Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup, and Oxygen Separation Equipment; Task 1: Cost Estimates of Small Modular Systems

This deliverable is the Final Report for Task 1, Cost Estimates of Small Modular Systems, as part of NREL Award ACO-5-44027, ''Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup and Oxygen Separation Equipment''. Subtask 1.1 looked into processes and technologies that have been commercially built at both large and small scales, with three technologies, Fluidized Catalytic Cracking (FCC) of refinery gas oil, Steam Methane Reforming (SMR) of Natural Gas, and Natural Gas Liquids (NGL) Expanders, chosen for further investigation. These technologies were chosen due to their applicability relative to other technologies being considered by NREL for future commercial applications, such as indirect gasification and fluidized bed tar cracking. Research in this subject is driven by an interest in the impact that scaling has on the cost and major process unit designs for commercial technologies. Conclusions from the evaluations performed could be applied to other technologies being considered for modular or skid-mounted applications

Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup, and Oxygen Separation Equipment; Task 2: Gas Cleanup Design and Cost Estimates -- Black Liquor Gasification

As part of Task 2, Gas Cleanup and Cost Estimates, Nexant investigated the appropriate process scheme for removal of acid gases from black liquor-derived syngas for use in both power and liquid fuels synthesis. Two 3,200 metric tonne per day gasification schemes, both low-temperature/low-pressure (1100 deg F, 40 psi) and high-temperature/high-pressure (1800 deg F, 500 psi) were used for syngas production. Initial syngas conditions from each of the gasifiers was provided to the team by the National Renewable Energy Laboratory and Princeton University. Nexant was the prime contractor and principal investigator during this task; technical assistance was provided by both GTI and Emery Energy

Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup, and Oxygen Separation Equipment; Task 2.3: Sulfur Primer

This deliverable is Subtask 2.3 of Task 2, Gas Cleanup Design and Cost Estimates, of NREL Award ACO-5-44027, ''Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup and Oxygen Separation Equipment''. Subtask 2.3 builds upon the sulfur removal information first presented in Subtask 2.1, Gas Cleanup Technologies for Biomass Gasification by adding additional information on the commercial applications, manufacturers, environmental footprint, and technical specifications for sulfur removal technologies. The data was obtained from Nexant's experience, input from GTI and other vendors, past and current facility data, and existing literature

Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup, and Oxygen Separation Equipment; Task 9: Mixed Alcohols From Syngas -- State of Technology

This deliverable is for Task 9, Mixed Alcohols from Syngas: State of Technology, as part of National Renewable Energy Laboratory (NREL) Award ACO-5-44027, ''Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup and Oxygen Separation Equipment''. Task 9 supplements the work previously done by NREL in the mixed alcohols section of the 2003 technical report Preliminary Screening--Technical and Economic Assessment of Synthesis Gas to Fuels and Chemicals with Emphasis on the Potential for Biomass-Derived Syngas

Lowering Energy Spending Together With Compression, Storage, and Transportation Costs for Hydrogen Distribution in the Early Market

International audienceThis chapter is dedicated to the optimization of cost and energy consumption for compression, transportation, and storage of hydrogen for vehicle refueling in the current hydrogen emerging market. Thus, it considers only small refueling stations (20–200 kg/day) and current costs. It considers two cases: the case of a refueling station on the site of the hydrogen production and the case of a production unit supplying hydrogen to several distant refueling stations.In the case of production and distribution located on the same site, no transportation has to be considered, and the energy consumption is mainly due to hydrogen compression and cooling. In a reference case corresponding to good current practice, the study calculates an energy need of 3.5 or 4.4 kWh per kg of hydrogen transferred to a car tank at 35 or 70 MPa, respectively. It then shows that this need can be reduced by > 25% through judicious use of four or five stages of buffers organized in a pressure cascade for the filling of a tank at 70 MPa. Whereas the total volume of the staged buffers is higher than the volume of a single very-high-pressure buffer (VHPB), the investment cost is only slightly higher; then the energy saving results in short payback times for the extra investment in staged buffers.In the case of a production unit supplying hydrogen to several distant hydrogen refueling stations, energy for transportation by truck and for re-compression on the distribution site must be added. Current off-site distribution practices are used as a reference case; it considers the transportation of hydrogen in 20 MPa steel bottle bundles or trailer tubes and the re-compression of all the hydrogen to the VHPB. To lower the energy spend, solutions are proposed and quantified, such as using small transportable containers of higher pressure light composite bottles and bypassing the compressor as much as possible. Energy needs and CO2 emissions are estimated and compared for the reference case and the innovative cases. The study shows that, even if the investment in composite bottles is high, the resulting overall cost is definitely lower and CO2 emissions can largely be decreased. The size effect appears very important; cost decreases by 60% from 20 to 200 kg/day

Implementing Power-to-Gas to provide green hydrogen to a bitumen upgrader

Summary Hydrogen is an important commodity in the processing of intermediate bitumen products into a finished petroleum product and for upgrading bitumen into synthetic crude. With the continued extraction of bitumen-rich material from Alberta's oil sands project, there is an opportunity to reduce the greenhouse gas emissions of upgrading and refining operations by using electrolytically produced hydrogen in place of hydrogen produced by steam methane reformation. Recently, a bitumen upgrading facility had been proposed for the city of Sarnia, Ontario because of its pre-existing petroleum processing infrastructure. Using the Ontario electrical system, which has a lower emissions factor than Alberta, the use of electrolytic hydrogen could result in a significant reduction of greenhouse gasses. In this paper, the objective is to determine an optimal system configuration for reducing greenhouse gas emissions while maintaining a low system cost. The analysis is performed with General Algebraic Modelling System tool, a mixed-integer linear optimization in addition to a simple model in Visual Basic. For each case, an economic and environmental analysis is performed including the use of cap-and-trade values for the price of carbon emissions, which are applied to determine the overall economic impact of the emissions reductions. Copyright © 2016 John Wiley & Sons, Ltd