"Microturbines fit into the overall distributed-generation mix," says Jeffrey Pierce, vice president of SCS Energy in Long Beach, CA, but the qualifier is the fuel. Although originally designed to be fired by natural gas, propane, or diesel, Pierce thinks where such "free fuel" as landfill or digester gas is available, microturbines might be just the ticket for beating high power costs. Buying natural gas at inflated prices in places like Ohio and trying to compete against coal-fired electricity, however, isn't an attractive economic proposition, even if you can manage to utilize the heat from the turbines in a combined heat and power (cogeneration) system.

A wastewater treatment plant in Lancaster, CA

Microturbines are smaller versions of the megawatt machines widely used in large distributed-energy installations. Some designs use the turbine to drive an off-the-shelf generator through a gearbox. A more unconventional approach is to use a single-shaft turbine with a high-speed, permanent magnet generator to produce variable-voltage, variable-frequency AC power. The NOx emissions target—often a major factor in deciding on turbine-generated power—is less than 9 ppm in practical operating ranges. Recuperated microturbines recover heat from the exhaust gas to boost the temperature of combustion and increase efficiency. Unrecuperated units have lower efficiency but higher exhaust temperatures, which makes them better suited to applications that can recycle the heat. Microturbines are low-maintenance and run basically unattended. On a 24/7, 365-day basis, the typical useful life of a commercially available unit ranges from 40,000 to 80,000 hours—approximately 10 years—with overhauls. Installed cost (without incentives) is typically from $1,500 to $3,000/kW, depending on the difficulty of the fuel and site integration.

Given its current high electrical rates and strict air-quality standards, California has become a hotbed of early-adopter microturbine activity. At Bentley Simonson Inc. (BSI), an independent oil and gas producer based in Ventura, CA, that operates seven oil fields in Los Angeles and Ventura Counties, President and CEO Clif Simonson was on the lookout for a way to rescue what appeared to be a nonpayout project. Faced at one oil field with having to install a new gas-production plant to meet changing gas standards, Simonson's problem was how to dispose of what typically is considered waste—what the industry calls overhead vapor. "This is very challenging in a tight urban environment," says Simonson. "You can sell it to a company that fractionates it to make propane, but there's not a good margin in that, or you can flare it, which is not legal in Los Angeles. Then we got to thinking: What if we were able to offset our cost of electricity on that site by using overhead vapors to generate electricity? Suddenly we had a project that would pay off—and [pay off] fairly quickly."

Working first with Honeywell before it withdrew from the microturbine market and then with Ingersoll-Rand Energy Systems, BSI installed a 70-kW microturbine fueled by overhead vapors from its gas plant to generate electricity that runs lift systems, pumps, and gas-plant compressors at the oil field. At Ingersoll-Rand, George Wiltsee confirms that the 70-kW recuperated microturbine BSI first installed and the 250-kW unit it has on order have an efficiency of 29% and 32%, respectively. Electrical output is at 480 V and 60 cps.

BSI's initial installation included one 70-kW microturbine, which is configured to burn 1,200- to 1,600-Btu fuel and switchgear. "Regarding the fuel supply, it's rare that associated gases are pure straight from the well—although if conditions are right, you may be able to operate a turbine on that ‘raw' gas," says Simonson. "The fuel characteristics most important for microturbine operation include the combined Btu content of the various constituent gases, the types and quantities of various contaminants, and the flow rate and the gas pressure in the collection systems. You can purchase an integrated fuel conditioner from Ingersoll-Rand that protects the turbine from performance losses or damage by providing levels of purity and pressure that are within the specific engine tolerances. Our gas processing provides the correct type of fuel as a byproduct." As Simonson describes it, "once separated from the crude oil pumped at the field, the vapor flows through the LTS [low temperature separator]; the liquids are removed from the raw feed gas, compressed, and chilled; and unwanted contaminants are eliminated. The natural-gas liquids are stabilized, and the byproducts of this heating process, overhead vapors, are then compressed to approximately 80 psig and then flow through a small receiver tank and into the microturbine. Software controls the flow rate." (Conditioning is typically required for other opportunity fuels, both high-Btu and low-methane, such as biogas. Manufacturer Ingersoll-Rand can provide a fuel conditioner as part of its microturbine package.)

BSI's first 70-kW unit was installed in February 2003 and so far has logged approximately 3,600 hours and generated 216,000 kWh of electricity, and the company has gone on to plan the installation of microturbines in three other oil fields. Simonson estimates his initial $75,000 investment has resulted in a monthly savings on electricity of just more than $3,000 at the field where it's operating.

"I was pretty shocked by the numbers," says Simonson. "But a project like this has to be analyzed very thoroughly. People get fooled into thinking it's as simple as putting in a turbine and buying gas from the gas company. We looked at reciprocating engines for this project, but they require catalytic converters, fuel-air ratio controllers, and a host of other equipment that make the project much more challenging and hard to permit. Plus, the cost of maintenance is higher. These considerations, coupled with a 42% DG [distributed-generation] incentive from the California Energy Commission, helped offset the capital cost, and a one-time microturbine exemption from the SCAQMD [South Coast Air Quality Management District] clinched the decision."

Like any distributed-energy system, coupling power with load is crucial. BSI evaluated running parallel with the grid, which would mean covering base load with the turbine and peak load with electricity from the utility, and running independent of the grid, which would require a steady state load (not the case with BSI facilities) and gearing up to cover the peak and exporting the excess. Simonson opted for a parallel grid system in all of the company's four microturbine installations and to size the turbines to pick up 60–95% of the base load.

A BSI site in East Los Angeles

Not long after the first turbine was installed, the company again found itself faced with having to alter its production process to meet shifting regulations at another of its Los Angeles County fields. "To meet the new regulations, we will be generating even more of these overhead vapors at this site," says Simonson, "and once again we went to a microturbine solution, which we now consider an important tool for meeting changing regulations. In this case, five 70-kilowatt microturbines will be installed for a combined capacity of 350 kilowatts." Although Ingersoll-Rand also offers a 250-kW unit, Simonson says the choice of the five smaller turbines was deliberate. "Typically the utility bills you for how much electricity you use; for your VARS, which is your power factor; and for your demand charge, which reflects spikes in demand for power off the grid. We got to thinking about how much it would cost us at this facility when our turbines went down for their monthly air-filter change and minor maintenance, and although we had originally specified one 250-kilowatt unit and one 70-kilowatt unit for that site, we went back and modeled the system assuming [it would have] all 70-kilowatt units with only one or two going down at a time, which would reduce our exposure to utility demand charges. The multiunit scenario resulted in a major savings in demand charges. You've got to know all of this information: the demand charges, the tariffs, the disconnect charges, the difference between your summer and winter bill."

Although most of its oil field operations don't avoid the chance to use heat for cogeneration, BSI eventually found an opportunity to take advantage of combined heat and power (CHP) incentives. "At our Sansinena Field, we will be operating a diethanol amine [carbon dioxide extraction] unit that normally uses a gas-fired burner as part of the process. We looked at all that hot air coming off of our microturbines and asked our process engineering firm to come up with a heat-transfer solution that would allow us to take the heat from the turbine exhaust and heat our DEA plant. Capturing the CHP incentive was a huge driver for that installation." Plans at this Saninena Field (which is served by a different utility and is not subject to excessive demand charges) call for installing one 250-kW microturbine, which will be combined with the waste heat recovery unit, and two 70-kW units for a combined capacity of 390 kW. Anaheim, CA–based Vanson Engineering's Projects Manager Dick Scott, who designed the Saninena CHP fix, estimates the field's power-generating facility will recover about 700,000 Btu or about 30–32% of the waste heat and then run it back through the DEA unit. Based on last year's electrical expenses, BSI believes that this equipment should help reduce electrical costs by $250,000/yr. over the entire project.

"In a turbine, you have air at about 10 times the volume of gas going into it," says Scott.

With a 250-kilowatt turbine, you'd have about 14,000 pounds per hour of a 500° gas; with a reciprocating engine of the same size, it would be 1,000 pounds. So in one sense, the turbine is less efficient than the internal combustion engine, but overall the turbine is more efficient because you're taking advantage of all the air you're heating up, which is another thing to consider in CHP applications. You wouldn't even attempt to recover the heat off of a corresponding-size reciprocating engine—there's just not enough available to make it worthwhile, whereas on a microturbine equivalent to 300 horsepower, you can recover maybe 800,000 Btu an hour." Scott also points out that microturbines weigh less than reciprocating engines, which gives them a leg up in applications where weight is a factor, such as on offshore oil rigs where turbines will also produce less vibration than reciprocating engines.

Lessons learned? "Front-load all of your critical paths, such as permitting, applications for incentives, and your interconnect agreement with your utility," says Simonson. "Do that the day you make the decision to go with microturbines. Use an integrated approach. Consult an electrical engineer and—if applicable—a process engineer. Keep your eye out for incentives, but be aware that sometimes the cost of capturing an incentive can be a wash with respect to the time you have to invest and the capital costs you have to endure to meet the special requirements that many incentive programs impose. Most of all, plan, plan, plan, then execute. I bet we've been through 50 economic models on these projects, reengineering them, looking at them again, then reengineering [them] again."

San Diego County's Jamacha Landfill microturbine system

Elsewhere in southern California, conditions were right for installing microturbines at a closed landfill operated by Monterey Park–based New Cure Inc. In July 2001, the California Public Utility Commission OK'd a hike in Southern California Edison's retail electrical rate from $0.10/kWh to $0.14/kWh (average numbers that take into account the complicated rate structure), which increased annual power costs at the landfill to $440,000. Anaerobic decomposition of organic solid waste in landfills produces landfill gas (LFG) consisting mainly of methane, carbon dioxide, and trace constituents. Because LFG can migrate through soil into structures located on or near landfills and because methane presents a fire hazard or explosive threat, LFG at both operating and closed sites must be controlled to protect property and public health and safety. Additionally in many jurisdictions, landfill operators are required to reduce reactive organic gas emissions to improve regional air quality.

Given the increased cost of electrical power at the New Cure facility, SCS Energy, which specializes in landfill systems, suggested that the company consider a feasibility study for an onsite power-generation facility. The landfill operator agreed but responded with a list of caveats. First the facility would be sized for the onsite load because Southern California Edison wasn't buying power at the time and because a retail deferral installation was considered to have a lower capital cost and a higher return on investment, even if the utility had been buying. Whatever power plant was recommended would have to be fueled exclusively by LFG, and the technology was to be limited to microturbines because the LFG at the site had a low methane content and low NOx emissions were a high priority with regulators. (The United States Environmental Protection Agency [EPA] estimates that one million tons of landfill are capable of producing 800 kW of microturbine power and that a 70-kW microturbine consumes as little as 1,200 m³/day of LFG.)

"It's a pretty select set of circumstances to which microturbines are applicable in this industry," says Pierce. "Primarily you have to have a site that has a significant enough load, and then you have to have that load aggregated at one point for a project to be economically viable. Typically on a landfill, the load is spread out, and you can't connect it economically to get to a central point."

At the New Cure landfill, loads were distributed between four operations: the landfill gas treatment system (LFGTS), a leachate treatment plant (LTP), an office building, and a booster blower. The LFGTS and the LTP were adjacent to each other, but the office building was across the eight-lane Pomona Freeway, and the booster blower was another 580 m away. SCS recommended that the adjacent LFGTS and LTP loads be combined and served by a 350-kW microturbine power plant (five 70-kW units), the office building by a 70-kW facility, and the booster blower by a 30-kW unit, all installations considered economically feasible by the company. The SCS study was submitted to EPA for funding approval in September 2001, at which time the agency decided that a 99.99% destruction and removal efficiency (DRE) of trace compounds would be required for the LFG generated at the site regardless of whether it was flared or used as fuel. At the time, the facility was producing an LFG treated with a thermal oxidizer capable of a DRE of 99.95%, which the microturbines were not expected to achieve.

At Ingersoll-Rand, Wiltsee observed that although microturbines are efficient combustors of methane, they are not designed to completely eliminate trace amounts of contaminants, such as the nonmethane organic compounds (NMOCs) in LFG. Most landfills must meet a 98% destruction-efficiency requirement for NMOCs, which microturbines can meet. The problem was that the New Cure landfill is a Superfund site with strict requirements closely monitored by EPA.

SCS came back with a solution that directed the microturbine exhaust into the LFGTE (the microturbine units were expected to use only 5% of the gas produced on-site). Because the oxygen content of the microturbine exhaust is so high, it would not impact mixing and combustion in the flare, nor would it affect the operation of the LFGTS; nonetheless, there were problems. The requirement to route the exhaust to the LFGTS effectively thwarted the plan to use microturbines at the office building and the booster blower on the opposite side of the freeway. Furthermore, to overcome the problem whereby Ingersoll-Rand's factory-installed onboard compressor could not be upgraded to raise the required quantity of LFG to the 5.5-atm gas required by microturbines, a positive displacement blower was used to prepressurize the LFG, and a chiller and heat exchanger were provided for moisture removal. This pretreatment equipment, including all nonutility electrical and control equipment, was designed and constructed on one skid, which allowed for offsite assembly and testing.

The LFGTS was equipped with combustion air fans to enhance the fuel mixing and combustion, and finally control of the microturbines was interlocked with the operation of the LFGTS to avoid backflowing the microturbines' exhaust out of the combustion air inlets, which could occur if the LFG system was off-line while the microturbines were on. The challenge of matching power generation to the onsite load was solved by generating more power than needed and through an agreement with the utility to "inadvertently" export excess to the grid. Inadvertent export turned out to be the most workable option, given that the power demands of the site had significant swings and that there was notable diurnal variation in power plant output based on ambient air temperature, which affected the density of the combustion air. Since turbine power output increases as ambient air temperature decreases, the power demand was arranged to be greater at night, thereby matching maximum load with maximum power output. The export decision required negotiating an agreement with Southern California Edison for an export limitation of 150 kW. The utility eventually charged New Cure $105,000 for upgrades to its side of the meter, including a new main transformer, a ground bank, and wiring modifications.

Like BSI, New Cure signed a five-year, fixed-price maintenance contract with Ingersoll-Rand, wherein the manufacturer will supply all scheduled and unscheduled maintenance at a fixed cost per year, an expense expected by the company to account for 70% of the power plant's overall operation. SCS also secured a $105,000 grant under the California Energy Commission's innovative peak load–reduction program and a $450,000 grant under California's Self-Generation Incentive Program (modified to add noncogeneration-based projects to the eligibility criteria), which helped offset the cost of facility installation.

The New Cure microturbine plant first produced electrical power in late August 2002, six months after signing a contract for SCS to provide a turnkey operation. Between October 2002 and January 2003, the plant was on-line 86% of the available hours; by the end of January, the plant was on-line 95% of the available hours, and the microturbines, designed for a methane content of 35% or greater, have demonstrated the ability to run on contents as low as 29% methane. Savings in "avoided electrical costs" recently have approached $30,000 a month.

"This is not something you do to get rid of your landfill gas," says Pierce. "This is a value-added proposition at a site. When designing a project, we typically run multiple proformas to look at different sizes of projects, bouncing off the distribution to power demand to come up with an optimal size. Invariably it's some point between the average demand and the peak load. It's never economical to actually cover the whole peak, but you would be surprised how many people start out their projects by sizing them based on their peak demand."

The Calabasas Landfill microturbine power plant and pretreatment skid

Where does Pierce see microturbines going? "Certainly when you get up to a megawatt, I don't think you're going to see microturbines replacing reciprocating engines as the technology of choice. I think the battleground is in the lower capacity range, and it's really on a case-by-case basis. The advantage that microturbines have is they can tolerate a lower methane content in the fuel. That's important in this industry because some of our older landfills out here in dry climates don't have 40%-plus methane, which is the minimum a reciprocating engine can operate at. Also if you have an air district that places a high priority on NOx emissions, the microturbines are much lower than reciprocating engines. Another factor is that Ingersoll-Rand is willing to guarantee maintenance costs for over five years at a favorably fixed price; for these smaller engines, reciprocating engine manufacturers are not generally willing to provide that kind of agreement. On the negative side, on a dollar-per-kilowatt basis installed, microturbines are a lot more expensive. But if you have a 40% capital-cost grant like those available here in California, that mitigates the sting of the additional capital costs."

Biogas of another sort has long been used to generate electricity by the County Sanitation Districts of Los Angeles, where Division Engineer Ed Wheless says the agency has been in the business of producing its own power since 1938. "We have a long history of using renewable fuels," says Wheless. "We generate something like 133 megawatts from all of our different landfills and treatment plants. As of now, none of this is done by reciprocating engines." The challenge at the agency's Lancaster wastewater treatment facility was to find a turbine that would fit the amount of biogas produced. When the Ingersoll-Rand 250-kW unit came on-line, Wheless jumped, also taking advantage of a California self-generation capital-improvement grant. "Assuming this project works," says Wheless, "it's almost the perfect application for the smaller wastewater treatment plants that are just about everywhere in every town and city in America. This is something our districts here in Los Angeles strive to do every day: to find uses for our waste and reduce the cost to our ratepayers.

"The big thing for us is that we require something that operates at a lower gas quality and also with low emissions. Internal combustion engines are cheaper, but it doesn't matter what they cost if you're not allowed to install them." Asked whether the microturbine would have been viable without the 40% capital-cost incentive, Wheless said that even without the incentive, the microturbine the agency purchased is "extremely cost-effective and would be viable"—although it probably would take longer than the one and a half to two years now projected to pay for themselves. The districts' system will involve cogeneration with heat from the turbine exhaust generating hot water that will be routed to the facility's digesters. Like LFG, digester gas requires conditioning, and the county's 250-kW microturbine will come factory-equipped with Ingersoll-Rand's new fuel conditioning system.

Across the county at the districts' Calabasas Landfill, 10 Capstone microturbines have been producing electricity to run the onsite gas blowers for more than a year. Wheless says the beauty of microturbines is the fact that they run unattended. "I can tell you from the Calabasas installation that it's a real eye-opener that you can have a system operating on your site, and you don't have to know anything about it. We don't have an operator; we don't have to train our mechanics on how to maintain it. These are very complicated factors for a larger organization to deal with. With microturbines, all you have to do is walk by, take a look, and see whether they're burning."

Journalist PENELOPE GRENOBLE O'MALLEY is a frequent contributor to Forester Communications publications.

DE - Jan/Feb 2004