surface of the contemporary channel, thus suggesting that dimensional relationships between dune deposits and the formative bed-form dimensions are likely to be valid from both recent and older deposits.

The data show that estimates of mean bankfull flow depth derived from dune, unit bar, and cross-bar channel deposits are all very similar. Thus, the use of all these metrics together can provide a useful check that all components and scales of the alluvial architecture have been identified correctly when building reservoir models. The data also highlight several practical issues with identifying and applying data relating to cross-strata. For example, the deposits of unit bars were found to be severely truncated in length and width, with only approximately 10% of the mean bar-form length remaining, and thus making identification in section difficult. For similar reasons, the deposits of compound bars were found to be especially difficult to recognize, and hence, estimates of channel depth based on this method may be problematic. Where only core data are available (i.e., no outcrop data exist), formative flow depths are suggested to be best reconstructed using cross-strata formed by dunes. However, theoretical relationships between the distribution of set thicknesses and formative dune height are found to result in slight overestimates of the latter and, hence, mean bankfull flow depths derived from these measurements.

This article illustrates that the preservation of fluvial cross-strata and, thus, the paleohydraulic inferences that can be drawn from them, are a function of the ratio of the size and migration rate of bed forms and the time scale of aggradation and channel migration. These factors must thus be considered when deciding on appropriate length:thickness ratios for the purposes of object-based modeling in reservoir characterization.

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See Also: CD DVD

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