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Policies, markets, and technologies interact to create the modern electrical system. Integrating large amounts of electricity generated by variable renewable resources, such as from wind and sunlight, into electricity systems may require energy storage technologies to synchronize electricity production with electricity demand. Electricity markets compensate the performance of these energy storage technologies for the services they provide, and these markets are often operated by regional independent system operators (ISOs) that specify the market rules for this compensation. To examine how different ISO rules can affect the operation and profitability an energy storage technology, we develop a dynamic programming model of pumped hydroelectric storage (PHES) facility operation under the market rules from the Midcontinent ISO and ISO-New England. We present how differences in rules between these ISOs produced different operational strategies and profits, and how important they are for PHES profitability.

Carbon dioxide (CO 2 ) capture and storage involves injecting CO 2 into permeable geologic reservoirs. Candidate reservoirs will be overlain by an impervious caprock, but CO 2 or brine may leak through this caprock via natural or manmade pathways into overlying units. Such leakage will incur multiple costs to a variety of stakeholders, as mobile fluids may interact with other subsurface activities, reach groundwater, or possibly escape from the surface. We summarize a methodology to monetize leakage risk throughout a basin, based on simulations of fluid flow, subsurface data, and estimates of costs triggered by leakage. We apply this methodology to two injection locations in the Michigan (U.S.A.) Sedimentary Basin, and show that leakage risk is site-specific and may change priorities for selecting CO 2 storage sites, depending on its siting relative to leakage pathways and other subsurface activities.

© 2016 American Chemical Society. We developed the Leakage Risk Monetization Model (LRiMM) which integrates simulation of CO2 leakage from geologic CO2 storage reservoirs with estimation of monetized leakage risk (MLR). Using geospatial data, LRiMM quantifies financial responsibility if leaked CO2 or brine interferes with subsurface resources, and estimates the MLR reduction achievable by remediating leaks. We demonstrate LRiMM with simulations of 30 years of injection into the Mt. Simon sandstone at two locations that differ primarily in their proximity to existing wells that could be leakage pathways. The peak MLR for the site nearest the leakage pathways ($7.5/tCO2) was 190x larger than for the farther injection site, illustrating how careful siting would minimize MLR in heavily used sedimentary basins. Our MLR projections are at least an order of magnitude below overall CO2 storage costs at well-sited locations, but some stakeholders may incur substantial costs. Reliable methods to detect and remediate leaks could further minimize MLR. For both sites, the risk of CO2 migrating to potable aquifers or reaching the atmosphere was negligible due to secondary trapping, whereby multiple impervious sedimentary layers trap CO2 that has leaked through the primary seal of the storage formation.

We examine how state-level factors affect greenhouse gas (GHG) reduction policy preference across the United States by analyzing climate action plans (CAPs) developed in 11 states and surveying the CAP advisory group members. This research offers insights into how states approach the problem of choosing emissions-abatement options that maximize benefits and minimize costs, given their unique circumstances and the constellation of interest groups with power to influence state policy. The state CAPs recommended ten popular GHG reduction strategies to accomplish approximately 90% of emissions reductions, but they recommended these popular strategies in different proportions: a strategy that is heavily relied on in one state’s overall portfolio may play a negligible role in another state. This suggests that any national policy to limit GHG emissions should encompass these key strategies, but with flexibility to allow states to balance their implementation for the state’s unique geographic, economic, and political circumstances. Survey results strongly support the conclusion that decisions regarding GHG reductions are influenced by the mix of actors at the table. Risk perception is associated with job type for all strategies, and physical and/or geographic factors may underlie the varying reliance on certain GHG reduction strategies across states.

Carbon capture and storage (CCS) is considered by some to be a promising technology to reduce greenhouse gas emissions, and advocates are seeking policies to facilitate its deployment. Unlike many countries, which approach the development of policies for geologic storage (GS) of carbon dioxide (CO 2 ) with nearly a blank slate, the U.S. already has a mature policy regime devoted to the injection of CO 2 into deep geologic formations. However, the existing governance of CO 2 injection is designed to manage enhanced oil recovery (EOR), and policy changes would be needed to manage the risks and benefits of CO 2 injection for the purpose of avoiding GHG emissions. We review GS policy developments at both the U.S. federal and state levels, including original research on state GS policy development. By applying advocacy coalition framework theory, we identify two competing coalitions defined by their beliefs about the primary purpose of CO 2 injection: energy supply or greenhouse gas (GHG) emission reductions. The established energy coalition is the beneficiary of the current policy regime. Their vision of GS policy is protective: to minimize harm to fossil energy industries if climate policy were to be enacted. In contrast, the newly formed climate coalition seeks to change existing GS policy to support their proactive vision: to maximize GHG reductions using CCS when climate policy is enacted. We explore where and at what scale legislation emerges and examine which institutions gain prominence as drivers of policy change. Through a detailed textual analysis of the content of state GS legislation, we find that the energy coalition has had greater success than the climate coalition in shaping state laws to align with its policy preferences. It has enshrined its view of the purpose of CO 2 injection in state legislation, delegated authority for GS to state agencies aligned with the existing policy regime, and protected the EOR status quo, while creating new opportunities for EOR operators to profit from the storage of CO 2 The climate coalition's objective of proactively putting GS policy in place has been furthered, and important progress has been made on commonly held concerns, such as the resolution of property rights issues, but the net result is policy change that does not significantly revise the existing policy regime.

This paper assesses the issue of monitoring to measure potential emissions from leakage at geologic sequestration (GS) sites for purposes of greenhouse gas (GHG) accounting under an emission reduction program. We find that a GHG accounting program can reasonably assume that there is no atmospheric leakage from GS sites as long as routine subsurface monitoring shows no loss of containment. If loss of containment is detected, current monitoring technology, such as hyperspectral imaging, should be able to detect and locate leakage at levels of concern at some but not all sites. If leakage can be detected, then it can be reliably quantified using existing technology. The disparities in leakage detection capability produced by geologic and ecosystem variations require a flexible GHG accounting policy for GS sites during the operations phase. The potential for leakage emissions during long-term stewardship is low, but mechanisms to account for it, such as an emissions reserve program, are important for building public support for CCS technology and supporting national emission reduction goals.

The objective of carbon capture and sequestration (CCS) is to reduce emissions to the atmosphere through the sequestration of carbon dioxide (CO 2 ) in deep geologic formations. Recent studies of life-cycle emissions from CCS projects that sequester CO 2 captured from coal-fired power generation through EOR show that net emissions from this process are positive due to the CO 2 emissions embodied in produced oil. For geologic sequestration through enhanced oil recovery (GS-EOR) to be effective, life cycle GHG emissions from the system must be small and consumption of the energy produced should not result in larger emissions than would otherwise happen in the absence of the GS-EOR project. In the best case, where relatively high emissions intensity oil and electrical generation are being displaced, the emissions reduction potential is greater than the amount of CO 2 purchased by the project; however, where a relatively light crude and carbon free marginal generation is being displaced, the GS-EOR project results in an emissions increase. As a matter of public policy, if reducing emissions of CO 2 is of great importance, encouraging GS-EOR will not be as effective as geologic sequestration in deep saline aquifers, or other means of reducing emissions that do not result in increased production of fossil fuels. Nonetheless, it is likely that GS-EOR projects will happen in the absence of emissions reduction incentives because they bring other benefits. The nature and scope of a GHG reduction program will determine the accounting approach needed to accurately estimate the emissions from GS-EOR, but in general, components that do not fall under an emissions cap will need to be accounted for via life cycle assessment. While further study is needed, it appears that allocating the emissions reduction to an electric power generator would be less complex and more effective that allocating it to the oil or fuels producer.

Regulations for geological sequestration (GS) of carbon dioxide (CO2) have been adopted in the state of Washington and proposed by the state of Kansas and the U.S. Environmental Protection Agency (EPA) Underground Injection Control (UIC) Program. These three sets of rules take significantly different approaches to regulating GS of CO2. This paper compares these rules, focusing on elements where their differences highlight the choices that must be made to create a regulatory framework for GS in the United States. Consensus is emerging in some areas, but there is still substantial disagreement regarding the allowable composition of the CO2 stream, the size of the area of review, reservoir performance goals, and management of risks other than those to groundwater. Gaps include issues related to ownership of subsurface pore space, greenhouse gas accounting, and long-term stewardship. The divergent approaches of these rules raise two overarching questions: (1) Should policy makers create GS regulations by modifying and supplementing UIC rules or through new enabling legislation? (2) What should be the relative roles of state and federal governments in GS regulation? We outline trade-offs between the consistency and coordination that federal involvement could offer and the reality that states need to be heavily involved with implementation of GS regulations. We conclude that federal involvement above and beyond the proposed EPA Class VI rules is needed to create effective GS regulation in the United States.

States will play a vital role in the deployment of carbon capture and sequestration (CCS) in the United States. Many of the decisions and planning required to deploy CCS projects on a national scale will occur at the state and regional levels, including Public Utility Commission decisions on treatment of CCS costs, decisions on land use for building CO2 pipelines and developing geologic sequestration sites. There has been a burst of CCS policy activity in the states over the past few years. As of August 2008, 26 states have some sort of policy in place aimed at furthering CCS. To examine the importance of states’ particular circumstances on CCS policy development, we consider variables related to each state’s geology, electrical power system, economy, and political ideology. We find that distinctly different profiles emerge between states with CCS policies, states with climate policy, states with both, and states with neither. Understanding the state level policy landscape provides a basis for more effective coordination between state, regional, and federal CCS policy, and sheds some light on the compromises that need to be made between geographically diverse states for CCS to be widely deployed. A case study of the Midwestern Governors Association CO2 Management Infrastructure Partnership illustrates the opportunities that regional partnerships offer to facilitate these types of compromises and coordinate policy between states with varying circumstances but a shared interest in regional cooperation to advance commercial scale CCS.

Managing local and global risks from the geological storage of CO2 under the Clean Development Mechanism (CDM) presents three main challenges. First, the CDM procedures must be adapted to the specifics of the technology. Second, storage must last far longer than the crediting period, leaving questions about the management of long-term risks. Third, management of local environmental, health and safety risks falls largely outside the CDM governance framework. CDM procedures could be adapted to successfully manage the short-term global risk of carbon dioxide re-entering the atmosphere during the CDM crediting period, but local environmental, health and safety risks and longterm global risk cannot be ensured under existing structures. To better manage these risks, the implications for the CDM are: (1) to provide guidance on site characterization requirements, and have an independent auditor verify that the proposed geological storage site has a high likelihood of safely containing the injected carbon dioxide; (2) to require that carbon capture and storage (CCS) project design documents specify post-crediting-period commitments; and (3) to support CCS specific capacity building. But because CDM governance is designed to strike a balance between respecting host country sovereignty and ensuring high-quality emission reduction credits, some limitations to risk management of geological storage under the CDM remain. These limitations should be weighed against the potential benefits of including CCS in the CDM.

This three-year project, performed by Princeton University in partnership with the University of Minnesota and Brookhaven National Laboratory, examined geologic carbon sequestration in regard to CO{sub 2} leakage and potential subsurface liabilities. The research resulted in basin-scale analyses of CO{sub 2} and brine leakage in light of uncertainties in the characteristics of leakage processes, and generated frameworks to monetize the risks of leakage interference with competing subsurface resources. The geographic focus was the Michigan sedimentary basin, for which a 3D topographical model was constructed to represent the hydrostratigraphy. Specifically for Ottawa County, a statistical analysis of the hydraulic properties of underlying sedimentary formations was conducted. For plausible scenarios of injection into the Mt. Simon sandstone, leakage rates were estimated and fluxes into shallow drinking-water aquifers were found to be less than natural analogs of CO{sub 2} fluxes. We developed the Leakage Impact Valuation (LIV) model in which we identified stakeholders and estimated costs associated with leakage events. It was found that costs could be incurred even in the absence of legal action or other subsurface interference because there are substantial costs of finding and fixing the leak and from injection interruption. We developed a model framework called RISCS, which canmore » be used to predict monetized risk of interference with subsurface resources by combining basin-scale leakage predictions with the LIV method. The project has also developed a cost calculator called the Economic and Policy Drivers Module (EPDM), which comprehensively calculates the costs of carbon sequestration and leakage, and can be used to examine major drivers for subsurface leakage liabilities in relation to specific injection scenarios and leakage events. Finally, we examined the competiveness of CCS in the energy market. This analysis, though qualitative, shows that financial incentives, such as a carbon tax, are needed for coal combustion with CCS to gain market share. In another part of the project we studied the role of geochemical reactions in affecting the probability of CO{sub 2} leakage. A basin-scale simulation tool was modified to account for changes in leakage rates due to permeability alterations, based on simplified mathematical rules for the important geochemical reactions between acidified brines and caprock minerals. In studies of reactive flows in fractured caprocks, we examined the potential for permeability increases, and the extent to which existing reactive transport models would or would not be able to predict it. Using caprock specimens from the Eau Claire and Amherstburg, we found that substantial increases in permeability are possible for caprocks that have significant carbonate content, but minimal alteration is expected otherwise. We also found that while the permeability increase may be substantial, it is much less than what would be predicted from hydrodynamic models based on mechanical aperture alone because the roughness that is generated tends to inhibit flow.« less

T wo technologies, hydraulic fracturing and geologic carbon sequestration, may fundamentally change the United States’ ability to use domestic energy sources while reducing greenhouse gas emissions. Shale gas production, made possible by hydraulic fracturing and advances in directional drilling, unlocks large reserves of natural gas, a lower carbon alternative to coal or other fossil fuels. Geologic sequestration of carbon dioxide (CO2) could enable use of vast domestic coal reserves without the attendant greenhouse gas emissions. Both hydraulic fracturing and geologic sequestration are 21st Century technologies with promise to transform energy, climate, and subsurface landscapes, and for both, effective risk management will be crucial. Potential environmental impacts, particularly to groundwater, are key concerns for both activities, because both inject large volumes of fluids into the subsurface. Unless environmental issues and public concerns are actively addressed, public opposition could stall deployment of these two important technologies. In the United States, shale gas production increased 8-fold in the past decade, and it is projected to comprise roughly half of domestic production in 2035. Between 2010 and 2011, the U.S. Energy Information Agency (EIA) doubled the estimate of technically recoverable unproven shale gas reserves. U.S. energy supply projections have been fundamentally and strategically altered. Hydraulic fracturing, which makes this bounty possible, injects a mix of water, propping agents, and proprietary chemicals at high pressure to create millions of small fractures in low-permeability shale and liberate trapped natural gas. At each well, 2 to 4 million gallons of water are injected and 30 to 70% remains underground. Geologic sequestration could keepCO2 out of the atmosphere by capturing it at coal burning power plants or other industrial facilities and injecting it into deep geologic formations. The U.S. Department of Energy, in the 2010 Carbon Sequestration Atlas, estimated that the nation has the capacity to store all CO2 emissions from large domestic stationary sources for at least 500 years (at 2009 emission rates). Geologic sequestration has great promise, but its role in the U.S. energy future is uncertain; there is no economic driver to do it unless society decides to substantively reduce GHG emissions. A few demonstration projects are underway, scheduled to inject a total of about 10 million tons of CO2 in the United States. Another 12 million tons of captured CO2 was used for enhanced oil recovery in 2010, but currently, geologic sequestration is a minor player on the U.S. energy stage. Although hydraulic fracturing and geologic carbon sequestration are distinct technologies, they pose some similar environmental risks. Groundwater contamination could occur if injected or mobilized fluids escape from the target formation and migrate upward into drinking water along faults, fractures, abandoned wells, or poorly constructed injection wells. Both technologies can protect groundwater by carefully studying site geology so only appropriate sites are chosen, using best practices for well construction, monitoring site performance, and developing emergency and remedial response plans so all parties are prepared if problems arise. Despite similarities in their environmental risks, regulations for geologic carbon sequestration and hydraulic fracturing are drastically different; the result is that similar risks are managed quite differently. Ironically, nascent geologic sequestration technology has state-of-the art regulations that were crafted during a decade of federal notice-and-comment rulemaking. The environmental risks of geologic sequestration will be managed by the EPA UIC program, under new Class VI well rules adopted in 2010. As the first injection well class added since 1983, Class VI rules incorporate advances in subsurface technology and modeling, regulatory philosophy, and environmental expectations that have transpired in the intervening quarter century. In contrast, the Energy Policy Act of 2005 officially exempted hydraulic fracturing from regulation under the UIC program. The environmental risks of shale gas production are managed

Governments worldwide should provide incentives for initial large-scale GS projects to help build the knowledge base for a mature, internationally harmonized GS regulatory framework. Health, safety, and environmental risks of these early projects can be managed through modifications of existing regulations in the EU, Australia, Canada, and the U.S. An institutional mechanism, such as the proposed Federal Carbon Sequestration Commission in the U.S., should gather data from these early projects and combine them with factors such as GS industrial organization and climate regime requirements to create an efficient and adaptive regulatory framework suited to large-scale deployment. Mechanisms to structure long-term liability and fund long-term postclosure care must be developed, most likely at the national level, to equitably balance the risks and benefits of this important climate change mitigation technology. We need to do this right. During the initial field experiences, a single major accident, resulting from inadequate regulatory oversight, anywhere in the world, could seriously endanger the future viability of GS. That, in turn, could make it next to impossible to achieve the needed dramatic global reductions in CO2 emissions over the next several decades. We also need to do it quickly. Emissions are going up, the climate is changing, and impacts are growing. The need for safe and effective CO2 capture with deep GS is urgent.

Carbon capture and sequestration (CCS) has the potential to enable deep reductions in global carbon dioxide (CO2) emissions, however this promise can only be fulfilled with large-scale deployment. For this to happen, CCS must be successfully embedded into a larger legal and regulatory context, and any potential risks must be effectively managed. We developed a list of outstanding research and technical questions driven by the demands of the regulatory and legal systems for the geologic sequestration (GS) component of CCS. We then looked at case studies that bound uncertainty within two of the research themes that emerge. These case studies, on surface leakage from abandoned wells and groundwater quality impacts from metals mobilization, illustrate how research can inform decision makers on issues of policy, regulatory need, and legal considerations. A central challenge is to ensure that the research program supports development of general regulatory and legal frameworks, and also the development of geological, geophysical, geochemical, and modeling methods necessary for effective GS site monitoring and verification (MV) protocols, as well as mitigation and remediation plans. If large-scale deployment of GS is to occur in a manner that adequately protects human and ecological health and does not discourage private investment, strengthening the scientific underpinnings of regulatory and legal decision-making is crucial.

We studied 90 male non diabetic patients aged between 40 and 65 years old with a total cholesterol of less than 240 mg/dl and not receiving cholesterol reducing drugs, that were subjected to elective coronary arteriography. Weight, height, blood pressure and smoking habits were recorded and a fasting blood sample was drawn to measure total and HDL cholesterol, triglycerides, apoproteins A1 and B, Lipoprotein(a) and plasma cholesteryl ester transfer activity. Arteriography disclosed coronary lesions in 54 patients. Compared to patients without lesions, the former had lower HDL cholesterol (34 +/- 9.8 vs 40.2 +/- 11.6 mg/dl) and higher total cholesterol/HDL cholesterol and apoB/apoA1 ratios. No differences were found for lipoprotein(a) and plasma cholesteryl ester transfer activity. Univariate analysis showed that low HDL cholesterol had the best predictive capacity for atherosclerosis.

In a retrospective study, the results of real-time sonography and grid mammography in 161 patients with histologically confirmed breast cancer were analyzed and compared with the histopathologic characteristics of the tumours to assess the diagnostic accuracy of these preoperative image-producing methods. The results showed the determination of the tumour size as obtained by the image-producing methods to correlate closely with the histopathologic findings. Furthermore, both real-time sonography and mammography yielded certain indications allowing prognostically valuable conclusions in respect of malignancy and invasiveness of the carcinomas. Taking into account the different but complementing diagnostic results of both methods, the combination of grid mammography and real-time sonography must be considered as the presently most reliable preoperative diagnostic procedure.

In colour masking for continuous tone processes, the number of masks which is generally required can be reduced if the unwanted densities of the dyes are suitably related to each other. In particular, in a process employing dyes which have three unwanted densities (the yellow having no densities to red and green light and the magenta no density to red light) the three masks required can in certain cases be reduced to two. A suggestion that a similar simplification might be achieved in the masking procedure for halftone processes outlined in a previous paper is examined, and it is concluded that if the unwanted densities of the inks obey the condition which allows the reduced number of masks in a continuous tone process, then the same number of masks in a halftone process should give results which differ only little from those obtainable with the more correct full number of masks.

In a recent paper1 the author drew attention to important differences between the colours of continuous tone and halftone images and a set of equations was established connecting the colour of a halftone area (when expressed in terms of the densities to red, green and blue light) with the dot sizes of the printers. In the present paper it is shown that because yellow inks used in practice are ideal, these equations are soluble giving the halftone masking equations. If it is assumed that the strengths of the Inks are high, the masking procedure is considerably simplified. The resulting masks are non-linear, having greater contrast in the highlights and less contrast in the shadows than conventional masks (which would give correct masking only for continuous tone processes), but the average contrast is similar. It is also shown that, in spite of the various simplifying assumptions, this masking procedure should result in good reproduction of colours and neutrals.

The relationship between ink density, dot size and integrated density of monochrome halftone areas is briefly reviewed and their colour is compared with that of continuous tone areas From the monochrome relationship and from those established by Neugebauer an expression for the densities to red, green and blue light of multi-colour halftone areas is derived, and the principles oftheadditivity of halftone densities, and of the equivalence of continuous tone and halftone densities are deduced. On the basis of the former principle it is shown that with equal dot sizes of the image components a neutral scale can only be obtained if restrictions are placed on the concentration and colour of the inks. Finally, examples of the failure in practice of the additivity principle are discussed.

An area of the dots to be measured is cemented to an area of large dots (very small holes) of the same spacing, so that a large moire pattern results. The moire “dots” are in effect enlargements of the dots under test, and their density contours are obtained by contact-printing the combination together with a step wedge on sheets of a suitable photographic material, using various exposures. In each print the density printed through is indicated by the step wedge, while the corresponding contour is indicated by the innermost row of small dots which have just printed. A contour map is then obtained by placing the prints in the negative carrier of an enlarger and tracing the isopaques on a sheet of paper on the easel.

Leakage of brine or carbon dioxide (CO 2 ) from geologic CO 2 storage reservoirs will trigger numerous costs. We present the Leakage Impact Valuation (LIV) method, a systematic and thorough scenario-based approach to identify these costs, their drivers, and who incurs them across four potential leakage outcomes: 1) Leakage only; 2) leakage that interferes with a subsurface activity; 3) leakage that affects groundwater; and 4) leakage that reaches the surface. The LIV method is flexible and can be used to investigate a wide range of scenarios. The financial consequences of leakage estimated by the LIV method will be specific to the case study, because the consequences of leakage will vary across case studies due to differences geologic, institutional, and regulatory settings.

In a retrospective study, the results of real-time sonography and grid mammography in 161 patients with histologically confirmed breast cancer were analyzed and compared with the histopathologic characteristics of the tumours to assess the diagnostic accuracy of these preoperative image-producing methods. The results showed the determination of the tumour size as obtained by the image-producing methods to correlate closely with the histopathologic findings. Furthermore, both real-time sonography and mammography yielded certain indications allowing prognostically valuable conclusions in respect of malignancy and invasiveness of the carcinomas. Taking into account the different but complementing diagnostic results of both methods, the combination of grid mammography and real-time sonography must be considered as the presently most reliable preoperative diagnostic procedure.

The synthetic resin Piccolyte WW 100 dissolved in xylene is proposed as a cement for gelatine light filters. Its advantages are a high thermal softening point, good adhesion to glass, absence of tendency to form air-bubbles, rapid drying and freedom from yellowing with age or on exposure to light. The technique of its use is described.