California Carbon Check

Source: By Susanne Retka Schill, Ethanol Producer Magazine • Posted: Friday, January 25, 2019

From solar power to dairy biogas to membrane dehydration, not to mention multiple process efficiencies, California’s ethanol plants are case studies in striving to drive down carbon intensity (CI).

Under California’s Low Carbon Fuel Standard, all fuels are given a CI score indicating their life cycle greenhouse gas (GHG) emissions as grams of carbon dioxide equivalent per megajoule of fuel. Fuels with lower CI scores generate carbon credits that can be bought to compensate for fuels with high CI ratings. Established in 2007 with a 10 percent reduction goal by 2020, the LCFS has been reauthorized with a 20 percent CI reduction goal by 2030. Prices for LCFS compliance credits have been climbing from averages of $20 to $30 five years ago, to around $190 per metric ton of CO2 equivalent in early December.

Doing the math, which includes an adjustment for the energy content of ethanol as well as the conversion from tons to grams, that is more than 1.6 cents per gallon of ethanol per point of CI. “In California, we’ve insisted we get reimbursed for that CI value,” says Lyle Schlyer, president of Calgren Renewable Fuels LLC in Pixley, California. Low-carbon ethanol receives a premium for every point better than the market-established base ethanol CI of 79.9.

Calgren has nine fuel pathways on the California Air Resources Board list, ranging from 60.74 to 77.04. The lowest uses California corn and landfill gas, the highest uses Midwest grain sorghum and natural gas. All of the distillers grains are sold wet (WDGS). California corn seldom is an option for Calgren, Schlyer says. But while surrounding dairies use all available corn for feed, chopped as silage, they are beginning to turn lagoon waste into a coproduct. Dairy biogas is the linchpin of Calgren’s most recent carbon reduction strategy. Four years ago, the company installed an on-site anaerobic digester to treat waste streams. In the fall of 2018, it began cleaning up biogas from the first of 12 dairies in a cluster connected by pipeline to capture biogas from covered lagoons.

Methane is a powerful GHG—with impacts 25 times greater than that of CO2—and under a new state law is targeted for a 40 percent reduction by 2030. If dairies do not voluntarily reduce emissions, they will be forced to cover their lagoons. Under the Livestock Protocol followed by CARB, environmental credits aren’t available to mandated digesters.

Schlyer says integrating dairy biogas into an ethanol plant solves a big problem that has stymied other proposed projects: how to handle widely varying production volumes. Under ambient temperatures, the gas production in summer is generally twice that in winter, while demand for renewable compressed natural gas (rCNG) is steady year-round. It’s uneconomic to build a biogas facility for the maximum output when CNG fuelers are reluctant to turn to petroleum sources, if local supplies run short.

Rather than risk venting surplus gas and losing credits, an ethanol plant can use it to displace natural gas. “If we used all our biogas we’re planning to produce for ethanol, we would have a CI value in the 20s,” Schlyer says. The better economic return, he adds, comes from selling the rCNG as transportation fuel. Calgren’s pathway for its rCNG is pending, but Schlyer points out that two existing dairy biogas-to-CNG pathways have CI scores of -254 and -273. Eventually, Calgren will likely build its own CNG fueling station, he adds, and fuel its own trucks with rCNG, further reducing its ethanol’s CI.
Schlyer also credits multiple other technologies for lowering the plant’s CI. Its distillation-dehydration-evaporation (DDE) system by Thermal Kinetics uses steam four times. And Calgren runs with high solids loading on the front end that reduces energy inputs at the back end for DDE and cooling. Other projects are under development, too, he adds.

Aemetis Advanced Fuels Keyes Inc. has five pathways on the CARB list. The lowest, 62.75, comes when using California corn, WDGS and landfill gas. Using natural gas bumps that score up 10 points. The CI when using Midwest corn, WDGS and landfill gas is 69.78.

Like Calgren, Aemetis is launching a dairy cluster project to collect and pipeline biogas to the plant’s new gas cleanup and compression facility. Phase 1, connecting 12 dairies, is expected to be operational late this year, says CEO Eric McAfee. In time, biogas could displace all the plant’s natural gas, he says, but Aemetis also plans to inject rCNG into the pipeline for use as transportation fuel.
Aemetis also is installing Mitsubishi’s Zebrex membrane dehydration technology to displace energy used by the plant’s molecular sieves. Due to come online in the fall, it is expected to reduce the plant’s CI by 3.5 points, according to McAfee.

With the membrane dehydration, dairy biogas and LanzaTech cellulosic ethanol technology all under development simultaneously, McAfee says the company is putting another promising technology on the back burner. “We have not yet committed to it because of our full plate, but we will be seriously investigating mechanical vapor recycling.” Using California renewable electricity to power fans to mechanically repressurize low-grade steam would have a lower CI than steam produced with natural gas from Texas, he explains.

Pacific Ethanol
Pacific Ethanol Stockton LLC has six pathways. It gets a score of 70.56 when using landfill gas and Midwestern corn, which drops by about 5 points if using California-grown corn. In its quest to lower CI scores, Pacific Ethanol has installed several innovative technologies at its two California plants in Stockton and Madera. In 2016, it was the first ethanol plant to install Whitefox membrane technology, using it to dehydrate a portion of the molecular sieve’s regeneration stream at the Madera plant. The company says the system reduces natural gas usage by about 5 percent.

In 2017, the company became the first to deploy Ener-Core’s Power Oxidizer as part of the combined-heat-and-power plant it is building at Stockton. The Power Oxidizer allows the company to burn waste gases diverted from the plant’s thermal oxidizers, along with natural gas. According to Ener-Core, the system would supply about half of the plant’s steam demand, generate 3.5 megawatts of energy, reduce CO2 emissions by 20 percent and reduce nitrogen oxide emissions by 57 percent. Pacific Ethanol anticipates up to a $4 million reduction in energy costs, once the CHP system is fully commissioned and operating, a company spokesman says.

Pacific Ethanol Madera LLC is sporting another first, completed this fall. A solar power array started up in late summer and is now operating at its full 5 MW generating capacity. Beyond the CI benefits, the company expects the system to also reduce its utility costs by about $1 million annually.

Another innovative California project proposing to make sugarcane ethanol is anticipating its low CI score of 22.44, and the $190-per-ton LCFS credit value will push the development phase to financial close this year. California Ethanol & Power’s CI score is just over half the typical score for Brazilian sugarcane ethanol. Several factors contribute to low sugarcane scores: higher ethanol yields per acre of sugarcane than corn, the limited tillage for sugarcane crops that get replanted every four to six years, and the use of bagasse for electricity generation.

CE&P’s treatment of vinasse is the biggest difference from the Brazilian model. Instead of spreading distillation waste streams onto fields, the California plant will divert them to its wastewater treatment facility, recycling a portion in the process. An anaerobic digester will treat nonrecycled waste streams, producing nearly a billion cubic feet of biogas annually. The inorganic solids from the vinasse are high in potassium that will be sold as fertilizer, creating an additional coproduct and reducing CI. And, of course, the California plant will have lower transportation-related emissions than Brazilian ethanol.
“The CI score needs to be verified, once the plant gets running,” says David Rubenstein, CE&P president and CEO. “But we think we can get it lower.” One idea is to use the biogas it produces to fuel its trucks, displacing close to a million gallons worth of diesel emissions.

New Scores for All
All plants selling ethanol in the California market will be recalculating their CI scores in the next couple of years. Lauren Taylor, senior environmental health and safety consultant for ERI Solutions Inc., explains that under the updated regulations taking effect in 2019, all existing fuel pathways will be deactivated Jan. 1, 2021. Applications for new pathways will need to use the California Greenhouse Gases, Regulated Emissions, and Energy Use Transportation Model (GREET) 3.0 in determining CI and, in 2020, third-party validation will be required. Starting in 2021, new annual reporting requirements also will include third-party verification.

In analyzing GREET 3.0, Taylor says most plants will see a 3- to 5-point reduction in CI scores, compared to the previous model. But the model parameter giving the best “bang for the buck” in carbon reduction by far, she says, is to increase ethanol yield.