Each year, National Engineers Week falls on the week of February 22 — George Washington’s actual birthday—in part to commemorate a man who is considered the nation’s first engineer. But not only that, the week is meant to highlight the contributions engineers have made to the world as we know it. Just think about that for a minute as you read this on a display screen that wouldn’t exist if not for engineering ingenuity. The list of accomplishments engineers have made to our society and the history books is massive.
From our perspective, we can highlight many areas in which Alden engineers have contributed to the annals of history. From testing airplane propellers and missile ballistics to the work on dam safety and fish passage and protection programs, we’ve had a hand in shaping our world throughout our 125 years of continual operation.
But trying to find a singular project to discuss for this week? That task is nearly impossible. So, that’s when I asked Dave Anderson, Senior Vice President and Chief Technology Officer to weigh in. Besides wanting to know where his present for National Engineer’s Week was (in the mail, of course), he offered some great insight.
“If I had to point to one thing we’ve done at Alden that has had the biggest impact on society – each and every one of us—it would be our work on power plant emission controls,” Dave says. “While we have made incredible contributions in so many areas, nothing is as important as the air you and I breathe.”
Dave is referencing the flow modeling work we’ve done to help design, integrate, and optimize the performance of emission control systems to meet clean air standards.
The Clean Air act has evolved throughout the years along with the research and techniques for controlling and monitoring power plant emissions. As programs and provisions were rolled out, the role of flow modeling and the subsequent design work needed to make emission control systems run efficiently became even more critical. And that’s where our engineers coupled their technical expertise with laboratory modeling techniques that use state-of-the-art computational fluid dynamic (CFD) modeling and traditional reduced scaled physical modeling to provide realistic, reliable solutions for each and every project.
Our engineering design, investigation, and evaluation of flow-related systems include experience with NOx, SOx, Hg, particulate collection system design and operation, carbon capture and sequestration, stack liquid discharge, dust deposition and entrainment, system optimization and pressure loss reduction.
For instance, we used computational and scaled physical modeling to simulate a planned Selective Catalytic Reduction system (SCR ). The objective of the project was to design internal flow controls and an ammonia injection system to optimize the NH3:NOx ratio entering the catalyst layers, ensure uniform flue gas velocity & temperature distributions within the catalyst, minimize the potential ash deposition, and reduce the non-recoverable pressure losses through the SCR system.
In another study, Alden engineers used CFD and scaled physical modeling to evaluate and optimize the performance of a planned Wet Flue Gas Desulphurization (WFGD) design by simulating the flue gas flow distributions entering and throughout the WFGD spray tower. Modifications to the inlet ductwork and within the WFGD were made to improve the gas flow and SO2 removal efficiency. The results of the study provided flow controls and a spray nozzle injection grid design to minimize liquid pullback while providing uniform spray coverage, which resulted in optimized SO2 removal.
Another client contracted us to design a quench spray header system to reduce stack inlet temperatures in order to protect a Pennguard lining during Flue Gas Desulphurization (FGD) bypass mode. Our team used CFD simulations to design a quench system that not only lowered the stack inlet gas temperature, but ensured full evaporation of the injected liquid, avoided wall wetting, and minimized gas temperature gradients entering the stack. Read more about the bypass quench system design here.
We have also used scaled physical modeling to simulate a planned Electrostatic Precipitator (ESP) upgrade and to design flow controls and perforated plates to optimize the flue gas velocity distribution entering the collection fields, minimize ash re-entrainment from the collection hoppers, and reduce the non-recoverable pressure losses throughout the system.
So what’s the end result of all this work and countless other emission control projects that have passed through our doors over the years? You’re breathing it. And for that, we can say it’s truly our contribution to making the world a better place for all of us.
As the US Nuclear fleet continues to age, and the availability of alternate sources of energy continues to rise, it is not surprising that we are seeing more news of permanent plant closures. The most recent announcements come from Entergy, stating they will shut down Palisades permanently on October 1st, 2018, and Indian Point in 2021.
For many of these plants announcing closures, the writing has been on the wall. In 2013, economist Mark Cooper, a Senior Fellow for Economic Analysis at the Institute for Energy and the Environment at Vermont Law School published Renaissance In Reverse, an interesting read on the factors that affect the viability of nuclear power economically. He provided a list of plants that face particularly significant challenges to operation, which is provided below.
Palisades (Repair impending, local opposition)
Ft. Calhoun (Outage, poor performance)
Nine Mile Point (Site size saves it, existing contract)
Fitzpatrick (High cost but offset by high market clearing price)
Ginna (Single unit with negative margin, existing contract)
Oyster Creek (Already set to retire early)
Vt. Yankee (Tax and local opposition)
Millstone (Tax reasons)
Clinton (Selling into tough market)
Indian Point (License extension, local opposition)
This list clearly correlates with recent announcements of plant closures, or plants that have already shut down. Mark listed some of the major local oppositions, but there are lots of challenges facing the aging nuclear fleet. Whether it is the aging workforce, political challenges, climate change, or aging components and obsolescence, there are many issues the aging fleets need to work through in the coming years.
With the challenges facing the future of existing plants, we need to be focusing not only on designing, but also on building, new nuclear reactors, lest we be left with only natural gas and coal for baseload power. PBS Newshour recently did a story on the future of nuclear, which was posted to their YouTube page, embedded below.
The focus of this short video was on new nuclear options, such as those being worked on by TerraPower, and molten salt coolant reactors. An interesting technology developer not discussed in the video is NuScale, working on Small Modular Reactors (SMR). PBS will be releasing a NOVA episode called The Nuclear Option, which will go into more detail and will air on January 11, 2017 at 9 pm. I look forward to watching!.
Stay tuned for additional discussion in the Alden Blog on the challenges facing the nuclear industry.
Attendees at the 2017 Alden Forum on Hydropower and Fish Passage
Based on presentations given by the various speakers, the primary takeaways from the forum include the following:
Cake consumed during a break at the 2017 Alden Forum, showing companies and agencies in attendance
The format and content of the forum was highly rated by the attendees and led to many in-depth and productive discussions. The setting appeared to be more conducive to open dialogue among all of the participants compared to typical relicensing meetings and agency consultations.
Planning for additional forums addressing other relevant topic areas related to fish passage and other environmental issues is underway by Alden staff, and may include hosting events in other regions of the U.S.
There is an interesting past and new future for the world’s largest batteries. For decades pumped storage plants have helped stabilize large power grids by supplying peak power support to base loaded nuclear and fossil fuel power plants across the United States and the world. Today, as many nations make a conscious move away from these generating sources toward renewable energy technology, such as solar and wind, and smaller micro grids, these behemoth batteries are finding new purpose. Keeping in the spirit of this green power revolution, it is imperative to keep the environmental impact of pumped power plants, and other power storage technologies, as low as possible.
Base loaded power plants, nuclear or fossil fuel, operate at full production 24 hours a day because they are difficult and slow to start and stop; however society’s power demand fluctuates dramatically throughout the day. In the morning and during business hours when most people are running home appliances or working with tools and equipment, the base load power may not be able to keep up. In contrast, at night when most of us are sleeping there is excess power. Historically, pumped storage plants used the excess power produced at night to pump water from a low reservoir to a higher reservoir, storing the power as potential energy in the water. Then during peak demand hours, the water is released through hydroelectric generators and electricity is resupplied to the grid. As with most supply and demand markets, the price of power is lower at night when there is excess and it increases during the day when demand is high. Pumped storage plants make money by buying low and selling high.
When generating power with a high fraction of non-hydropower renewable technologies, the supply issue may be very different; these power sources are intermittent and may not supply reliable power when it is needed. Going solar and generating with wind are viable low-carbon options, but we still want to run the oven and watch television on a dark and windless night. Large scale energy storage, such as pumped storage, is a necessary component for a reliable approach to green energy. Nuclear and fossil plants have historically managed the base load and continue to provide a significant fraction of the reliable power we have become accustomed to. Gas fired plants, which have been gaining popularity due to lower fuel prices, do better as peaking plants as these are much easier to start and stop. While they are typically very efficient they do have a carbon footprint.
Pumped storage is far from the only option for large scale power storage. There are dozens of methods in use and dozens more in development. The U.S. Department of Energy and private interests are spending millions of dollars each year hoping to come up with inexpensive and efficient alternatives. However, pumped storage is one of the most mature technologies, employing pump and turbine equipment that has been in use in the United States since 1930 (Popular Science 1930), and although the initial construction of a large facility may be a serious undertaking, the operating costs of a pumped storage plant are among the lowest (IEA 2014).
Figure 1: Physical model of a pumped storage intake at Alden
In keeping with the spirit of green energy it is important to keep the environmental impact of a pumped storage plant to a minimum. The development and flooding of the project’s reservoirs may displace wildlife habitat, and if the one or both of the reservoirs is directly connected to an active body of water there may be negative impacts such fish entrainment and sedimentation. These effects may be circumvented or minimized with proper design, but early planning and community interaction are also crucial.
In the last installment of this series, we discussed energy demand, energy supply, and the impact of the rapid growth of solar power on changing energy sources. Today, we continue with the effects of power prices, the importance of power storage, and offer some conclusions.
Price of Power
A significant portion of the United States electricity markets is split into hubs. Each hub is an independent energy market in which supply and demand set the price of electricity on a real time basis. A map of United States hub zones is shown in the following figure.
Daily electricity demand is primarily based upon the time of day and climate. As shown in Part I, more electricity is used during daylight and evening hours than night time. Very cold or very warm weather can add demand due to heating and cooling. Additional constraints on fuel costs and available supply add an extra layer of complexity. The cost of environmental mitigations for coal fired power plants, the lack of sufficient natural gas supply in certain markets like New England, and the recent addition of large amounts of intermittent renewables adds significant uncertainty and instability to real time power pricing. If supply exceeds demand in certain electricity hubs, negative power pricing can even occur.
These factors combine to create wide price swings in the cost of real time open market electricity pricing, as shown in the following plot from ISO New England. The figure shows the five minute open market pricing for the New England Hub for 03/02/2017. Prices for this day varied between -$150.13/MWh and $71.93/MWh.
For energy sources that have a high capital cost to construct and a marginal ability to throttle energy output in real time, highly volatile real time energy markets with negative pricing periods create a large amount of uncertainty. This uncertainty in the future price of markets makes new and continued investments in large power generating infrastructure unattractive.
In order to limit the impact of our changing energy demand and production, energy storage will need to be a major priority going forward. One major type of energy storage is hydroelectric pumped storage. This is a process by which water is pumped to a higher elevation during periods of high output and low demand, to be later sent through hydropower turbines to produce energy during peak demand periods. Alden has previously covered pumped storage on the blog so check that out for more information.
Massachusetts has an Energy Storage Initiative which intends to promote and support energy storage within the state. Late last year the state released the State of Charge, a Massachusetts Energy Storage Initiative Study. If the full length report seems daunting, there is an Executive Summary available which gives a good overview of the problem and some of the policy goals to help foster power storage in Massachusetts.
We have provided an introductory look into some of the factors that affect the changing energy climate in the United States. As we discussed in our first blog post, nuclear plants are facing major challenges with many shutdowns on the horizon. These closures will continue to change the landscape of how power is produced in the United States. Optimal solutions to this problem will need to include the growth of renewables and the next generation of nuclear, coupled with significant amounts of power storage if we are going to avoid the continued dependence on carbon emitting power options. Let us know in the comments below if there are any particular items you would like us to expand upon in future posts!
Recognition and Sources
All of our plots above came from either the US Energy Information Administration or ISO New England. They both have a wealth of information and we highly recommend you check them out if you are interested more information on these topics.
Special thanks to Will Fay for his assistance in the development of this post. He works in our Hydraulic Modeling and Consulting Group and is directly involved in Massachusetts power generation as an owner and operator of three hydropower plants.
Today’s entry comes from a guest blogger, Jim Walsh, President of Rennasonic, a small consulting firm specializing in turbine and pump performance testing and optimization of multi-unit hydroelectric power plants using ultra-sonic multi-path flow meters. Alden has partnered with Rennasonic for numerous turbine performance tests, providing supplemental flow measurements using dye dilution and current meter profiling.
As a hydropower electric power generating utility, how do I know when I should, or should not, invest in my equipment? The answer can be complicated due to many factors, including but not limited to: the current price of power, generating capacity, equipment age, and government regulations. To determine the performance of an installed hydropower turbine, the measurements of water flow, head, and power must be made within a reasonable amount of uncertainty. Generally speaking, flow is the most difficult parameter to measure in the field and, consequently, is the most expensive. The cost of measuring flow can seem unsurmountable for small hydropower owners, so the question becomes when testing expenditures yield a return on investment.
Field performance tests are often used only for large projects with Francis runners that have capacities greater than 50 or 60 MW. For these performance tests to be viable, a return on investment must be assessed, particularly because plants can have multiple units and the performance of the first replaced unit is often assumed to be representative of subsequent units. The author has been involved with test programs where the payback is perceived short, and the benefit cost relationship is easily greater than one. A recent project involved testing a 4 unit (50MW each) plant. This plant needed to have pre- and post-upgrade field tests on all 4 units for an energy analysis to support production tax credits (PTC) under the 2005 Energy Policy Act. The approximate cost of this test program, which occurred over a 4 year period, was $195,000. Some cost savings were available because the flow measurement was performed using previously installed acoustic transit time flow meters.
In order to qualify for PTC’s, models had to be created to predict the energy increase resulting from upgrades to the turbines. Inflows to the plant over an 8 year period were obtained and a computer model of plant operations was created. The model included the order in which each of unit would be dispatched. The historical inflows were used as inputs to the model, to determine the baseline energy production of the plant before any upgrades. Annual energy production from the model was compared to the Energy Information Administration (EIA) reported generation tables over the same period and the baseline model was found to be within 2% of the reported data for years when unit outages did not occur. Later, using newer characteristic curves obtained from field testing of the new units, a new dispatch table was created to represent the new plant model. Energy calculations were performed and compared to the baseline mode.
The results of the comparison yielded a 4.7% increase in annual energy production, on average. Using the current EIA average wholesale market rate of $45 per MWHR, annual expected gains in energy revenues can be calculated. The model projected increase was reduced to 2.7% to account for uncertainty in the model, yet the expected gain in revenue was still approximately $450,000 per year when all units are in service. The benefit cost ratio of this project is over 2.0 over a five year period, and the internal rate of return (IRR) calculates to 3% after 2 years and 26% after 5 years.
One can use these figures to determine that the same level of test effort applied to a lower capacity unit (25 MW x 4) can still be justified, because the benefit cost ratio will be 1.0 after 5 years and the IRR will be approximately ½ of the above example over the same time frame. In short, it makes sense to test all the units at plants having a combined capacity of 100 MW. One can also make the assumption that smaller plants having nameplate capacities of 50 MW and perhaps lower can justify the cost of field testing for at least one unit when transit time meters are installed.
Assuming transit time meters are not installed, the outlay increases by the cost of transducer fittings, electronics, transducers and the installation of the equipment. The sunk cost, or previously incurred unrecoverable cost, increases by slightly over $100,000. Under the same assumptions as above, the IRR becomes 15% after 5 years with a benefit cost ratio of 1.33. Even with the cost of the installation and equipment, it can make financial sense for similar capacity plants to initiate this program.
A view of the tailrace of a hydropower dam during performance measurement
As we discussed in our first blog post, there are many challenges facing the nuclear industry. One of the greatest is the current energy climate. There are many contributing factors to the general state of flux in energy production, which we would like to explore today. These challenges don’t just impact the nuclear industry, but also affect energy producers across generation types.
It may surprise you, but US energy consumption has effectively plateaued over the last 15 years. Below is a plot generated with the US Energy Information Administration Open Data Embedded Visualization Library. The EIA provides a wide range of information and data products covering energy production, stocks, demand, imports, exports, and prices; and prepares analyses and special reports on topics of current interest.
There are four sectors that are included when looking at total energy consumption. These include Residential, Commercial, Industrial, and Transportation, all of which are shown in the figure. As you can see, starting around the year 2000 the Total Energy Consumption has plateaued. The largest changes in trends have been experienced by the Industrial Sector, showinga significant decrease in consumption over that time. This is likely most attributable to a major focus on energy efficiency, which is improving consistently. There are still challenges, however, outlined in this US Department of Energy Report, which provides information on barriers to industrial energy efficiency.
The way energy is produced in the United States has changed dramatically over the last 15 years. Another plot from the EIA is provided showing the change in net generation for coal, natural gas, nuclear, hydroelectric and renewables. Each supply type is zeroed relative to its 2001 value for comparison.
It is obvious from this plot that while nuclear and hydroelectric production has remained relatively constant on an absolute basis, coal has suffered significantly while natural gas and renewables rise.
Solar Growth/Capacity Issues
Utility scale solar is the fastest growing renewable power generation source in the US on a percentage basis, as shown below. The figure shows the growth of various renewables as a percentage change from 2001.
The growth of solar, particularly in the Alden headquarters home state of Massachusetts, has been significant. Below is a plot from ISO New England showing the Projected Cumulative Growth in New England Solar Power. Starting in January of 2010, there was a minor amount of PV capacity in New England, however by 2025 they predict 3.27 Gigawatts of PV capacity.
Next week, we will continue this thread with a discussion of power prices and power storage, and how these effect the changing energy climate.