News Ticker


Put science before emotion on the topic of NORM waste

Radioactive waste . . . NORM waste . . . “hot” filter socks . . . illegal dumping . . . Many attention-grabbing headlines have been written in the past year. What’s it all about? What do these headlines really mean to the public and the North Dakota landscape in which we take such pride?

These are reasonable questions that demand solid answers. Unfortunately, the science behind the issues does not translate easily into a quick news story. It is time to put science before emotion to counter some of the misconceptions and even exaggerations about what NORM is, how it is disposed of, and why industry and state regulators are working together to ensure the safe and responsible disposal of these materials.

NORM stands for naturally occurring radioactive material with radioactivity in excess of
5 picoCuries per gram of bulk material (a measurement of radioactivity per unit weight of material). Radioactivity exists in all natural materials, including soils, rocks, water, and even air. It is present in food, building materials, electronics, and even that wristwatch you’ve been wearing for years. And yes, NORM is present in Bakken shale. It is brought to the surface via drill cuttings and water that naturally exists in some geologic formations.

Although a small number of irresponsible business owners have put this issue in the public spotlight, the vast majority of industry has been handling NORM properly since the early 1980s when the issue first arose in oil and gas exploration. Oil producers in the Bakken currently spend large sums of money to transport materials that may or may not contain NORM to licensed special waste landfills in Colorado, Texas, Idaho, and other states. These materials must be hauled long distances because North Dakota does not currently have NORM-specific regulations permitting in-state disposal. It is for this very reason that industry is working with state regulators to put the proper regulations, infrastructure, and facilities in place to safely and responsibly dispose of any NORM specifically associated with the oil and gas industry.

Under current North Dakota regulations, material or equipment in which less than 5 picoCuries per gram is measured may be disposed of without restriction. The regulated radioactivity threshold is specific to two isotopes, or radioactive particles, of radium. Putting this in perspective, the granite countertop in your home can likely not be disposed of in a North Dakota landfill under current rules. The countertop has a low level of radioactivity, as does common cat litter. Bananas, coffee grounds, Brazil nuts, and other foods contain similar levels of radioactivity, though not necessarily associated with the radium isotopes. Some phosphate-containing fertilizers, a staple of North Dakota’s agricultural industry, contain NORM activity 5–30 times higher than current North Dakota oilfield waste disposal regulations would allow.

North Dakota needs rules that enable responsible disposal procedures that ensure public health, but we need to keep this in proper perspective. NORM is NOT nuclear waste. It is NOT the highly dangerous material reported in exaggerated headlines and other public statements. NORM is present all around us in our everyday lives. NORM is typically several orders of magnitude (thousands of times) less radioactive than nuclear waste. Words such as “radiation” and “NORM” should not evoke the emotional reaction currently sought by some. Instead, we must understand the science to understand the potential impacts.

The improper handling and potential illegal dumping of NORM is strongly condemned by responsible industry and by state regulators, and it underscores the need for licensed disposal sites within our state. Responsible parties agree that having in-state sites to handle the waste generated in the state will discourage improper handling and illegal dumping that now occasionally occur. Making sure that we have those sites available will take thorough research to ensure we have the proper regulations, permitting, and protocols in place, with special consideration given to North Dakota’s unique geology, landscape, and hydrology. The North Dakota Petroleum Council, the North Dakota Department of Health, the North Dakota Industrial Commission’s Oil and Gas Research Council, and the University of North Dakota’s Energy & Environmental Research Center are collectively working toward this end. In working together, we can ensure that we continue to develop our energy resources safely and responsibly.

Jay Almlie is Senior Research Manager at the Energy & Environmental Research Center (EERC) in Grand Forks, North Dakota.

The CO2 Challenge: Economical Capture, Utilization, and Storage

Much debate has surrounded anthropogenic (man-made) sources of greenhouse gases, particularly CO2, and their link to global climate change. The argument over this concept has moved into the international political structure and is now a major driver of policy. Although the long-term impacts of climate change, both ecologically and sociologically, are being debated rigorously, worldwide goals for reducing CO2emissions are moving forward as are regulations. In the United States, many questions confront utilities as to how to comply with proposed U.S. Environmental Protection Agency (EPA) emission regulations and still provide affordable power.

Anthropogenic CO2 is a by-product of almost everything humans do, including breathing. Large stationary sources of CO2 are the focus of EPA’s emission limits. Electric utilities, petroleum and gas processing, ag-related processing, and industry, such as cement and steel plants, are the largest point sources of CO2, and entire books have been written on their potential influence on the world’s climate. This article will focus on the coal-fired power generation sector and the challenges it faces with CO2 emissions.

The scale of CO2 emissions from U.S. power generation is large. One metric ton of coal used to fuel electricity production produces 2.0 to 2.4 metric tons of CO2. A typical coal-fired power plant will consume hundreds of metric tons of coal an hour, depending on coal type and plant size. The U.S. electricity industry alone has a very large carbon footprint, given that there were 1308 coal-fired units across 557 locations in the United States (as of the end of 2012). In fact, according to the International Energy Agency (IEA), the U.S. coal-fired fleet emitted over 1.5 billion metric tons of CO2 in 2012. For the spectrum of generation units across the country, this translates to hundreds of thousands to millions of metric tons of CO2 emitted annually by each plant. Nonetheless, the U.S. represents only about an eighth of the world’s coal use, and that fraction is rapidly diminishing as domestic use stabilizes and international use continues to grow.

The use of coal for electricity generation is unlikely to be significantly reduced in the foreseeable future. Since the Industrial Revolution, coal has been the foundation for many of the technological advances the world has enjoyed and is so firmly enmeshed that it is simply impossible to quit using coal “cold turkey.” Coal is a fossil fuel, like oil and natural gas, and is part of our nation’s energy security. It is abundant and can be used efficiently and in an environmentally sound manner to meet energy needs. The IEA projects that the use of coal will remain steady and continue to be the foundation of energy production, not only for the United States but for the world for decades to come.

The discussion of CO2 in the power generation sector has to be fully laid out for context. Various aspects of the process can be found in all of the major publications, but the integrated process—CO2 capture, utilization, and storage (CCUS)—must be considered in its entirety. When each aspect is viewed separately, the overall process appears generic and not representative of a given situation. To achieve an accurate representation, a fully integrated process must be considered. Discussion of CO2 capture involves the discussion of plant size, existing emission controls, CO2 technology being used, and the energy penalty to the plant and must include the available options for transporting the CO2, as well as available options for storage or use of the captured CO2. The cost of each of these points must be taken into consideration because they will impact the ultimate cost of electricity in a carbon-managed power production scenario.

Moving toward U.S. energy security means entering into a situation where most U.S. energy, and energy sources, are harvested in North America in a manner that is reliable, relatively inexpensive and environmentally responsible. Most consumers of power are resistant to large increases on their electricity bill, while simultaneously, there is a public demand to reliably purchase power that is produced in an environmentally friendly way. The U.S. energy security goal is a very delicate balance between all of these factors, and the CCUS composition must be able to adjust to them.

The capture component is not as simple as one might think. A broad spectrum of generation units varying from less than 50 to over 800 MW in size are in use today utilizing various coals of different heat densities, at different quantities, and with very different levels of emission control. The technologies that currently exist for capturing CO2 are sensitive to the composition of the flue gas, mostly sulfur and nitrogen oxides, referred to as SOx and NOx. Most currently deployed systems for removing SOx and NOx from flue gas do not remove enough of these constituents to prevent the degradation of the chemicals or membranes used in today’s CO2 capture technologies. In many cases, plants will likely need to deploy additional impurity removal techniques prior to CO2 capture, equating to additional capital expense.

CO2capture technologies for coal-fired power plants are an ever-growing science and engineering enterprise. New concepts, or improvements to known concepts, are being generated every year. At this time, most of these concepts are not ready to be deployed at the full scale, so “first-generation” technologies which rely on experience gained in other industries will likely be the first deployed. Technologies to capture impurities from gas streams are not new, and many have been around for decades. Today’s most deployable technologies either rely on solvents or sorbents to capture the CO2 from a flue gas stream, while coal gasification can also employ membranes for CO2separation. Solvents/sorbents require heat, both to release the captured CO2and to regenerate the solvent/sorbent for reuse. This additional heat requirement is one of the largest challenges facing implementation of CO2capture and results in a significantly large energy penalty (parasitic load) on a power plant.

The most logical source of heat for solvent/sorbent regeneration is the steam cycle itself. In most coal-fired power plants, the steam cycle provides the energy for the electrical generator to produce electricity, and if steam is diverted to other purposes, then that energy is not available to turn the generator. It is universally recognized that the integration of today’s CO2capture technology will result in a reduction of the plant’s electricity output by up to 35%. Many of the smaller plants, certainly those below 100 MW, would be forced to shut down, as the costs of additional emission control and CO2capture integration and energy penalty would be too great to overcome. Other sources for regeneration energy could be used, but it would mean the construction of additional units and/or the application of an additional fuel source, which again equals more expense.

Solvents are currently the quickest way to capture CO2 but come with their own set of challenges. A majority of solvents used for CO2 capture are composed predominantly of water and amine-based chemicals, which typically make up 20% to 40% of the solution. The water component does not aid in the solvent’s ability to capture CO2, and there is ongoing research to reduce and/or remove the need for water altogether. Water content greatly contributes to the overall need for regeneration energy; therefore, less water would also mean a lower energy penalty. Each plant utilizing a solvent would need hundreds to thousands of gallons a year to replace the spent solvent. When adjusting that to the number of plants that would potentially use the solvent, the volume of chemicals needed each year becomes very large. Many chemical suppliers have recognized that a challenge would exist to produce enough of these chemicals for CO2capture alone, to say nothing for the production of these chemicals for any other use worldwide. Of additional note is the fact that these solvents may be hazardous, need to be handled carefully, and must be stored and disposed of properly to avoid potential harm to the environment.

Incremental improvements/changes in the composition of these solvents can have a broad effect on CCUS. Less water usage, lower regeneration energy requirement, greater CO2 uptake by the solvent, and greater tolerance for SOxand NOx are all factors that highly influence the economic viability of any solvent.

This is the focus of the Partnership for CO2 Capture (PCO2C) Program at the Energy & Environmental Research Center (EERC). One of the primary goals of this program is to study solvents, sorbents, and technologies used for CO2 capture and test them utilizing actual combustion- or gasification-derived flue gas generated in pilot-scale systems from many different fuel sources. It is through this program, and others like it, that progress toward the goal of cost-effective CO2 capture is being realized, providing a pathway to technology demonstration and commercialization.

The U.S. Department of Energy (DOE) recognizes that demonstrations of CO2capture technologies have been limited, and with the implementation of first-generation technologies, the wholesale cost of electricity could increase by 80% as a result of a projected cost of CO2 capture at $60 per metric ton. The DOE has set a goal for second-generation technology to drop the costs of CO2capture below $40 per metric ton in the 2020–2025 time frame. This is all part of a critical DOE-sponsored program that is focused on reducing the issues facing commercially viable carbon capture. The process for reaching commercial viability needs to be stepwise, ending in multiple scale-up demonstrations of each technology.

The decisions made for updating emission control to accommodate for CO2capture integration and the selection of the CO2 technology are only the halfway point on the path to commercial CCUS. The remaining part of the path involves determining what should be done with the captured CO2. The most common option for CO2 storage is in deep geologic targets in sedimentary basins, such as depleted oil and gas fields, deep brine- or saltwater-filled formations, and deep unminable coal layers. The techniques for injecting and storing gases and fluids in deep geologic formations have been used in the oil, gas, and waste management industries for decades and have well-established practices. If the plant is located above or near a deep sedimentary basin, then there may be several options for CO2 storage. If there are nearby oil fields, the obvious first choice would be to provide CO2 for enhanced oil recovery (EOR). Utility power plants and other regulated CO2emission sources that do not have regional access to geologic options will have severe challenges when it comes to storing captured CO2.

To utilize CO2, it must first be transported. Transport of CO2is only economical within a certain distance from the emission source to a wellhead or a pipeline interconnect. Transportation is available through the use of pipelines and tankers to move compressed CO2 wherever it is needed, but at a cost, and these costs are not trivial. Costs have been estimated for trucks and trailers to be in the range of $45 per metric ton to transport CO2, whereas railcars are estimated to be about $35 per metric ton. Pipelines are a more economical option in the long run but require significant planning, permitting, and up-front capital. Costs for pipelines can vary widely, but a quick estimate can be made using rule-of-thumb guidelines at $70,000–$100,000 per inch of pipe diameter per mile of pipe. For example, a 12-inch pipeline would cost $840,000–$1,200,000 per mile; if the line were only 10 miles long, then the cost would be $8.4 to $12 million dollars. For a plant 500 miles from subsurface use, the costs for transport may be too high. In these situations, partnerships must form between the CO2 provider and the CO2 user.

CO2utilization and storage are the focus of another program led by the EERC called the Plains CO2 Reduction (PCOR) Program. This program is one of seven regional partnership programs sponsored by DOE’s National Energy Technology Laboratory’s Regional Carbon Sequestration Partnership Program. The PCOR Partnership Program is a collaboration of over 100 U.S. and Canadian stakeholders that is laying the groundwork for practical and environmentally sound CO2 storage projects in the heartland of North America.

It is easy to quickly realize that the costs for CCUS will be in the billions of dollars and, ultimately, those costs will be passed down in some form to the consumer. EOR and other utilization processes may ease some of the associated costs, but in the end, the price of energy will likely rise. In addition, many challenges are associated with the commercial implementation of CCUS, but we are working toward economically viable solutions. These solutions are going to take time to develop but will be needed, as the world’s energy demand increases, along with the need to be good stewards of the environment. As such, it makes sense to continue the work under the important DOE CCUS programs, to improve readiness, and to reduce the costs for widespread commercial CCUS implementation, not just in the United States but around the world.

By John Kay, Senior Research Manager, Energy & Environmental Research Center (EERC)