Control Your Energy Destiny

Ethanol producers aren't completely at the mercy of the natural gas markets or the electrical grid. The sooner plants are finding that out, the sooner they are improving their bottom line.
By Dave Nilles | August 01, 2006
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It's a well-known and oft-repeated statistic. Energy is the second highest input cost of fuel ethanol production, making up approximately 20 percent of a typical ethanol plant's budget. Fluctuating energy prices are proving that alternative sources of power—and reliable service—are critical to maintaining production levels and achieving profit.

Ethanol producers are busily studying ways of limiting the impact of variable energy prices, and analysts like U.S. Energy Service's Matt Haakenstad say ethanol plants should own and manage their energy assets whenever possible. "Control your own energy destiny," he said, during a June 21 FEW session titled, "Energy Integration: Optimizing Your Energy Costs." During that and another energy-related session at the conference, it was firmly established that maximizing competitive energy options early and often in an ethanol plant's lifespan can make all the difference in collecting a return on investment.

Here, EPM takes a look at two prime case studies in energy ingenuity. The first case study looks at a veteran producer battling harsh winters without a firm natural gas supply.

Alternatives for Alchem
Located in Grafton, N.D., Alchem LLP has the distinction of being the nation's second northern-most ethanol plant. With its location in rural northeastern North Dakota come several challenges—the foremost being its historically limited ability to obtain a steady supply of natural gas.

For some ethanol plants, interruptible natural gas service is worth looking into, Haakenstad said, especially if it means not paying the premiums associated with firm supply. However, Alchem was experiencing extended downtime due to lack of steady gas supply for its three natural gas boilers and two gas-powered dryers. Change was in order for the 10.5 MMgy plant, and Alchem officials began considering options.

Enter Itasca Power Co. and Novaspect Inc. Itasca Power is a 10-year-old cogeneration equipment and project development company based in Spring Lake, Minn. The company acted as the technical construction manager for a combustion turbine and waste heat recovery boiler project installed at Lena, Ill.-based Adkins Energy. Novaspect is a process management company with offices throughout the Upper Midwest

The companies combined to introduce Alchem to fluidized bed technology. Itasca Power managed the design and construction of the modification and retrofit of two coal-fired fluidized bed boilers at the plant. In doing so, the company handled the installation and integration of an atmospheric fluidized bubbling bed combustor that's coupled with a waste heat recovery unit and air pollution control equipment.

The objectives of the project were to reduce energy costs, curtail natural gas usage, take advantage of available solid fuel and meet new emissions regulations.

Alchem faces several challenges in installing the new equipment. The plant—originally a potato processing facility—hadn't seen many updates throughout the years. In fact, much of the plant's control equipment had been in place since the 1950s. In addition, Novaspect's Larry Link, who spoke in "Energy Resources from Gasification and Fluidized Bed Technologies," said there is minimal documentation available on the equipment.

The project moved ahead in two phases. The first phase involved demolishing and retrofitting existing control and process equipment, and training operators. The lack of an experienced work force for this type of project proved challenging to the project, as did the extreme cold. Temperatures dipped 40 degrees below zero during the winter. Workers also had to deal with tight construction areas around existing structures. Link said the group had to use "creative construction due to confined areas."
The second phase of the project revolved mainly around designing and installing the fluidized bed system. An abbreviated list of activities included process design and plant redesign, civil and structural engineering, electrical rework, relocating the existing main burner, installing new gas boilers, ductwork fabrication and installation, rebuilding the fluidized bed furnace, and installing a fuel delivery system, as well as an ash/sand separation system and all the infrastructure involved. The new major equipment includes a heat recovery steam generator, economizer, baghouse and induced draft fan.

The new fluidized bed system has been in operation for less than one year, but it has already provided several benefits. Alchem has seen no curtailment issues, and with waste-heat recovery, the facility has achieved a lower overall per-gallon production cost. The plant has started to minimize downtime and has opened the door to another option—fuel source flexibility. While an Alchem official told EPM in May that the plant operates nearly 100 percent on coal, Itasca Power's Dean Sedgwick said the plant could eventually use biomass for fuel. "In our opinion, coal is a very good transition fuel," he said.

Other plants are already taking advantage of the opportunities biomass provides.

Beating Power Loss and Spiking Gas Prices
At times, ethanol producers expect to be lightning rods. Small rural communities often have heated debates over whether or not to allow an ethanol plant to become part of its landscape and local economic base.

However, ethanol plants can also literally be a lightning rod. Oftentimes, these shining stainless steel facilities with their towering bins and emissions stacks are the tallest objects for miles on the level prairie, making them a prime target for lighting strikes.
For some plants, lightning strikes can be little more than a potential hazard. For others, it can be a financial drain due to power outages wreaking havoc on the production line. Last year, one Minnesota plant suffered a power outage shortly after conducting a maintenance shutdown. The outage caused the heat exchangers to become fouled, requiring additional unplanned maintenance that ran into six figures.

Haakenstad said more companies experience these problems than many think. He suggests looking at an electric company's reliability definition to determine the possibility of frequent power outages.

Some facilities take power outages into their own hands by using backup power systems to alleviate blips in power supply. A handful of plants are looking to completely eliminate reliance on the electrical grid.

While its primary intention is to eliminate natural gas usage, Central Minnesota Ethanol Co-op's (CMEC) gasification system offers the pleasant side effect of allowing it to conduct a smooth, controlled shutdown in the event of a power outage.

CMEC, a 20.5 MMgy ethanol plant located in Little Falls, Minn., held a ceremonial groundbreaking in July 2005 on its unique biomass gasification system (See EPM's "Turning Off the Valve," September 2005), which will use wood waste instead of natural gas to power the plant.

Equipment for the project arrived on-site last fall. At press time, the gasification system was slated to come on line in early July. The reasons for the system are varied, as are its benefits. CMEC, as all Minnesota ethanol plants, was under pressure from the U.S. EPA, the Minnesota Pollution Control Agency and the U.S. Department of Justice to lower its emissions. Plant officials used it as an opportunity to reduce energy usage altogether.

Sebesta Blomberg & Associates Inc. developed the gasification system for CMEC. Primenergy LLC provided the gasification and thermal oxidation systems. Sebesta Blomberg's Cecil Massie, also a presenter in the "Energy Resources" session, said CMEC was one of the few companies that didn't enter into a consent decree with the aforementioned regulatory agencies to install a thermal oxidizer. While a thermal oxidizer would have indeed sufficiently reduced emissions, it also equates to higher natural gas usage. CMEC officials decided to look at other options.

The gasification technology CMEC implemented is already proven in the rice-hull industry, Massie said. It operates through oxygen-starved partial oxidation of solid fuel to produce synthesis gas, which is a mixture of carbon monoxide and hydrogen used as a substitute for natural gas. The goals of the project were to achieve regulatory compliance with the volatile organic compounds limit, protect shareholder equity over time and reduce overall operations cost. "This is a classic make-or-buy decision," Massie said. "We chose to essentially make our own gas."

CMEC will now be using wood waste from local sawmills. The project did involve some modifications to the dryer, such as redoing ductwork. The gasifier essentially runs side-by-side with the dryer. It takes in dryer gases and burns them, in effect acting as a thermal oxidizer.

Massie said educating investors and bankers on the merits of cost reduction versus expansion was a hurdle, especially in light of the payback expansions are bringing other facilities. For a 20 MMgy plant, a $15 million investment will take a four-year payback, according to Massie. That's predicated on gas prices in the $6 or $7 range. "It's a matter of spending capital today to avoid operating cost tomorrow," Massie said.

Securing a biomass source is the essential first element in making a project such as CMEC successful. "Being biomass-based and off the world prices of oil and gas puts us at a sustainable economic advantage," Massie said.

Studying for the Future
The flexibility of Alchem and CMEC's energy systems allows the plants to use biomass instead of fossil fuels. Considering today's energy and feed market economics, distillers grains—or some derivative of it—is perhaps slowly becoming an accepted option as a fuel source.

Massie said distillers grains contains nearly enough energy to meet the energy needs of an ethanol plant. In addition, each acre of corn produces enough biomass to convert that acre's grain to ethanol.

Winnebago, Minn.-based Corn Plus has reduced its natural gas usage by 52 percent through burning its "syrup," according to General Manager Keith Kor, who also spoke in the June 21 "Energy Integration" session. Others may follow suit.

Doug Tiffany of the University of Minnesota's (UM) Department of Applied Sciences is heading a study considering distillers grains as a fuel source. The study, sponsored by Xcel Energy and the Agricultural Experiment Station at UM, is intended to develop technical data and economic tools to guide the decisions of dry-grind ethanol plants seeking to enhance profits by using biomass to produce process heat and electricity.

The research partners of RMT Inc. and the Biosystems and Agricultural Engineering Department at UM are currently analyzing samples of DDGS, DDG, concentrated solubles and corn stover. Plants taking part in the study are Ace Ethanol in Stanley, Wis., Badger State Ethanol in Monroe, Wis., Corn Plus, Chippewa Valley Ethanol Co. in Benson, Minn., and Agri-Energy in Luverne, Minn.
Researchers are now conducting analyses of the combustion and emissions characteristics of the biomass sources under various protocols in hopes of determining the capital and operating costs of varying technologies. The systems being tested include syrup combusted in a fluidized bed, DDGS combusted in a fluidized bed, DDGS gasified to produce synthesis gas that can be used in several places in the plant, corn stover combusted in a fluidized bed and corn stover gasified in a fluidized bed.

The results are expected to show if biomass can provide process heat, a combination of process heat and electricity needs, or that same combination in addition to selling some energy back to the grid. RMT is conducting the combustion and emissions modeling.
The study is ongoing with information available at www.biomasschpethanol
.umn.edu
.

Tiffany said an earlier biomass-related master's thesis conducted by Diego Nicola at UM showed that many problems were related to storage. That study depicted some of the additional capital costs for a biomass facility, such as handling, storage, equipment, emissions controls and ash disposal.

Nicola's study stated biomass plants require an additional maintenance expense of $180,000 per 50 MMgy of ethanol. Biomass plants also require one more employee per shift per 50 MMgy. The study found that a natural gas plant produces undenatured ethanol for 34,000 Btus per gallon while a coal or biomass plant produces it for 37,000 Btus per gallon.

Nicola also made conclusions about the ash disposal required in fluidized beds and gasifiers. The study found a 5 percent ash disposal for coal and 7 percent for corn stover. At $15 per ton, ash disposal costs add approximately $80,000 per year for a 50 MMgy plant.

Corn Plus is planning to put in a unit to pelletize its fluidized bed ash, which will be sold for use as fertilizer. Kor said the plant is also considering building two wind towers in its quest for energy independence.

Finally, Nicola's study took into account the limestone needed to counter the sulfur produced in a coal or biomass plant. The added expense was up to $12,000 per year for a 20 MMgy plant and $83,000 per year for a 50 MMgy plant.

Managing Energy Cost Inputs
While several individual ethanol producers are striking out on projects aimed at eliminating reliance on energy cost variance, all ethanol projects can use steps to help control energy cost inputs, Haakenstad said.

In the preliminary phase of a project, ethanol companies need to focus on obtaining the optimal energy supply. Create competition whenever possible, Haakenstad said. Also consider on-site power generation, such as a diesel or natural gas standby, cogeneration and heat recovery evaluations.

Haakenstad said that plants taking ownership of electrical substations and transformers are responsible for maintaining them.
During the construction phase, ethanol projects should investigate purchasing power at large pooling points in the supply chain, Haakenstad said. This provides higher liquidity, more competition and lower seller margins. Establishing credit with suppliers, and negotiating long-term distribution and/or transportation agreements can also lower energy costs.

"If you're going to do a plant expansion, which you very well might down the road, make the utility suppliers aware of your good load factor," Haakenstad said. "It's probably one of the best load factors they have on their system. Many of the plants we work with have a 90 percent or better load factor."

Risk management strategies and an optimal hedging execution process contribute to more stable energy prices once operating. Haakenstad suggested consolidating accounts and double-checking bills.

Energy cost and service terms can be negotiated and controllable, Haakenstad said. While this may be true, world energy prices are not so easily controlled. That's why such a focal point is moving toward that 20 percent of an ethanol plant's budget. EP

Dave Nilles is an Ethanol Producer Magazine staff writer. Reach him at dnilles@bbibiofuels.com or (701) 373-0636.