Search

Natural gas based hydrogen production with carbon capture and storage is referred to as blue hydrogen. If substantial amounts of CO2 from natural gas reforming are captured and permanently stored, such hydrogen could be a low-carbon energy carrier. However, recent research raises questions about the effective climate impacts of blue hydrogen from a life cycle perspective. Our analysis sheds light on the relevant issues and provides a balanced perspective on the impacts on climate change associated with blue hydrogen. We show that such impacts may indeed vary over large ranges and depend on only a few key parameters: the methane emission rate of the natural gas supply chain, the CO2 removal rate at the hydrogen production plant, and the global warming metric applied. State-of-the-art reforming with high CO2 capture rates combined with natural gas supply featuring low methane emissions does indeed allow for substantial reduction of greenhouse gas emissions compared to both conventional natural gas reforming and direct combustion of natural gas. Under such conditions, blue hydrogen is compatible with low-carbon economies and exhibits climate change impacts at the upper end of the range of those caused by hydrogen production from renewable-based electricity. However, neither current blue nor green hydrogen production pathways render fully "net-zero" hydrogen without additional CO2 removal., Sustainable Energy & Fuels, 6 (1), ISSN:2398-4902

Large reductions in carbon dioxide (CO2) emissions are needed to mitigate the impacts of climate change. One method of achieving such reductions is CO2 capture and storage (CCS). CCS requires the capture of carbon dioxide (CO2) at a large industrial facility, such as a power plant, and its transport to a geological storage site where CO2 is sequestered. If implemented, CCS could allow fossil fuels to be used with little or no CO2emissions until alternative energy sources are more widely deployed. Large volumes of CO2 are most efficiently transported by pipeline and stored either in deep saline aquifers or in oil reservoirs, where CO2 is used for enhanced oil recovery (EOR). This thesis describes a suite of models developed to estimate the project-specific cost of CO2 transport and storage. Engineering-economic models of pipeline CO2 transport, CO2-flood EOR, and aquifer storage were developed for this purpose. The models incorporate a probabilistic analysis capability that is used to quantify the sensitivity of transport and storage cost to variability and uncertainty in the model input parameters. The cost of CO2 pipeline transport is shown to be sensitive to the region of construction, in addition to factors such as the length and design capacity of the pipeline. The cost of CO2 storage in saline aquifers is shown to be most sensitive to factors affecting site characterization cost. For EOR projects, CO2 storage has traditionally been a secondary effect of oil recovery; thus, a levelized cost of CO2 storage cannot be defined. Instead EOR projects were evaluated based on the breakeven price of CO2 (i.e., the price of CO2 at which the project net present value is zero). The breakeven CO2 price is shown to be most sensitive to oil prices, losses of CO2 outside the productive zone of the reservoir, and reservoir pressure. Future research should include collection and aggregation of more specific data characterizing possible sites for aquifer storage and applications of these models to this data. The implications of alternative regulations and requirements for site characterization should also be studied to more fully assess cost impacts.

The CCSReg Project is an interdisciplinary project which aims to design and facilitate the rapid adoption of a U.S. regulatory environment for the capture, transport and geological sequestration of carbon dioxide. Our objective is to assure that CCS will be done in a manner that is safe, environmentally sound, affordable, compatible with evolving international carbon control regimes (including emissions trading) and socially equitable. The project is anchored in the Department of Engineering and Public Policy at Carnegie Mellon University. Other members of the project team are located at the Hubert H. Humphrey Institute of Public Affairs at the University of Minnesota, the Institute for Energy and the Environment at the Vermont Law School, and the Washington, DC law firm of Van Ness Feldman.

This document brings together the five Technical Reports prepared under this contract to document enhancements made to the Integrated Environmental Control Model (IECM). Additional documentation of the model prepared under previous contracts is available at the IECM Web site: http://www.iecm-online.com. Table of Contents Volume I: Wet Cooling Tower Model Volume II: Air Cooled Condenser Model Volume III: Plant Water Usage Model Volume IV: Updates to PC and IGCC Plant Models Volume V: CO2 Transport and Storage Models

Large reductions in carbon dioxide (CO2) emissions from fossil fuel use will be required to stabilize atmospheric concentrations of CO2 [1-5]. One option to reduce CO2 emissions to the atmosphere from large industrial sources— particularly fossil-fuel fired power plants—is carbon capture and storage (CCS); i.e., the capture of CO2 directly from anthropogenic sources and disposal of it in geological sinks for significant periods of time [6]. CCS requires CO2 to first be captured and compressed to high pressures, then transported to a storage site, where it is injected into a suitable geologic formation. Each of these steps—capture, transport, and storage—is capital and energy intensive, and will have a significant impact on the cost of production for electricity or other industrial commodities produced using CCS. However, with appropriate policy incentives, CCS could act as a potential “bridging technology” that would achieve significant CO2 emission reductions while allowing fossil fuels to be used until alternative energy sources are more widely deployed.

Cost estimates for CO2 capture and storage (CCS) systems typically focus on details of the CO2 capture process and make simplistic assumptions about the cost per ton of CO2 for the transport and storage components of the system. These ad hoc assumptions ignore the large variability in the storage cost from site-to-site caused by variation in storage reservoir characteristics. Moreover, the typical costs of storage that are widely applied in CCS cost estimates do not fully consider the cost of site characterization and operational monitoring. To address this problem, we have recently developed an engineeringeconomic model for geological storage in deep saline formations. In this paper we briefly describe the newly-developed performance and cost models for CO2 storage in deep saline formations, and use these models to develop a range of cost for CO2 storage. The range of cost is explored using four cases, representing different types of potential storage reservoirs. Results from the four case studies show considerably different capital costs and, consequently, levelized costs of CO2 stored. In addition, the sensitivity of CO2 storage cost to variability and uncertainty in model input parameters for one of the case studies is examined. These results show clearly that the cost of CO2 storage in saline formations is most sensitive to factors affecting site characterization costs, which have been significantly underestimated in most past studies, and are highly dependent on future regulation of geological storage projects.

This paper examines two questions: (1) in a high oil price (and operating cost) environment what are typical breakeven prices for CO2? and, (2) are these prices sufficient to incentivize development of large-scale CCS projects? To address these questions we have developed an engineering-economic model for geological storage of CO2 through EOR. In this paper we briefly describe the performance and cost models for CO2-flood EOR, and use them to estimate the breakeven price for CO2 as a function of significant variables. In particular, the relationship between breakeven CO2 price and oil price is developed for four illustrative cases, all of which are, or were, operating EOR projects in North America. The sensitivity of the breakeven CO2 price to variability and uncertainty in reservoir characteristics and other model input parameters is also examined in detail for one of the cases.

This report is an account of research sponsored by the U.S. Department of Energy’s National Energy Technology Center (DOE/NETL) under Contract No. DE-AC21- 92MC29094.

What does it take to establish geological sequestration (GS) of CO2 as an acceptable method of greenhouse gas emissions reduction?

Geological sequestration of CO2 through Enhanced Oil Recovery (EOR) presents an opportunity to enhance significant emissions reductions.

In recent years, global concerns about greenhouse gas emissions have stimulated considerable interest in CO2 capture and storage (CCS) as a potential “bridging technology” that can achieve significant CO2 emission reductions while allowing fossil fuels to be used until alternative energy sources are more widely deployed. To date, the literature in this field has focused most heavily on CO2 capture technologies, which are believed to be the most costly components of a CCS system. Far fewer studies have addressed the costs of CO2 transport and storage in comparable detail. Most commonly, transport and storage costs are either omitted from cost analyses, or reported simply as a cost per ton CO2 with little or no detail as to the basis for such estimates. Our review of the CCS literature reveals frequent inconsistencies and lack of clarity in defining the scope of the CO2 capture, transport and storage components, with the result that some CCS cost elements—especially the significant costs of CO2 compression—often are double-counted as parts of both the CO2 capture cost and the CO2 transport/storage cost.