How Much RNG Can We Produce?

Breaking Energy

The Energy Collective

Renewable natural gas (RNG) is methane produced from biomass that is cleaned to pipeline quality standards and blended with fossil natural gas. RNG, also known as biomethane, is carbon-neutral and chemically identical to fossil natural gas allowing it to be blended without restriction. Renewable natural gas is produced from a variety of (mostly waste) resources including landfills, sewage, farm waste and food waste. Biomass energy crops could be cultivated for RNG production, but currently those resources tend to be used for liquid fuels.

The major benefits of RNG production are that it takes methane that is already naturally produced from waste and going into the atmosphere as a potent greenhouse gas and turns it into a valuable carbon neutral fuel. RNG also helps address energy security because it is a locally produced fuel that is available in every community. RNG is also a universal fuel that is certified for use in existing infrastructure without technical issues and can be used for heat, power and transportation.

A series of studies from the government research agencies and industry in the last few years have found that anywhere from 5% to 20% of today’s natural gas demand could be met with RNG. These studies have attempted to quantify the resource by sector and region that are available for RNG production. The studies covered in this article do not include power to gas, nor synthetic natural gas which is produced from other fossil fuels such as coal.

Assumptions for how resources are calculated vary from model to model, particularly in the use of energy crops, which is the single biggest variable that differs among the studies. Conversion efficiencies and costs also vary by feedstock and by conversion process, but conversion efficiencies typically range from 60% – 70%.

USA, NREL (National Renewable Energy Laboratory)

Biogas Potential in the United States (Fact Sheet), 2013

The methane potential from landfill material, animal manure, wastewater, and industrial, institutional, and commercial organic waste in the United States is estimated at … about 420 billion cubic feet… This amount could displace about 5% of current natural gas consumption in the electric power sector and 56% of natural gas consumption in the transportation sector (EIA 2013).

The methane generation potential is expected to be much higher if lignocellulosic biomass resources are used. Future estimates reach 4.2 trillion cubic feet per year… which could displace about 46% of current natural gas consumption in the electric power sector and the entire natural gas consumption in the transportation sector.

2014_12_15_EPA_methane potential USA

AGA (American Gas Association)

The AGA is one of the USA’s major natural gas industry trade associations. AGA formally endorses the development of the RNG industry and the blending of biomethane with fossil natural gas in pipelines and for transportation.

AGA argues that RNG helps reduce greenhouse gas emissions, increases domestic energy production, improves waste management, provides new revenues for farmers, and helps creates jobs.

AGF (American Gas Foundation)

The American Gas Foundation is a group related to the AGA that conducted a major study in 2011 on US RNG resources and potential.

The Potential for Renewable Gas: Biogas Derived from Biomass Feedstocks and Upgraded to Pipeline Quality.

This report breaks down the resources by state and includes both anaerobic digestion and thermal gasification pathways.

This analysis presents three potential degrees or scenarios of total biomass utilization or market penetration:

  • Non-aggressive. This scenario assumes roughly 5% -25% (depending on resource) of biomass is processed into biogas. Total RNG production is 0.97 quads per year or 4% of US natural gas demand.
  • Aggressive. This scenario assumes 15%-75% (depending on resource) of biomass is processed into renewable gas. The Aggressive scenario represents a concerted national effort to employ this renewable resource. Total RNG production is 2.48 quads per year, 10% of US natural gas demand.
  • Maximum. This scenario assumes 100% biomass utilization and conventional conversion efficiency. It provides a theoretical upper limit for renewable gas production. Total RNG production is 9.5 quads per year, or 40% of US natural gas demand.

Resources calculated for the study include:

  • Animal waste from dairy cows, beef cattle, hogs and pigs, sheep, broiler chickens, turkeys and horses.
  • Wastewater from 436 wastewater facilities.
  • Landfill gas from 2,402 landfills.
  • Municipal solid waste, thermal gasification of MSW not already used in waste to energy projects.
  • Wood residue, from forests, mills and urban wood collection.
  • Energy crops, switch grass, willow, hybrid poplar, but not food crops such as corn or soy.
  • Agricultural residues, from corn, wheat, soybeans, cotton, sorghum, barley, oats, rice, rye canola, beans, peas, peanuts, potatoes, safflower, sunflower, and flaxseed.

2014_12_15_AGF_RNG potential USA National Grid

National Grid is a major power and gas utility based in the UK but with significant operations in the Northeast USA. IN 2010 they released a study titled, Renewable Gas – Vision for a Sustainable Gas Network where they presented the business and resource caser for RNG in their operating area.

The biggest driver of renewable gas is GHG reduction, but what makes renewable gas more compelling is that it also enhances diversity of supply while providing a solution for using local waste resources to produce renewable energy.

National Grid estimates that over the long term renewable gas has the potential to meet up to 16% of the natural gas demand in the four states they service, Massachusetts, New Hampshire, Ney York and Rhode Island.

2014_12_15_National Grid_RNG potential

National Grid is a partner with the New York City Department of Environmental Protection on one of the biggest RNG projects in the USA. Newtown Creek is the largest of NYC’s 14 wastewater treatment plants and uses 8 digester eggs to process 1.5 million gallons of sewage sludge every day. Food waste is also added separately in a partnership with Waste Management, Inc. who preprocesses food waste collected from local schools into biosludge that is delivered to Newtown Creek for digestion. Methane production numbers were not available as the system is still undergoing commissioning.

2014_12_15_NYC_Newtown Creek

National Grid commissioned a similar study in 2009 to analyze RNG potential in the UK. The report, titled The Potential for Renewable Gas in the UK, came to similar conclusions as reports in the USA. The baseline scenario found that 5% of UK natural gas demand could be met by RNG and that the aggressive or ‘stretch’ scenario was 18% of total UK gas demand.

2014_12_15_National Grid_RNG potential_UK

NPC (National Petroleum Council)

The NPC issued a paper in March 2012, Renewable Natural Gas for Transportation. In the paper NPC finds:

  • Approximately 4.7 trillion cubic feet of RNG is potentially available from domestic resources in the USA. 4.7 TCF is about 20% of US natural gas consumption.
  • If used for transportation fuel, this amount of RNG would amount to 40 billion gasoline gallon equivalents per year and would result in 90% reductions in greenhouse gas emissions.

A literature review in the paper reviewing costs for RNG production states:

  • The California Energy Commission estimated the costs of producing pipeline quality RNG from landfill gas to be $1.7 – $2.2/MMBTU.
  • CALSTART estimated current (2010) RNG production costs of $5.9/MMBTU from livestock manure for a medium sized facility and $9/MMBTU for a smaller one. The dominant cost was upgrading the biogas to RNG: $4/MMBTU for a medium sized facility and $7/MMBTU for a small one. Biogas production was typically $2 per 1000 ft3 of biogas, with covered lagoons being the lowest cost and the large, covered lagoon system at Hilarides only $0.38.
  • A 2009 California Energy Commission study did a detailed economic analysis of RNG from dairies injected into the pipeline using current technology and costs. They found that the cost of pipeline injection could be significant, especially for dairies miles from an interconnection to the natural gas grid. For example, the cost of pipeline injected RNG would be $12/MMBTU for the Hilarides Dairy compared to $42/MMBTU for the Castelanelli Dairy which would require 5 miles of Capital costs, including the costs to pipeline interconnect, were the cost drivers.
  • NREL’s case study for biogas from dairy farms resulted in a RNG cost of $11/MMBTU delivered into the This consisted of $6 paid to the farmers, $2.5 for RNG production and $3 for delivery (10 miles) into the pipeline.
  • ECN in the Netherlands estimated costs of RNG production from biomass using the MILENA gasification technology ranging from $13/MMBTU at a large facility to $42/MMBTU at a smaller one, including biomass costs of $3.7 to $7.7/MMBTU of RNG.

2014_12_15_NPC_biogas costsBioenergy Association of California

The Bioenergy Association of California issued a paper in November, 2014 calling for a Renewable Gas Standard, similar to the Renewable Portfolio Standard and the Renewable Fuels Standard to help promote RNG. According to BAC, RNG could meet over 10% of California’s roughly 2300 BCF annual natural gas demand.

World Bioenergy Association

The World Bioenergy Association from Stockholm, Sweden issued a fact sheet titled Biogas – An Important Energy Source, in which they state that 25% of global natural gas demand or 6% of global primary energy use could be met with biogas.

Conclusions

Though estimates vary for how much renewable natural gas can be produced, depending on how aggressively analysts calculate the resource base, and whether energy crops are included, there is a broad consensus that RNG can make a substantive and valuable contribution to global renewable energy production.

RNG offers multiple benefits. First, methane emissions from natural sources that would otherwise be going into the atmosphere as a potent greenhouse gas are converted into a valuable asset.

Second, RNG is a universal fuel that can be used for heat, power and transportation, meaning that it can be directed into sectors in greatest need of greenhouse gas reduction.

Third, since RNG is chemically identical to conventional natural gas, it can utilize existing infrastructure without concern for pipeline degradation or interference with end use devices. Alternative biofuels such as ethanol, methanol or biodiesel are greatly challenged in this regard because they are chemically different from the fossil fuels they seek to replace and require expensive upgrades to engines, storage and delivery systems.

Waste feedstocks for RNG production are widely distributed throughout society and every community has an opportunity to contribute to this valuable stream of renewable energy production. Anywhere there is waste, local citizens can be employed to convert this waste into valuable clean fuel creating win-win scenarios or an improved environment and improved energy security.

Renewable Natural Gas vs. Cellulosic Ethanol

Published at Breaking Energy, Dec. 10, 2014 (.pdf)

The Energy Collective, Dec. 15

The EPA has long promoted cellulosic ethanol as the future of biofuels, but technical challenges have kept production far below targets. A recent rule change allows RNG, renewable natural gas, to qualify as cellulosic biofuel even though RNG is not cellulosic, but this helps EPA appear to be meeting their goals.

RNG growth has been dramatic and is the lowest carbon vehicle fuel available today. Perhaps the EPA should be promoting a Renewable Gas Standard instead of a Renewable Fuel Standard.

In 2013 production of cellulosic ethanol was effectively zero, even though the legislated target volume for 2013 was 1 billion gallons. In August 2013 EPA reduced the target to 6 million gallons, and again reduced the target retroactively to 810,185 gallons, less than 1 million. By all accounts this represents a complete failure of the cellulosic ethanol program. In July 2014 the EPA revised the cellulosic biofuel rules to allow RNG to be categorized as cellulosic.

The RFS production data tells the story. In 2013, cellulosic biofuel production was nearly zero. In 2014, a small amount of cellulosic ethanol was produced, but all a sudden there are 17.5 million gallons of renewable CNG and LNG. The appearance of RNG was purely a function of the rule change in July that allowed already existing (unsubsidized) production of renewable CNG/LNG to qualify. The production of cellulosic ethanol is barely half of the already modest target despite extensive federal support.

2014_12_05_EPA RFS Production Data

EPA uses five RIN D-codes (D3, D4, D5, D6 and D7) to define biofuels under the RFS. D3 and D7 are for cellulosic biofuels with a GHG reduction requirement of 60%; D6 is for corn ethanol (GHG reduction 20%); D4 is for biomass-based diesel (50% GHG reduction); and D5 is for advanced biofuels, including sugarcane ethanol and biogas (50% GHG reduction).

Ethanol fuels have been subject to a great deal of criticism for both environmental and engineering reasons. Ethanol is traditionally made from sugars fermented into alcohol. The sugars are derived from agricultural crops, predominantly corn in the USA and sugarcane in Brazil, the world’s two largest ethanol producing countries. Since the use of food crops for fuel competes with food production and raises food prices there has been much effort to develop alternative pathways to produce (cellulosic) ethanol from non-food crops such as grasses, wood and waste.

The problem with cellulosic ethanol is that it is quite challenging to break down cellulose because it is the part of a plant that is meant to be tough. Cellulosic ethanol producers have struggled to find energy and cost efficient means of accomplishing the task and many have gone bankrupt, such as KiOR recently.

There are significant engineering challenges in using ethanol as well, the biggest being that ethanol is hydroscopic, meaning that it attracts and absorbs water. Water build up can create corrosion in tanks, fuel lines and engines and can create phase separation of the fuel itself causing engine performance issues. Ethanol also breaks down certain types of polymers and rubber sealants, as well as attacking iron, copper and brass and in some circumstances ethanol has been thought to react with fiberglass fuel tanks creating sludge build up.

Older engines can be ruined by the use of ethanol, though modern engines use materials that are resistant to such failures. A properly designed engine can run on pure (neat) ethanol, though attention must be made to manufacturer’s instructions regarding appropriate fuel choice.

Ethanol blends in gasoline up to 10%, known as E10, are approved for general use in the USA and are common today, but blending ethanol above 10% is a heated debate. The 10% threshold is known as the “blend wall” and current ethanol production currently lies at the right at that level. Ethanol producers and advocates are actively lobbying the government to approve blends of E15 and E85 (15% and 85%). Petroleum interests are actively opposed to increased ethanol blends, for obvious reasons, as they are trying to protect market share for their product.

Consumers, vehicle manufactures, fuel distributors and retailers are caught in the middle. E15 would be marketed for general use and there is a great deal of concern that increased ethanol ratios will create major maintenance problems. As it stands today E10 is not used in boating, is discouraged for use in small engines such as lawn mowers and chain saws, and is not distributed through pipelines due to corrosion issues. Ethanol must be transported separately from gasoline in trucks and blended at the end of the line near the point of distribution.

The vast majority of ethanol produced in the USA is made from corn, which is an intensive crop to cultivate, requiring fertilizers, pesticides and heavy equipment, all of which are based on fossil fuels. This is why life-cycle greenhouse gas emissions from corn ethanol are only marginally lower than for gasoline. GHG emissions from corn ethanol are higher than that of fossil natural gas! Cellulosic ethanol has low GHG emissions in theory, but since there is hardly any actual commercial production it remains a theory.

Renewable natural gas has clear benefits over ethanol. First, RNG is chemically identical to fossil natural gas and can be blended and used without restriction. No engineering modifications must be made to accommodate RNG.

Secondly, RNG is readily producible from non-food resources, particularly waste from landfills, farms, food and sewage. All of the raw materials that have been identified as potential cellulosic ethanol feedstocks could be more easily used as RNG feedstocks. There are many proven pathways for producing RNG, ranging from simple digestion processes up to more complex thermochemical processed suitable for more difficult feedstocks. 10% – 20% of natural gas supplies could be renewable.

While ethanol offers questionable greenhouse gas reductions, RNG is widely regarded as the lowest carbon vehicle fuel available. Data from the Department of Energy’s Alternative Fuels Data Center (shown below) presents the case clearly. Agricultural crops converted into ethanol and biodiesel are barely lower in carbon than gasoline and are higher than fossil natural gas. Landfill CNG has the lowest carbon intensity for both light duty and heavy duty vehicles.

2014_12_05_DOE_carbon in fuels light2014_12_05_DOE_carbon in fuels heavy

Natural gas is the fastest growing vehicle fuel in use today, it is safe and non-toxic with the lowest emissions of criteria pollutants and also the lowest carbon emissions of any fossil fuel. Renewable natural gas takes carbon emissions down to the lowest possible levels and is a universal fuel that can replace coal and petroleum, ethanol is strictly a blend stock for gasoline that requires substantial engineering upgrades for questionable energy security and environmental outcomes.

It is time to consider a Renewable Gas Standard to replace the failed Renewable Fuel Standard.

Need for a Renewable Gas Standard

Published at Breaking Energy, Dec. 5, 2014 (.pdf)

The Energy Collective, Dec. 8, 2014

The use of natural gas is growing throughout the world as new drilling techniques have opened up vast shale resources and low cost gas is flooding the market. The environmental advantages of natural gas over other fossil fuels have put it in a favored position as emissions regulations continue to tighten around the world. But conventional natural gas is still a fossil fuel with significant carbon emissions that need to be contained.

So how do we avoid damaging carbon emissions while embracing the engineering and emissions advantages offered by natural gas? By blending renewable natural gas (RNG) into the natural gas supply.

Natural gas is primarily methane, the simplest of all hydrocarbons (CH4), and methane is renewable. Methane can be produced in substantial quantities from food waste, farms, sewage and landfills. Renewable methane can be blended in unlimited ratios with fossil natural gas and is undetectable to end-users. There are a wide variety of technologies and feedstocks that can be used to produced renewable natural gas at competitive costs.

Recently, the Bioenergy Association of California issued a report titled Decarbonizing the Gas Sector: Why California Needs a Renewable Gas Standard. The BAC argues that the use of RNG will help eliminate millions of tons of greenhouse gas emissions and provide the lowest carbon transportation fuels among other benefits.

A Renewable Gas Standard (RGS) would be modeled on California’s successful Renewable Portfolio Standard that has contributed to a doubling a renewable electricity in a decade. BAC proposes a very modest proportion of 1% RNG blended into the fossil natural gas supply in 2020 and increasing up to 10% by 2030.

The RGS should apply to all retail sellers of natural gas, beginning with sales that fall under the jurisdiction of the California Public Utilities Commission which covers 82% of the state’s gas sales and expanding ultimately to all utilities and gas providers.

Price impacts to rate payers are expected to be negligible under the proposal as presented because the volume requirements are so modest and the phase in time gradual. Nonetheless it is important that protections are built in to protect rate payers as well as allow utilities to bank and borrow on their compliance measures.

According to figures used by the BAC, organic waste converted into biogas could meet more than 10% of California’s natural gas demand. Total organic waste in CA could be used to produce 284 billion cubic feet (bcf) of renewable natural gas. This RNG is equal to 2.5 billion gge (gasoline gallon equivalents) of transportation fuel, enough to replace ¾ of all the diesel fuel used in the state. Alternatively, the RNG could produce 5,000 – 6,000 MW of flexible electric power generation.

2014_12_04_BAC_RNG_CA Potential

California, like much of the world, has abundant resources to produce RNG. More than 16 million tons of organic waste are landfilled every year in the state. Additionally there are over 500 wastewater treatment plants, 278 landfills, 1600 dairies, and extensive forests. It is estimated that food waste could provide 82 bcf of gas, landfill gas could provide 53 bcf, livestock manure could provide 43.4 bcf, sewage treatment could provide 23 bcf, and forest waste could provide 82.4 bcf every year.

Renewable natural gas can be produced in a variety of ways. The most common is through the process of anaerobic digestion (AD) where microbes in an oxygen starved container decompose organic materials. AD is commonly deployed at wastewater treatment plants to break down sewage and on farms to help dispose of animal manure.

Landfills produce methane naturally through the decomposition of organic materials and in many areas this methane effluent is regulated. So the landfill industry has been collecting the methane in many landfills for years and this is the leading commercial source for renewable natural gas today. The waste disposal industry have been leaders in converting their garbage trucks to run on landfill gas which is typically cleaned up and upgraded to road quality CNG.

In addition to digestion processes, RNG can be produced through gasification of woody biomass and related thermochemical processes. Power-to-Gas offers the ability to convert electric power from renewables and nuclear plants into RNG to help meet energy storage needs. In a related process, CO2 methanation is a technique for recycling captured carbon dioxide back into methane using Power-to-Gas methods.

2014_12_04_BAC_RNG_ghg reductions

In addition to providing many jobs and economic opportunities there are many environmental benefits to producing RNG. Aside from reduced carbon emissions resulting from replacing fossil natural gas, use of RNG also reduces fugitive methane emissions by putting the methane to work and also reduces black carbon. RNG production reduces the amount of waste going into landfills and helps reduce wildfires by using by fuel from the forest floor. RNG helps improve energy security and offers flexible and reliable power generations opportunities.

RNG needs policy to support the growth of the industry because currently RNG is more expensive to produce than fossil natural gas. But since RNG offers additional environmental and social benefits of fossil natural gas it should be worthy of public support.

Northeast Shale Production and Natural Gas Prices

Published at FC Gas Intelligence, Dec. 3, 2014 

The northeast USA offers an interesting story of natural gas pricing as pipeline constraints limit the flow of gas from the bountiful production regions in the Marcellus and Utica shales to the enormous demand centers in Boston and New York City. Key chokepoints for the gas distribution are around New York City/Long Island and in New England. With production booming, gas prices have been held down at key pipeline hubs in Pennsylvania, while in neighboring states, Massachusetts and New York, prices are climbing.

As US shale gas production continues to grow, Henry Hub spot prices for natural gas have held steady through the autumn of 2014 at a little above $4/MMBtu. But falling temperatures across most of the country in mid-November caused natural gas prices to rise.

Since the summer of 2012, rising production of natural gas in the Marcellus has outpaced the growth of pipeline capacity in the region causing gas prices to decline and separate from the benchmark Henry Hub price. Price hubs in the central and northeastern portions of the Marcellus, where pipeline capacity is particularly limited have seen the sharpest drops.

Prices in Connecticut and Massachusetts spiked as high as $10/MMBtu in mid-November, while price at the Transcontinental Pipeline’s Leidy Line in the Marcellus was held below $3/MMBtu. The large amounts of backed up supply has also made regional prices volatile, dropping as much as $1/MMBtu on moderate temperature days when demand is low.

2014_12_2_EIA_marcellus gas prices

Natural gas transportation into New York and New England is highly constrained during times of peak demand. Winter temperatures create increased demand for heating in both residential and commercial sectors as well as demand for gas-fired power generation which represent nearly 50% of New England’s electric generation capacity. Past winter seasons have seen price spikes for natural gas and the pattern is expected to continue this winter season.

For decades, ever since the gas pipeline infrastructure was first laid down, the Northeast has been a major natural gas demand center. Gas was imported into the region from all available areas: the Gulf Coast; Midcontinent, Rockies, Canada, and LNG through the Boston terminal. In the past three years though, gas production from the Marcellus and Utica shale in Pennsylvania, West Virginia and Ohio has grown substantially and shows signs of long term productivity. Gas production has gone from less than 3 Bcf/d in 2009, where it was for decades, to 18 Bcf/d in 2014 with projections of 30 Bcf/d by 2019.

Break-even prices for producers in the Marcellus and Utica shale regions suggest that the regions have strong foundations for growth. The break-even price for dry gas producers in the Northeast Marcellus are around $2.50/MMBtu and the price for wet gas producers in Southwest Marcellus are lower at $2.00/MMBtu. Wet gas producers are able to sell the condensates and natural gas liquids for a premium which takes pressure off the price needed for the dry gas.

There are a number of pipeline expansion projects nearing completion or in the works that will help increase the capacity of gas to flow into the Northeast by up to 35 Bcf/d. New York and New England are not the only regions seeking Marcellus shale gas. Because of structural changes that new gas resources have brought, older pipelines into the Northeast are often going underutilized. The natural gas pipeline industry is working to modify the pipeline infrastructure to enable bi-directional flow and move up to 8.3 billion cubic feet per day out of the Northeast and into the Midwest and down to the Gulf Coast.

The enormous gas production from the Northeast is not just impacting the local markets. Gas producers have their eyes on markets in every direction, pushing out into the Midwest and Ontario and looking to the Southeast. The big prize market for gas producers is the Gulf Coast where there is expected to be dozens of gas hungry petrochemical facilities and LNG export terminals.

There are nearly 60 gas pipeline projects in various stages of development throughout the Marcellus and Utica shales. 41 of the projects will add capacity to move gas out of the region. There are five major corridors through which the pipelines flow: east to New York and New England, south via the Atlantic coast, southwest towards the Gulf, Midwest via Ohio, and North to Canada. These projects represent one of the biggest energy infrastructure changes in the USA in decades.

According to the EIA:

  • Columbia Gulf Transmission completed two bidirectional projects in 2013 and 2014 that enable the system to transport natural gas from Pennsylvania to Louisiana.
  • ANR Pipeline, Tennessee Gas Pipeline, Texas Eastern Transmission, and Transcontinental Gas Pipeline are planning to send natural gas from the Northeast to the Gulf Coast because of the potential of industrial demand and LNG exports from the Gulf Coast. These projects total 5.5 Bcf/d of flow capacity.
  • The Rockies Express Pipeline’s partial bidirectional project (2.5 Bcf/d of capacity) is primarily to flow Marcellus natural gas to more attractive markets in Chicago, Detroit, and the Gulf Coast.
  • The Iroquois Gas Pipeline’s bidirectional project (0.3 Bcf/d of capacity) will deliver natural gas from the Marcellus to Canada. Iroquois will receive gas from the Dominion, Constitution (expected in service in 2016), and Algonquin pipelines.

2014_12_2_NGA_proposed pipelines

The reasons for modifying existing pipelines rather than constructing new pipelines include: lower capital costs, fewer permits, and less environmental impacts. At the same time, modifying pipelines to be bi-directional offers much greater flexibility to respond to changing market conditions in the years to come and maximize pipeline utilization rates.

Each pipeline project requires contracted customer commitments to proceed, pipelines are not built speculatively. Developers must also meet all federal and state regulatory requirements, permitting can be a time consuming and expensive process.

The Federal Energy Regulatory Commission (FERC) is the lead permitting agency for interstate pipeline projects. FERC is an independent agency that regulates the interstate transmission of natural gas, electricity and oil. A FERC review of an interstate pipeline project takes from 5-18 months, with an average time of 15 months.

Reverse Combustion Equation

This equation describes the idea of reverse combustion with renewable methane, carbon capture and oxy-combustion. This is also known as chemical looping and is a form of using renewable natural gas as energy storage.

Combustion works by combining fuel (CH4) with oxygen to create heat (energy) plus carbon dioxide (CO2) and water (H2O). Typically the CO2 and H2O are just released to the atmosphere, but if we capture the CO2 to prevent it from going to the atmosphere as a greenhouse gas, then we can do reverse combustion and recycle it.

Reverse combustion requires an energy input such as nuclear power or renewables to perform electrolysis on the CO2 and water to create renewable methane and oxygen. The oxygen must be looped back and reused for oxy-combustion to enables the carbon capture.

The use of water in this equation is interesting because non-drinking water can be used for the electrolysis and clean water can be produced on the back end creating an opportunity to use power production as a means to produce clean water.
2014_12_2_reverse combustion equationThe combustion of 1 pound of methane results in the production of 3.71 gallons of water and 1 Bcf of methane produces over 11 million gallons of water.

Power-to-Gas Enables Massive Energy Storage

Published in Breaking Energy, Dec. 2 (.pdf).

The Energy Collective, Dec. 6, 2014

Power-to-Gas (PtG) enables the natural gas pipeline network to be used for energy storage, resolving many of the integration issues that plague intermittent renewable energy sources such as wind and solar.

It is well known that finding a solution for scalable energy storage is critical in the pursuit of achieving a renewable energy future. While batteries, pumped-hydro, flywheels and other technologies have their merits, none are able to offer seasonal deep storage at the terawatt scale. Power-to-Gas is an elegant innovation that simply takes excess renewable electricity to create renewable hydrogen and methane for injection into natural gas pipelines or use in transportation. Existing gas pipelines can store hundreds of terawatt hours of carbon neutral methane for indefinite periods of time.

Hydrogenics PtG_11_25_2014

Germany has been pursuing the most aggressive renewable energy targets in the world under their Energiewende program. The Germans have been experiencing challenges in integrating large proportions of wind and solar power into the electric grid because the times of power production do not correlate with times of demand, so there are sunny afternoons when solar PV is outproducing demand, and likewise windy nights when power production must either be curtailed or else exported to neighboring countries at low prices. Adding to the technical challenge is the fact that wind and solar production can spike and drop off very quickly with little warning creating inefficiencies as grid managers scramble to match supply with demand.

Many technology pathways are being pursued towards the goal of broad based energy storage to help meet the challenge of integrating renewables into the power grid. Batteries and flywheels are excellent for rapid discharge and frequency management but are not suitable for long term storage. Pumped Hydro and Compress Air Energy Storage (CAES) offer longer term storage but are fundamentally limited by the requirement of favorable geographies. Chemical conversion of electricity to gas allows the existing natural gas pipeline infrastructure to be leveraged for massive volume, long-term, distributed storage that is cost competitive with other storage technologies. Additionally, the synthetic methane of hydrogen produced via PtG can be utilized as the carbon neutral transportation fuels or elsewhere in industry.

Germany has embraced PtG as a critical component in the Energiewende program. PtG enables German utility operators to manage the gas and power networks in tandem, shifting gas to power and power back to gas as needed throughout the day to match supply and demand. There are 30 PtG plants at various levels of commercial production throughout Germany and neighboring countries.

DNV_P2G Map Europe_11_25_2014

There is a suite of technologies being deployed to create PtG and technology innovation is rapid in the space. PtG begins with basic electrolysis, using electricity to split water, H2O, into its components hydrogen and oxygen. The oxygen has commercial value and is sold or utilized and the hydrogen can be deployed in three different ways.

Hydrogen can be injected directly into the natural gas pipelines and analysis is ongoing to determine what proportions of hydrogen can be supported. Originally it was thought that no more than 5% hydrogen could be used, but depending on the pipeline engineering and downstream uses ratios up to 12% have been achieved. Older cast iron and steel pipes don’t contain hydrogen well because they are embrittled by the hydrogen which can also leak through seams because it is much smaller than a methane molecule. Modern plastic pipes contain the hydrogen much more effectively and can take higher ratios but users must be consulted to ensure their operations are not impacted by higher hydrogen ratios. This is an ongoing area of investigation and pipeline standards for direct hydrogen injection have not been established in Germany.

The second method for hydrogen use is methanation, reacting the hydrogen with carbon dioxide to created synthetic methane, or renewable natural gas. Natural gas is primarily methane, CH4, and synthetic methane is identical to fossil methane and can be blended or substituted with no limitations. The chemical process is known as the Sabatier reaction and is the inverse of methane stream reforming commonly used to produce industrial hydrogen from natural gas.

Methanation of CO2 is one of the many ways to utilize captured carbon dioxide for beneficial purposes and is not limited to use with excess renewable electricity, any energy source could be used including nuclear power. It is entirely feasible that a dedicated nuclear power plant could be set up to do reverse combustion and convert CO2 and H2O into synthetic methane or synthetic liquid fuels that are ultra-pure and carbon neutral, but that is a discussion for a separate article.

The third method for utilizing PtG would be use in transportation instead of pipeline injection. Compressed hydrogen, CNG, or LNG could be manufactured on site for direct use in vehicles as carbon neutral clean fuels.

Two of the leading vendors of P2G solutions are Hydrogenics and ETOGAS. Hydrogenics has over 60 years’ experience manufacturing alkaline electrolyzers and is actively involved in numerous PtG projects in a number of countries. The technical challenge in using older generations of alkaline electrolysis has been the slow ramp up rate from a cold start which limits the flexibility and efficiency for grid integration. Newer generations of hardware have been designed that reduce cold start times from minutes to seconds and Hydrogenics is actively pursuing the market for grid frequency regulation that requires second-by-second reaction response times.

In 2013 ETOGAS inaugurated the world’s largest commercial PtG methanation plant in Werlte, Germany which was built in partnership with Audi and Siemens to produce synthetic natural gas. Audi markets the gas as e-gas and it is distributed via pipeline to CNG filling stations where it is sold as carbon neutral vehicular fuel.

The Werlte plant was constructed next to a biogas digester facility that provides the CO2 for methanation. Since methanation is an exothermic process producing significant heat (approximately 300° C steam), the heat at the Wertle plant is sent back to the digester to facilitate the digestion process. The thermal energy from the methanation is valuable for industrial processes and creates many opportunities for systems integration with other processes. The Wertle plant has an electrical capacity of 6 MW and consumes 2,800 metric tons of CO2 to produce 1000 metric tons of renewable natural gas per year. Though the Wertle plant is the largest commercial PtG plant in operation globally, it is still considered a demonstration plant.

There are a number of emerging PtG technologies coming along including Proton Exchange Membrane (PEM) electrolysis and biological methanation. Biological methanation uses bacteria to react the CO2 and hydrogen into methane instead of traditional catalytic methods, but these processes are still pre-commercial. PEM electrolysis is considered very promising, though not as mature as alkaline electrolysis. PEM is essentially a hydrogen fuel cell in reverse and consumes electricity to produce hydrogen rather than consume hydrogen to produce electricity. The advantage of PEM electrolysis is very rapid response times and expected cost reductions that couple with the development of hydrogen fuel cells for vehicles.

System efficiencies and costs for PtG vary widely on a case by case basis and are closely tied to overall systems integration, particularly in the case of CO2 methanation. Under the best circumstances the life-cycle efficiencies are over 70%, but there are many methods for capturing CO2, many methods for utilizing industrial heat, and many methods for consuming methane, all of which impact full systems efficiency. And while synthetic natural gas is more expensive than fossil natural gas in the American market, SNG from PtG is entirely carbon neutral, which means that it can carry a price premium and earn credits under potential carbon emissions regimes. More importantly though, PtG offers the ability to decouple renewable electricity production from electricity demand and open up alternative industrial and transportation markets for renewable energy.

Despite the interest in Europe, there has been very little discussion of PtG in North America. American environmentalists seem to be so busy fighting hydrofracking and natural gas infrastructure that they are overlooking the incredible promise of renewable natural gas and PtG. There is one project going forward in Ontario, Canada, a 2.5 MW grid storage project by Hydrogenics. News of this project got the attention of the California power authorities (Cal ISO) who just recently signed a contract with NREL (National Renewable Energy Lab) to model the Western States Grid to identify PtG opportunities. California has some of the most aggressive renewable energy targets after Germany and California authorities have come to recognize the potential for using PtG to help integrate renewables into the grid.

sCO2 Power Cycles Offer Improved Efficiency Across Power Industry

Breaking Energy, Nov. 24, 2014 (.pdf)

The Energy Collective, Dec. 4, 2014

Supercritical CO2 power cycles are gaining increasing attention in the engineering world. sCO2 is an ideal working fluid for use in power generating turbines because it offers high efficiency in a compact footprint and can be matched to many different heat sources. sCO2 power turbines could potentially replace steam cycles in a wide variety of power generation applications resulting in higher efficiencies and lower cost of electricity.

CO2_pressure-temperature_phase_diagram_11_20_2014

Supercritical CO2 is a fluid state of carbon dioxide where it is held above its critical pressure and critical temperature which causes the gas to go beyond liquid or gas into a phase where it acts as both simultaneously. Many fluids can achieve supercritical states and supercritical steam has been used in power generation for decades. Supercritical CO2 has many unique properties that allow it to dissolve materials like a liquid but also flow like a gas. sCO2 is non-toxic and non-flammable and is used as an environmentally friendly solvent for decaffeinating coffee and dry-cleaning clothes.

The use of sCO2 in power turbines has been an active area of research for a number of years, and now multiple companies are bringing early stage commercial products to market. The attraction to using sCO2 in turbines is based on its favorable thermal stability compared to steam which allows for much higher power outputs in a much smaller package than comparable steam cycles. CO2 reaches its supercritical state at moderate conditions and has excellent fluid density and stability while being less corrosive than steam.  The challenges in using sCO2 are tied to identifying the best materials that can handle the elevated temperatures and pressures, manufacturing turbo machinery, valves, seals, and of course, costs.

Sandia_supercritical CO2 brayton cycle_11_20_2014

sCO2 power cycles are potentially applicable to a wide variety of power generation applications. Anywhere that steam cycles are used could, in theory, be upgraded to sCO2 that would enable much greater efficiencies and power outputs. Nuclear power, concentrated solar thermal, fossil fuel boilers, geothermal, and shipboard propulsion systems have all been identified as favorable applications for sCO2 cycles and would replace traditional steam Brayton and Rankine cycles. Researchers believe that sCO2 power cycles could lower the cost of electricity approximately 15% over today’s steam cycle technologies. Lower installed cost for sCO2 systems are due to its smaller footprint and reduced balance of plant requirements.

The single phase nature of sCO2 allows for the design of simple, single phase, single pressure exhaust heat exchangers with low gas-side pressure drop. Due to the superior thermal stability and non-flammability of CO2, direct heat exchange from high temperature sources is possible, permitting higher working fluid temperature (and thus higher cycle efficiency). Because sCO2 is a single-phase working fluid, it does not require the heat input for phase change from water to steam and does not create the associated thermal fatigue or corrosion associated with two-phase flow. Lower operation and maintenance costs for sCO2 are possible because plant personnel are not needed for water quality and treatment functions typically found in steam-based plants.

echogen sco2 turbine_11_20_2014

Source: Echogen

sCO2 can be used in either direct or indirect heating scenarios. Indirect heating would use the CO2 in a closed loop recuperated recompression Brayton or Rankine cycle. Indirect heating could replace steam boilers in coal plants, nuclear power, solar thermal, or heat recovery steam generators used in combined cycles. Indirect heating cycles offer thermal efficiencies greater than 50% and is non-condensing making it ideal for heat sources that offer constant temperatures (such as turbine exhaust).

Echogen is bringing to market their EPS100 8MW heat engine that is targeted for use in combined cycle applications. Their system is self-contained, closed-loop, and has zero emissions and no water requirements (though water cooling is an option).

Echogen EPS100_11_20_2014

Direct heating can use oxy-fuel combustion in a recuperated Brayton cycle to replace coal and natural gas combined cycles and offers the capacity for integrated carbon capture. Direct heating is fuel flexible and is adaptable for coal, syngas or natural gas and is a water producer.

NET Power recently announced they will be building their first sCO2 50MW demonstration plant that is direct heated. This power plant is fueled by natural gas and has zero emissions of any kind (no smokestack) and has integrated carbon capture. The plant will output pressurized CO2 that will be sold for use in Enhanced Oil Recovery.

The US Department of Energy is working on integrating sCO2 into nuclear power in order to significantly raise the efficiency and power output. DOE is also working on using sCO2 in solar thermal applications in the Sunshot CSP Program. The Southwest Research Institute (SWRI) and Sandia National Labs have active research programs today in the USA and there are other programs in Europe, Asia and in industry.

Ongoing research programs are focused on demonstrating the commercial viability of sCO2 power cycles at increasingly larger power outputs. Rotordynamics continue to be analyzed and optimized. Heat exchanger research seeks to improve heat transfer correlations for varying geometries and improve heat exchanger durability through testing of materials, fabrication, channel geometry, fouling, corrosion and maintenance. Long term corrosion and materials testing across all components also continue to be active areas of research.

 

Renewable Natural Gas

Published at FC Gas Intelligence, Nov. 24, 2014

Renewable natural gas (RNG) is a topic that does not get a lot of attention in the debate over renewable energy, but it represents some of the best untapped resources available today.

Pipeline quality natural gas is primarily methane, and liquefied natural gas (LNG) is almost pure methane (99%), and methane is a renewable molecule. Natural gas can be produced biologically and synthetically from abundant waste biomass and also excess electric power from intermittent renewable sources.

Currently there is very little policy to support the integration of RNG into the natural gas market and very little awareness of the opportunity. The Bioenergy Association of California (BAC) was formed to support sustainable bioenergy development in California and they have recently come out with a series of reports on biogas resources in California.

In their recent report, “Decarbonizing the Gas Sector,” BAC states that California currently imports more than 90% of the natural gas it uses, costing the state billions of dollars per year. California consumes more than 2 trillion cubic feet of natural gas every year and it provides more than half of the state’s electricity, heating, and cooling and a growing share of transportation fuels. Natural gas is also the source of more than a quarter of California’s greenhouse gas emissions.

Organic waste converted into biogas could meet more than 10% of California’s natural gas demand. According to BAC total organic waste in CA could be used to produce 284 billion cubic feet (bcf) of renewable natural gas. This RNG is equal to 2.5 billion gge (gasoline gallon equivalents) of transportation fuel, enough to replace ¾ of all the diesel fuel used in the state. Alternatively, the RNG could produce 5,000 – 6,000 MW of flexible electric power generation.

California, like much of the world, has abundant resources to produce RNG. More than 16 million tons of organic waste are landfilled every year in the state. Additionally there are over 500 wastewater treatment plants, 278 landfills, 1600 dairies, and extensive forests. It is estimated that food waste could provide 82 bcf of gas, landfill gas could provide 53 bcf, livestock manure could provide 43.4 bcf, sewage treatment could provide 23 bcf, and forest waste could provide 82.4 bcf every year.

In addition to providing many jobs and economic opportunities there are many environmental benefits to producing RNG. RNG directly displaces fossil natural gas resulting in reduced greenhouse gas emissions, methane emissions and black carbon. RNG production reduces the amount of waste going into landfills and helps reduce wildfires by using by fuel from the forest floor. RNG helps improve energy security and offers flexible and reliable power generations opportunities.

Renewable natural gas has the lowest carbon content of any transportation fuels available. Gasoline and diesel have nearly 100 grams of CO2 per megajoule of energy. Traditional biofuels such as ethanol from corn and sugarcane are not much better since producing agricultural crops is very fossil fuel intensive and the conversion processes are not very efficient. Natural gas has 68 grams of CO2 and hydrogen derived from natural gas has 39.42 grams of CO2. Landfill gas has only 11.26 to 15.56 grams of CO2 and the numbers drop from there for dairy biogas (13.45), wastewater biogas (7.89) and most remarkably, biogas from food and green waste is rated as having negative carbon emissions (-15). Biogas produced from food and green waste is the only carbon negative transport fuel available today.

2014_11_24_CO2 intensity of fuels

There is a major effort across transportation sectors to ramp up the use natural gas to replace diesel fuel in high horsepower applications such as truck transport, marine, rail and off road vehicles. The reasons for push are two-fold, to take advantage of natural gas’s lower costs compared to diesel, but also to reap the environmental benefits. Diesel and other liquid fuels are responsible for major shares of toxic criteria pollution, such as NOx, SOx, and particulates. Fossil natural gas is clean and using it results in the virtual elimination of SOx and particulates and substantial reductions in NOx. But fossil natural gas still has significant carbon emissions that must be reduced. RNG amplifies the emissions benefits of fossil natural gas by also reducing carbon emissions because renewable carbon is substituted for fossil carbon.

Renewable natural gas can be produced in a variety of ways. The most common is through the process of anaerobic digestion (AD) where microbes in an oxygen starved container decompose organic materials. AD is commonly deployed at wastewater treatment plants to break down sewage and on farms to help dispose of animal manure.

Landfills produce methane naturally through the decomposition of organic materials and in many areas this methane effluent is regulated. So the landfill industry has been collecting the methane in many landfills for years and this is the leading commercial source for renewable natural gas today. The waste disposal industry have been leaders in converting their garbage trucks to run on landfill gas which is typically cleaned up and upgraded to road quality CNG.

There is now also a growing anerobic digestion (AD) industry focused on diverting organics from going to landfills. Large digesters are being built throughout the country as governments recognize the importance of diverting organic waste from landfills. The biosolids, or digestate, that is left over in AD process are a valuable fertilizer that helps replace the use of fossil fuel derived chemical fertilizers.

Finally, there is a new emerging technology platform for producing renewable natural gas from renewable electricity. Power-to-gas (P2G) is a concept that is being deployed in Germany and elsewhere in Europe but has barely broken through in energy policy discussions in the USA. Power grid operators have major technical challenges with integrating large proportions of intermittent renewable energy sources such as wind and solar into the grid. Traditionally, supply and demand of electricity are balanced by grid operators who can instruct power plants to ramp up or down. The challenge with wind and solar is that they produce power when the resources are available without regards to demand, so sunny afternoons or breezy nights can see a large ramp up in power production that exceeds demand and forces other power plants to shut down quickly and inefficiently. As the quantity of intermittent renewables climbs this integration challenge grows and has caused a great deal of interest in creating energy storage solutions such as large batteries, flywheels, pumped hydro and others.

Power to gas offers an alternative solution for energy storage by converting excess electricity into hydrogen or methane for storage in the natural gas pipeline networks. The major advantage of P2G is that it leverages existing infrastructure that is endlessly scalable and allows for long term energy storage today. By using P2G, grid operators can manage electric and gas networks simultaneously, creating electricity from gas and vice versa as needed, and overcoming bottlenecks arising from trying to constantly match power demand and supply in a dynamic production landscape.

Renewable natural gas offers robust opportunities to mitigate waste problems while producing high quality low carbon fuels that are suitable for use in heat, power and transportation applications.

sCO2 Offers Zero Emissions Power Plants

Breaking Energy, Nov. 14, 2014 (.pdf)

The Energy Collective, Nov. 18

NET Power, a young company from Durham, NC recently announced they will construct the first of a kind natural gas fueled power generation system with zero air emissions and complete carbon capture. NET Power’s Allam Cycle technology combines oxy-fuel combustion with a supercritical CO2 turbine to create power generation at better efficiencies than natural gas combined cycle plants (without carbon capture). The NET Power plant comes in a smaller package at lower cost than NGCC while generating pipeline quality pressurized CO2 as a free output.

NET Power has completed all the partnership agreements for a 50MWth demonstration plant that will be built in Texas and commissioned in 2016. The $140 million project is a collaboration with CB&I, one of the world’s leading energy infrastructure providers, Exelon Corporation who is a major power utility, and Toshiba Corporation who is providing the sCO2 turbines, 8 Rivers Capital is the project developer and owner of the Allam Cycle technology. The project is funded by the partners who are all major industrial players and demonstrates that the technology has great promise.

The most efficient fossil fuel power plants today are natural gas combined cycle, integrated gasification combined cycle (IGCC) for coal, and supercritical coal, all rely on turbines and steam cycles for power generation. Using supercritical CO2 as a working fluid in turbines is a breakthrough in power engineering, the high fluid density of sCO2 enable much smaller hardware packages and efficiencies above 50%. The Allam Cycle also integrates high pressure carbon capture into the system without penalty, while carbon capture in conventional power plants is an expensive add-on that reduces system efficiency.

2014_11_13_NET Power_Allam Cycle

Source: NET Power

NET Power plants using the Allam Cycle are a zero emissions power generation system, there is no smokestack and no water consumption (though water is produced as a product of combustion). The NET Power plant uses oxy-combustion, where fuel is burned with pure oxygen instead of ambient air, this is preferable because air is almost 80% nitrogen and creates harmful NOx pollution when combusted. Oxy-combustion virtually eliminates NOx. Oxygen is produced using an Air Separation Unit (ASU) and combined with fuel and high pressure CO2 in a combustor and sent through a CO2 turbine where power is produced. CO2 and water exit the turbine and go into a heat exchanger where the water is condensed out and some of the CO2 is looped back to the combustor while the rest exits the system through a high pressure CO2 pipeline.

NET Power plants are much smaller than conventional power plants and the small footprint translates to lower capital costs. High pressure is used throughout the system and enables higher power densities as smaller components are used. Since the entire steam process is eliminated including the second turbine and Heat Recovery Steam Generator (HRSG) that gives combined cycle its name, complexity is dramatically reduced.

2014_11_13_NET Power

Source: NET Power

Carbon capture is greatly enhanced in a NET Power plant compared to conventional power plants. Capturing carbon at a conventional steam cycle power plant requires expensive additional equipment such as amine scrubbers and CO2 compressors that are a drain on power production and result in expensive CO2. There is enormous demand for pressurized CO2 for use in enhanced oil recovery but the capture costs thus far have not proven economic and so little progress has been made in commercializing carbon capture.

NET Power plants offer the opportunity to fundamentally reset the economics of carbon capture because it is already built into the system. As long as the LCOE (levelized cost of electricity) produced by the NET Power plant is competitive in the market then the pressurized CO2 is effectively free and only requires a pipeline for transport.

Toshiba has taken responsibility for providing the first-of-a-kind combustor and sCO2 turbine. These components must tolerate high temperature and pressure gas at the turbine inlet. To deal with these conditions Toshiba utilizes specialty materials originally developed for use in high temp steam turbines which Toshiba has extensive experience with. The combustor has been designed to cope with a gas pressure of 300 bars, which is more than 10 times the gas pressure utilized in conventional gas turbines.

NET Power is not limited to natural gas as a fuel. They have designs for coal as well that integrate gasification and removal of all pollutants. NET Power is currently working on feasibility studies for coal that build on the natural gas platform. By combining coal gasification with various stages of water scrubbing they are able to effectively remove all of the sulfur, nitrogen, particulates and heavy metals found in coal without the use of more expensive acid gas removal technologies. The pollutants are purified and available to be sold as commodities.

2014_11_13_NET Power executives

From Left to Right: Yoshihiro Aburatani, Executive Officer and Senior Vice President, Toshiba Corporation Power Systems Company; Philip Asherman, President and CEO, CB&I; Chris Crane, President and CEO, Exelon Corporation; Bill Brown, CEO, 8 Rivers Capital and NET Power. (Photo: Business Wire)

Wyoming LNG Roadmap

Published at FC Gas Intelligence, Nov. 13, 2014

The Governor of Wyoming, Matt Mead, is all in for natural gas. The Governor commissioned a report titled the Wyoming LNG Roadmap. The report finds that Wyoming is well positioned to lead the USA in the development of a robust, sustainable LNG industry for High Horsepower (HHP) applications.

The report is a comprehensive analysis of the feasibility, potential, costs and benefits of using liquefied natural gas to replace or supplement diesel fuel in Wyoming’s HHP sectors. The roadmap will be used to help guide the state in its development of energy policies and educational programs, as well as identify ideal opportunities for investment in infrastructure and technology to help spur natural gas market development.

Natural gas can help spur job growth while improving air quality and at the same time save money by displacing more expensive diesel fuel that is used in large quantities by high horsepower applications in Wyoming such as mine trucks, locomotives, energy exploration and production engines, and over-the-road trucking.

Wyoming has vast natural resources and is one of the world’s most prolific energy-producing regions. Wyoming ranks number one among US states in coal production and produces about 40% of all the coal mined in the USA. Nine of the country’s top ten coal mines are located in Wyoming’s Powder River Basin (PRB). Wyoming ranks third among states in natural gas production, producing 9% of American natural gas, and has an estimated 35 trillion cubic feet of reserves. WY also ranks eighth among states in oil production. These vast resources and activities translate to heavy use of HHP equipment and diesel fuel.

The collective market for mine haul trucks, locomotives, drill rigs, pressure pumping services, on-road semi-tractors and other large off-road equipment is about 634 million gallons of diesel/year. There are about 16,000 diesel-powered units collectively in the six sectors using tens of thousands of gallons of fuel annually.

The primary driver for a transition to natural gas as a replacement for diesel fuel is economics, LNG is 40% cheaper than diesel on an energy equivalent basis. Secondly, reducing emissions from diesel of criteria pollutants and greenhouse gasses is also very important. Finally, the ability to leverage a “home-grown” fuel in will both improve Wyoming’s employment and economy and improve energy diversity.

For a conversion to natural gas to achieve attractive economics two key parameters must be met. First there must be high annual fuel use and secondly there needs to be a large price differential between LNG and diesel. In Wyoming’s very large HHP sectors, both of these factors point to very favorable economics for conversion to LNG.

2014_11_12_gas oil price spread

Baseline diesel use as compiled in the report is as follows:

2014_11_12_WY_diesel use

2014_11_12_WY fuel savings

2014_11_12_WY_costs

According the assumptions built into the report, the potential “upper bound” demand for LNG in Wyoming over the coming decade is estimated to be approximately 186 million LNG gallons per year (GPY). This is equivalent to 509,000 gallons per day (GPD) of LNG production, or approximately 38.7 million cubic feet per day (MMcf/D).

This upper bound estimate for LNG demand in Wyoming’s HHP sectors refers to a time frame of 10 to 20 years to reach full fruition. For this LNG demand to be fully realized, LNG-ready HHP vehicles and equipment will need to be deployed in careful orchestration with Wyoming’s build-out of the supporting fuel production, distribution and dispensing facilities.

Each of the industries surveyed is going through their own research and development processes to commercialize LNG equipment suitable for their needs. None of the industries have mature technology packages available today for using natural gas, but in all cases key technical hurdles have been overcome and pilot projects have been successfully completed. There are three categories of natural gas engines, Dual-Fuel combines gas with diesel in varying quantities in retrofitted diesel compression engines. High Pressure-Direct Injection uses a small amount of diesel and mostly natural gas, it was developed by Westport and has been adopted by Caterpillar for their mining trucks and is also used in over-the-road trucking and can be retrofitted or built into new engines. Spark ignition engines are mostly new build engines and works well in medium sized engines but lacks horsepower for the most demanding applications.

2014_11_12_WY LNG tech

An estimated $327 to $400 million in capital investments will be required to build out Wyoming’s infrastructure to be capable of producing, distributing, storing and dispensing 509,000 GPD of locally sourced LNG. This level of investment in state-of-the-art gas processing facilities, LNG production plants and supply chain infrastructure will bring compelling economic benefits to Wyoming that are expected to include direct infusions of capital into the Wyoming economy and the creation of well-paying technology-based jobs in construction and operations.

There will be new opportunities for Wyoming to develop educational programs and curriculum focused on clean energy technology in general, and the HHP LNG sector in particular. This will provide major new opportunities for cutting-edge education, technical training, skill development, and high-income employment for Wyoming’s residents.

New LNG sources will need to be developed in close proximity to centers of concentrated fuel demand which will be around the Powder River Basin (Campbell and Converse Counties) and in the Southwest part of the state. The authors of the report find that it would be best not to build one large centralized LNG plant due to high capital costs for developers who would face risks over the ten to twenty year phase in of the LNG market. Secondly, there would be higher costs for consumers of LNG if it is transported over 250 miles.

The optimal approach would be to develop multiple localized mid and small scale LNG production facilities (100,000 to 250,000 GPD). These centralized plants could be supplemented by numerous micro-scale LNG production plants (5,000 to 10,000 GPD) in more remote locations where smaller volumes are needed, such as at a mine facility where they fuel their local fleet of trucks.

“This report shows there is potential for expansion of LNG use in Wyoming that can add value to our natural gas, be a sound business decision for Wyoming industries and lead to job growth,” Governor Mead said. “I felt this was an opportune time to team up with private companies to facilitate research and understand what possibilities exist. The private sector will ultimately make investments in LNG technologies based on market conditions, and this report can be a catalyst.”

The Wyoming LNG Roadmap report was written by Gladstein, Neandross & Associates, North America’s leading clean transportation and energy consulting firm, who were joined by a coalition of private-sector businesses: Ambre Energy, Anadarko Petroleum, Caterpillar, Chart Industries, Desser-Rand, Eagle LNG Partners, Encana, Ensign, GE Oil & Gas, ONEOK Partners, TallGrass Energy, Westport, and Wyoming Machinery.