Hughes, David J. May 2011. Will Natural Gas fuel America in the 21st century? PostCarbon. 66 pages
Without shale gas, U.S. domestic gas production is projected to fall by 20% through 2035. Shale gas is characterized by high-cost, rapidly depleting wells that require high energy and water inputs.
Analyses place the marginal cost of shale gas production well above current gas prices, and above the EIA’s price assumptions for most of the next quarter century. An analysis of the EIA’s gas production forecast reveals that record levels of drilling will be required to achieve it, along with incumbent environmental impacts. Full-cycle greenhouse gas (GHG) emissions from shale gas may also be worse than previously understood, and possibly worse than coal.
Even assuming the EIA forecast for growth in shale gas production can be achieved, there is little scope for wholesale replacement of coal for electricity generation or oil for transportation in its outlook.
Replacing coal would require a 64% increase of lower-48 gas production over and above 2009 levels, heavy vehicles a further 24% and light vehicles yet another 76%. This would also require a massive build out of new infrastructure, including pipelines, gas storage and refueling facilities, and so forth. This is a logistical, geological, environmental, and financial pipe dream.
More than half of the coal-fired electricity generation fleet is more than 42 years old. Many of these plants are inefficient and have few if any pollution controls. As much as 21% of coal-fired capacity will be retired under new U.S. Environmental Protection Agency (EPA) regulations set to take effect in 2015. Best-in-class technologies for both natural-gas- and coal-fired generation can reduce CO2 emissions by 17% and 24%, respectively, and reduce other pollutants. Capturing waste heat from these plants for district and process heating can provide further increases in overall efficiency. The important role of natural gas for uses other than electricity generation in the industrial, commercial, and residential sectors, which constitute 70% of current natural gas consumption and for which there is no substitute at this time, must also be kept in mind. Natural gas vehicles are likely to increase in a niche role for high-mileage, short-haul applications.
Post Carbon Institute undertook this report in order to examine three widespread assumptions about the role that natural gas can and should play in our energy future:
Assumption #1: That, thanks to new techniques for hydraulic fracturing and horizontal drilling of shale, we have sufficient natural gas resources to supply the needs of our country for the next 100 years.
Assumption #2: That the price of natural gas, which has historically been volatile, will remain consistently low for decades to come.
Assumption #3: That natural gas is much cleaner and safer than other fossil fuels, from the standpoint of greenhouse gas emissions and public health.
Based on these assumptions, national energy officials at the Energy Information Administration (EIA) foresee a major expansion of natural gas in the coming decades. President Obama touted natural gas as a cornerstone of his Administration’s “Blueprint for a Secure Energy Future” and endorsed plans for converting a sizable portion of the vehicle fleet to run on natural gas. Some environmental groups, rightly concerned about the greenhouse gas emissions of coal, have called for large-scale replacement of coal-fired power plants with those that burn natural gas, despite increasing concern over the environmental impacts of hydraulic fracturing. As this report details, all of these assumptions and recommendations need to be re-thought.
The shale gas industry was motivated to hype production prospects in order to attract large amounts of needed investment capital; it did this by drilling the best sites first and extrapolating initial robust results to apply to more problematic prospective regions.
The energy policy establishment, desperate to identify a new energy source to support future economic growth, accepted the industry’s hype uncritically. This in turn led Wall Street Journal, Time Magazine, 60 Minutes, and many other media outlets to proclaim that shale gas would transform the energy world. Finally, several prominent environmental organizations, looking for a way to lobby for lower carbon emissions without calling for energy cutbacks, embraced shale gas as a necessary “bridge fuel” toward a renewable energy future. Each group saw in shale gas what it wanted and needed. The stuff seemed too good to be true—and indeed it was.
While enormous amounts of natural gas, oil, and coal remain, the portions of those fuels that were cheapest and easiest to produce are now mostly gone, and producing remaining reserves will entail spiraling investment costs and environmental risks. Moreover, while alternative energy sources exist— including nuclear, wind, and solar—these come with their own problems and trade-offs, and none is capable of replicating the economic delivered in decades past.
There is no likely scenario in which the decades ahead will see energy as abundant or as cheap as it was in decades past. None of the major participants in our national energy discussion wants to utter that dismal truth. Yet continued appeals to wishful thinking merely squander opportunities to pre-adapt gracefully and painlessly to a lower-energy future.
How realistic are the current EIA projections for U.S. natural gas supply given that 45% of it is projected to come from shale gas by 2035?
Only 32% of the energy used to generate electricity is actually delivered to end users. The remainder is lost due to the inefficiency of conversion from coal or natural gas and from losses along the transmission and delivery chain. Moving away from large, remote, centralized sources of electricity generation to local, smaller-scale, distributed sources of generation can serve to increase efficiency and minimize these energy losses, as well as make cogeneration of both heat and power more feasible.
Roughly 68% of the energy used to generate electricity is unavailable due to generation and transmission losses.
Oil accounted for more than 97% of the fuel used by the transportation sector in 2009, which amounted to 29% of total U.S. energy consumption.
If heavy trucks and buses are included, motor vehicles account for 81% of oil consumption in the transportation sector, 58% of all U.S. oil consumption. More efficient rail and ship transport accounted for a mere 6.7% of oil consumption in the transportation sector, 4.8% of total U.S. oil consumption. Air travel accounted for 9.4% of oil consumption in the transportation sector, 6.7% of total oil consumption
Coal is the poor sister to oil and gas in terms of utility for a variety of uses. It is primarily suited as a source of heat in the electricity generation sector and as a source of coke in the production of steel in the metallurgical industry. In 2009, 93% of U.S. coal consumption was used for electricity generation, with practically all of the balance used in the industrial sector, primarily in the steel industry. Coal is unsuited for use in the other sectors without very costly transformations through coal-to-liquids or coal-to-gas technologies. Transforming coal to gas or to liquids involves large capital investments in infrastructure that are roughly equivalent in scale to those required for oil-sands production, and the transformation process entails large energy losses and GHG emissions. As a result, the conversion of coal to gas or liquids in North America is almost nonexistent, and is a very minor source of end-use energy worldwide.
In 2009, 45% of U.S. electricity was generated by coal and 23% by natural gas
EIA projections assume that U.S. shale gas production will nearly quadruple by 2035, when it is supposed to account for 45% of U.S. gas supply. Other estimates for increases in shale gas production are even higher. Some of the most prominent voices promoting the benefits of natural gas are the natural gas producers’ lobby, in the form of the organization America’s Natural Gas Alliance (ANGA), and major shale gas producers such as Chesapeake Energy Corporation.
U.S. natural gas production hit its all-time high of 21.73 trillion cubic feet (tcf) per year in 1973. Up until the late 1990s, the majority of U.S. gas production came from conventional reservoirs, which are pressurized pools of free-flowing gas trapped beneath impervious seals.
Unconventional gas from coalbed methane became important in the early 1990s and was once heralded as a panacea to offset declines in conventional production, although now coalbed methane production is forecast to decline in the future.
Production from unconventional, very-low-permeability reservoirs in the form of tight gas sands and shale gas became significant in the late 1990s and especially over the past six years. Natural gas production is a story about a race against depletion. Typically, the production from a new conventional gas well will decline by 25% to 40% in its first year, before tapering off to lower yearly declines as time goes by. The overall yearly decline rate of all U.S. gas wells has been estimated at 32% by EOG Resources. This means that gas production would decline by a third each year, if no new wells were drilled. Sixty percent of U.S. gas production in 2006 came from wells drilled in the prior four years according to the EOG estimates. Chesapeake Energy has estimated that as of year-end 2007, nearly half of U.S. production came from wells drilled in the previous three years. So in order to keep overall gas supply from declining, drilling activity must be sustained. Natural gas production is also a story about a rapidly increasing number of producing gas wells and a declining amount of gas produced from each. There are now more than half a million producing gas wells in the United States, nearly double the number in 1990 (Figure 10). Yet the gas production per well has declined by nearly 50% over this period. This is a manifestation of the law of diminishing returns, as a complex infrastructure nearly 100% larger than that in 1990 must be maintained today to achieve a 21% increase in natural gas
The law of diminishing returns is further illustrated in Figure 11, which plots the annual number of successful gas wells drilled versus gas production. When gas production peaked in 1973, about 7,000 gas wells were drilled annually. Throughout the 1990s gas drilling averaged about 10,000 wells yearly, which allowed some growth in production. Despite doubling this rate to more than 20,000 wells annually, gas production hit a post-peak summit in 2001 and began to decline. In the run-up to the Great Recession, gas drilling more than tripled from 1990s levels to 33,000 wells per year in the 2006–2008 time frame before falling back below the 20,000 level. This burst of drilling served to grow production modestly to near the 1973 peak, albeit at more than four times the 1973 drilling rate. This “exploration treadmill” indicates the United States will need on the order of 30,000 or more successful gas wells per year to increase production going forward, which is triple the 1990s levels.
Of current drilling activity, some is motivated by requirements to retain leases and is likely otherwise uneconomic. It is unlikely that drilling will rebound to 2008 levels in a low-priced gas environment; hence production can be expected to start falling until prices and drilling activity recover.
The low U.S. natural gas prices observed since late 2008 are a recent phenomenon, yet it is assumed by proponents of natural gas for electricity generation and vehicle transport that prices will remain low for the foreseeable future. The high and volatile prices over most of the past decade have restricted the use of gas for electricity generation mainly to balancing peak loads. Comparatively little gas has historically been used for base load generation, although it is now being contemplated on a large scale. Notwithstanding the fact that the United States was a net importer of 12% of its gas consumption in 2009, the enthusiastic assumption in many quarters of ever-growing U.S. gas production has owners of several LNG import facilities planning to add LNG export capacity to take advantage of much higher gas prices outside of North America. The spread between North American gas prices and the rest of the world has, however, been relatively short-lived, and is unlikely to persist indefinitely into the future. This is obvious to economists like Jeff Rubin, who notes that “far from being the game-changer it’s supposed to be, North American shale gas production isn’t even sustainable at today’s natural gas prices.”
The bottom line with natural gas is that it isn’t so much a matter of the resources in the ground that count. What really counts are the flow rates at which these resources can be produced. The flow rate will determine the ability of natural gas to contribute to future energy requirements, as well as to the social and environmental impacts of this production.
In a 2011 report, the U.S. Potential Gas Committee (a non-profit organization made up of members of the natural gas industry) estimated total U.S. gas resources at 1739 tcf of probable, possible, and speculative resources (of which 687 tcf are shale gas) and a further 159 tcf of coalbed methane, for a total of 1898 tcf.31 Coupled with proven reserves of 272 tcf, this indicated a potential of 2170 tcf.
It has been widely reported that the United States “has 100 years of gas” even though 2170 tcf, if it could actually be recovered, would last much less in actuality given the proposed ramp-up of shale gas production and the proposed increased use of gas for electricity generation and vehicle transport. As mentioned earlier, the most important consideration for the outlook of natural gas is not the estimated volumes of potential resources and proven reserves in the ground, it is the rate at which they can be produced to meet present and future demand. Of the potential resources identified by the U.S. Potential Gas Committee, two-thirds are in conventional and unconventional tight sand and coalbed methane reservoirs, sources that are projected to decline in production going forward. Virtually all growth in gas supply in the current EIA reference case is projected to come from shale gas, which constitutes only a third of estimated U.S. gas resources.
An Overview of Some of the Issues with Shale Gas
Shale gas is a complex and hence high-cost source of natural gas fraught with environmental issues that are now becoming apparent.
Shale is a very-low-permeability reservoir rock that must be fractured to allow conduits for gas to migrate to the production well bore. This is typically accomplished using multiple horizontal wells drilled from a common well pad (Figure 14), with multiple slick water hydraulic fracture treatments in each (from as few as 5 to more than 20 fracture treatment stages per well). Because of the very low permeability of shale, minimum well spacing of 40 to 80 acres37 or less is required—much closer than well spacing for conventional gas drilling, which is typically 160 acres or more.
Water used in drilling and particularly in hydraulic fracturing can amount to between 2 million and 6 million gallons per well. Injected water contains a previously mostly confidential combination of proprietary additives (sand, acid, gelling agents, friction reducers, biocides, corrosion and scale inhibitors, cross linkers, etc.) to facilitate the fracturing and propping open of the fractures after their creation.
The U.S. House of Representatives has recently released a report on the chemicals used for hydraulic fracturing, several of which are carcinogenic and are hazardous air pollutants. Anywhere between 30% and 70% of the injected water is brought back to the surface, along with formation water if it is present. Most of this water is produced in the first few months of production and, as it is toxic, must be disposed of through recycling, through reinjection, or, on the surface, through processing at wastewater treatment facilities.
These and other factors make shale gas wells expensive. Wells typically range between $2 million and $10 million (or more),
Conventional gas wells typically decline by 25% to 40% in their first year of production, whereas shale gas wells decline at much higher rates, typically between 63% and 85%.42 The initial productivity of shale gas wells can be very high. In plays like the Haynesville Shale in Louisiana, initial rates can be more than 10 million cubic feet per day (Barnett Shale wells are typically much lower at about 2 million cubic feet per day). However, their steep production decline rates suggest that relying on shale gas for a large proportion of U.S. gas production will only exacerbate the “exploration treadmill” problem of the number of wells that must be drilled to maintain production. There is simply too little history of shale gas production to substantiate the 40-year well life purported by many shale gas producers. Analyst Arthur Berman, who has studied the Barnett Shale (the oldest and best-known shale gas play) in depth, suggests that the estimated ultimate recovery from shale gas wells and overall recoverable reserves have been overstated by operators, and that shale gas plays are marginally commercial at best in the current low gas price environment.43 A further issue is the extrapolation made in assuming all parts of shale gas plays will be equally productive. Initially, it was assumed that shale gas plays would be “manufacturing” operations, where wells would be equally productive regardless of where they were drilled. This proved to be erroneous.
in the Barnett Shale all 17 counties were thought to be equally prospective a few years ago, but today just two and a half counties have been proven to be highly productive core areas. In the Haynesville Shale play of Louisiana, which in 2008 was promoted as the fourth-largest gas field in the world, the focus of interest has retracted to a core area about 10% of the original area assumed in the optimistic projections.
Contamination of surface water, and potentially drinking water, through improper disposal of toxic produced drilling fluids containing salts, radioactive elements, and other toxins.
Recycling involves distilling purified water from the drilling waste, which still leaves a residue of toxins and is very energy intensive.
The surface impacts of road and drill pad construction and the requirement for hundreds of truck trips for each well
A major argument put forth by natural gas proponents as to why there should be a wholesale switch from coal to natural gas for electricity generation is the fact that CO2 emissions from burning natural gas compared to coal are about 44% less per unit of heat generated through combustion.
This assumes there are no emissions in the upstream exploration, production, and transport of natural gas or coal to the point of use. The EPA has released a new study detailing upwardly revised estimates for fugitive methane and CO2 emissions in the natural gas supply chain, and in particular emissions from unconventional gas well completions and workovers. This study states that “the natural gas industry emitted 261 [million metric tons of CO2 equivalent] of CH4 and 28.50 [million metric tons] of CO2 in 2006.” This amounts to 290 million metric tons of CO2-equivalent emissions, which is 5% of total U.S. end-use emissions and 22% more than the emissions of natural gas included in Figure 8 (which only considers end-use emissions).
According to EPA estimates, vented and flared gas amounted to 4.2% of production over 2006–2008, exclusive of emissions in the transportation and distribution process. ProPublica reviewed the new EPA emissions report and concluded that natural gas may be as little as 25% cleaner than coal, or perhaps even less. An in-depth analysis comparing the full-cycle GHG emissions from shale gas, conventional gas, and surface- and underground-mined coal has been completed by Howarth et al. of Cornell University. In their paper published in April 2011, they state: Natural gas is composed largely of methane, and 3.6% to 7.9% of the methane from shale-gas production escapes to the atmosphere in venting and leaks over the lifetime of a well. These methane emissions are at least 30% more than and perhaps more than twice as great as those from conventional gas. The higher emissions from shale gas occur at the time wells are hydraulically fractured—as methane escapes from flow-back return fluids—and during drill out following the fracturing. Methane is a powerful greenhouse gas, with a global warming potential that is far greater than that of carbon dioxide, particularly over the time horizon of the first few decades following emission. Methane contributes substantially to the greenhouse gas footprint of shale gas on shorter time scales, dominating it on a 20-year time horizon. The footprint for shale gas is greater than that for conventional gas or oil when viewed on any time horizon, but particularly so over 20 years.
Compared to coal, the footprint of shale gas is at least 20% greater and perhaps more than twice as great on the 20-year horizon and is comparable when compared over 100 years.
Another option for gas supply, should the United States commit to large amounts of new gas-fueled infrastructure that cannot be supplied by domestic gas production, is imported LNG. Aside from its higher costs, the life-cycle emissions of CO2 are much higher for LNG than for conventional gas due to the energy required for liquefaction, transportation, and regasification. Jaramillo et al. concluded in 2005 that, on average, LNG-transported natural gas adds 20% more CO2 emissions than conventional gas on a full life-cycle basis. They also concluded that LNG increases emissions for the overall delivery process before the burner tip by 137% on average compared to the emissions for conventional gas (which includes the sum total of emissions in production, processing, transmission, storage, and distribution). A further consideration with LNG is increased reliance on potentially unstable foreign suppliers.
The EIA has become increasingly enamored with huge production increases from shale gas to meet its forecast natural gas demand requirements for the United States.
The enthusiasm of the EIA for shale gas is illustrated in Figure 17, where yearly forecasts for the production of shale gas have increased from 16% of U.S. production in 2030 in its 2009 forecast to 45% of U.S. production in 2035 in its 2011 forecast.
Another key question in the reality check is the marginal cost of production of shale gas. Analysts like Arthur Berman suggest the marginal cost is about $7.50/mcf72 compared to a current price of about $4.00/mcf. Others, such as Kenneth Medlock (2010), suggest that the break-even price ranges from $4.25/mcf to $7.00/mcf.73 The Bank of America (2008) has placed the mean break-even cost at $6.64/mcf with a range of $4.20/mcf to $11.50/mcf.74 One thing seems certain: Shale gas, which appears to be the only hope for significantly ramping up U.S. gas production, is expensive gas, much of which is marginally economic to non-economic at today’s gas prices.
Based on a historical analysis, the annual number of new gas wells will have to be nearly double its projection to achieve its production forecast. This is unlikely to happen without significantly higher prices, which the EIA projection rules out. A more likely scenario, in my opinion, is for declining gas production over the next few years, unless prices go considerably higher to spur increasing amounts of drilling, along with increased price volatility. Based on such forecasts, the assumption of a business-as-usual future with abundant gas supplanting imported oil and replacing coal is folly.
Electricity generation from gas would have to more than double from current levels and overall gas production from the lower 48 would have to increase by 64% to offset the electricity generated by coal in 2009. Given that achieving the 265% growth in shale gas production in the existing EIA reference case is likely to be extremely challenging in itself, and will involve major environmental impacts, the concept of replacing coal with gas is likely wishful thinking at best. The Aspen Environmental Group reviewed some of the logistical bottlenecks to the wholesale transition from coal to natural gas.78 These include the lack of sufficient pipeline capacity in 21 states as well as the lack of storage capacity on the East Coast, in the Central Plains states, and in Nevada, Idaho, Arizona, and Missouri. Aspen concluded that the cost of building gas plants to replace all existing coal plants, plus new pipeline requirements and ancillary infrastructure, would be more than $700 billion.
A legitimate question in this comparison of various gas- and coal-fired electricity generation technologies is the extent to which fugitive methane could be reduced through the application of available technology to capture these emissions. A considerable effort to capture fugitive methane emissions has already been underway for some time through the EPA’s Gas Star Program.115 Howarth et al. (2011) attribute fugitive methane emissions to five components of the supply chain: well completions; leaks at well sites; liquid unloading; gas processing; and transport, storage, and distribution.116 The two largest components for shale gas are well completions (1.9% of total production) and transport, storage, and distribution (1.4% to 3.6% of total production).
The U.S. coal-fired electricity generation fleet is aging. Fifty-nine percent of the existing 1466 plants are more than 42 years old.123 These plants represent 34% of total coal-fired generating capacity. As illustrated by Figure 25, the real construction boom in U.S. coal plants in terms of added generation capacity occurred from the late 1950s through 1990. There has been little added capacity over the past two decades. The older plants are generally of smaller capacity and much worse in terms of efficiency and overall emissions.
The environmental issues associated with these coal plants, aside from CO2 emissions, include emissions of sulfur oxides, oxides of nitrogen, mercury, particulates, and a host of other contaminants. Pollution control technology exists to greatly reduce emissions, but a significant proportion of the coal fleet, in particular the older units, has no pollution controls. Pollution control technologies include: – Scrubbers to remove sulfur oxides and mercury. – Activated carbon injection (ACI) and baghouse (filtration) to remove particulates and mercury. – Selective catalytic reduction (SCR) to remov <You have reached the clipping limit for this item>