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Shale Gas -- Friend or Foe

Natural Gas Well
Since I reside in Palm Beach County, FL, I pay attention to my local electricity rates, provided by Florida Power & Light [FPL] -- a regulated utility. Recently, FPL lowered its rates by about 2% for 2012. FPL President and CEO Armando J. Olivera stated the market prices of natural gas for 2012 are trending even lower than previously expected, and this is driving a significant reduction in our projected fuel costs for the coming year.

The price of natural gas dropped from about $13/MMBTU in mid 2008 to its present price, approximately $4/MMBTU. The lower natural gas market prices are due to Shale Gas. Consider that shale gas in 2008 comprised about 11 percent of all natural gas production. But by 2010, the shale gas component jumped to 27 percent and by 2015, it will be 43 percent. This prediction attributed to IHS Global Insight (D. Yergin Dec. 2011), which says that by 2035 shale will amount to 60 percent of all natural gas production. Black & Veatch predicts the price of natural gas to remain stable until 2015 [Dec. 2011].

What is Shale Gas?

Shale gas -- a so-called unconventional resource -- never left its birthplace. It's still in the source bed whose organic matter gave rise to the gas. Because the pores in the fine-grained shale are not well connected, the rock is too impermeable to let the gas go i.e. tight shale formation.

The two basic tools drillers needed to unleash unconventional shale gas were already on hand, waiting to be combined and refined. From the offshore oil and gas industry, they borrowed horizontal drilling. The ability to drill straight down and then bend the hole, thus, making it possible to drain much more of a reservoir from a single offshore drilling platform. Onshore, horizontal drilling out to about 8000 feet from a drill site can multiply the length of a single well within a gas-bearing shale layer by five or 10 times.

The other tool was hydraulic fracturing, or fracking. Drillers pressurize a horizontal section of a well by rapidly pumping in 3 million or 4 million gallons of water (plus a bit of fine sand and chemicals) to pressures of up to 1000 pounds/square inch [psi]. The extreme pressure creates a football-shaped cloud of fractured shale about 1000 feet long, the fractures remaining propped open by sand grains. Repeat up to 30 times in one well and drill tens of wells from a single site; avoiding the costs of several vertical wells.

Using horizontal drilling and hydraulic fracturing requires just one well typically costing about $3.5MM -- as opposed to drilling several vertical wells to recover the shale gas.


In June 2010, MIT predicted that the 2000 trillion cubic feet [Tcf] of recoverable natural gas in the United States -- equivalent to a 92-year supply under current consumption rates -- will increasingly contribute to generating electricity over the next 40 years and that unconventional resources like shale will be a primary reason for that growth. A report released in July 2011 by the U.S. Energy Information Administration (EIA) estimates that there is approximately 750 Tcf of recoverable natural gas in the shale plays of the Lower 48 states alone -- providing about 35 years of supply at current demand levels. Either prediction offers an abundant supply of economically recoverable natural gas.


The accompanying figure depicts the location of Shale Gas fields in the USA (per USEIA March 2010). The following lists these fields:

In most cases these drilling depths are well below potable aquifer levels. In Dec 2011, during its study of Pavillion WY for more than two years, the USEPA stated that drilling is more remote and fracking occurs much deeper than the level of groundwater that would normally be used.

Increased Demand

EPA and local regulations could lead to 45 gigawatts of coal-fired power generation being retired by 2020, stimulating as much as five billion cubic feet a day (bcfd) of gas demand just to offset lost generation from the idled plants. Total gas demand growth in the power sector alone could range between 8-10 bcfd by 2020.

Conversion of older, smaller coal-fired plants to natural gas reflects a growing trend with electric utility industry. An analysis by the Associated Press [Dec. 2011] indicates that 32 coal-fired power plants in a dozen states will be forced to close and an additional 36 might have to close. The majority of these plants are located in KY, VA, OH, TX, IN, NM, MN, MI, MO proximate the Shale Gas formation. Depending upon the specifics of each plant abandonment or conversion may occur. In some instances, depending on MW capacity, the conversion could be for base or peak demand. In either case Natural gas demand will grow as these conversions occur. This increased demand, occurring after 2015, could raise the price of natural gas. The private sector investment recognizing the probability has invested tens of billions of dollars in Shale Gas development and infrastructure.

Converting a coal plant to natural gas should cost about $440/KW ($2011). The cost to retrofit a coal-fired plant to meet SOx,NOx and Mercury emission limitations should be about the same as converting to natural gas. The Operating Cost of natural gas is about 10% lower than coal-fired plants ($2011). Natural gas conversion, either base-loaded or peaking, would cost the electric utility less.

Profit Incentive

Exxon Mobil Corp.'s purchased XTO Energy for $34.9 billion. If ExxonMobil's predictions are right, unconventional formations such as shale would provide significantly more of this country's generation and transportation fuels.

As for XTO, its holdings include the Bakken Field in North Dakota as well as those in the Appalachian region. But other fields such as the Barnett Shale in the Dallas area now supply 6 percent of the nation's natural gas. XTO's field also include the Haynesville Shale project in Louisiana and Texas as well as the Marcellus field that stretches from New York State down through Appalachia. Estimates are that 21 shale beds exist in 20 states but that it will take several years to prepare them for development.

BHP Billiton Ltd. agreed to pay about $12.1 billion for Petrohawk Energy Corp. to expand its presence in U.S. shale. Since June 1, 2011, companies including Exxon, Marathon Oil Corp. and Malaysia's Petroliam Nasional Bhd have announced at least $7 billion worth of North American shale-gas deals. In Oct. 2011, Kinder Morgan announced plans to buy El Paso Corp. for $38 billion. The combined acquisition would include 80,000 miles of pipelines spanning nearly all of the major unconventional [shale] gas formation.

Overlaying the shale gas transportation network, shale gas formations and coal-fired plants slated for abandonment shows close proximity of pipelines, shale gas and power plant (suitable for natural gas conversion). The juxtaposition of these factors creates a scenario for increased power plant demand. The expected increased demand from power sector presents a strong profit incentive for these investments -- given the expectation that natural gas prices will rise in a few years.

Job Creation

Oil and Gas Production currently employs 440,000 workers -- an 80% increase from 2003. In North Dakota, where 200 rigs are pumping 440,000 barrels of oil per day, there are 16,000 job openings with an unemployment rate equals 3.5% [lowest in USA]. In Pennsylvania, the Marcellus natural gas development has created 18,000 in the first half of 2011 -- overall job creation of 214,000. In Ohio, development of natural gas from Utica Shale has potential to created more than 200,000 jobs by 2015.

Hydraulic Fracturing -- Environmental Concern

Hydraulic Fracturing or Fracking involves the use of large quantities of water, three to eight million gallons per well, mixed with additives, to break down the rocks and free up the gas. Some 10 to as much as 40 percent of this fluid returns to the surface as "flowback water" as the gas flows into a wellhead.

Once a well is in production and connected to a pipeline, it generates what's known as produced water. Flowback and produced water contain fluid that was injected from surface reservoirs--and 'formation water' that was in the shale before drilling."

These flowback fluids carry high concentrations of salts, and of metals, radionuclides and methane. Such chemicals may affect surface and groundwater quality if released to the environment without adequate treatment.

Job and economic growth has not deterred State Regulatory Officials from imposing their own constraints on shale oil gas development. In PA salt-laden fracked water must be recycled instead of disposed and/or sent to local municipal treatment plants. In both south Texas and North Dakota, local water scarce regions, hydraulic fracturing water usage is scrutinized to minimize impact to regional aquifers.

While the states recognize the economic benefits of Oil Gas Shale Production, they are holding industry accountable for its environmental compatible development. The scientific consensus, regarding "fracking's" environmental effect is unclear.

On April 16, 2011, House Democrats representing the Energy and Commerce Committee (Henry A. Waxman), Natural Resources Committee (Edward J. Markey), and Oversight and Investigations Subcommittee (Dina DeGette) released a report that stated no scientific data to support this assertion and ignore fundamental principles of toxicology, epidemiology, and risk assessment that would be needed to determine, scientifically, whether hydraulic fracturing chemicals could be harmful to people or the environment. The report's conclusion that "questions about the safety of hydraulic fracturing persist" cannot fairly be drawn from the data presented.

Duke University researchers found that methane levels were on average 17 times higher in groundwater near fracking sites compared with areas where no gas drilling had occurred. Recently U.S. Department of Energy Secretary Steven Chu formed a subcommittee of industry, environmental and state regulatory experts to make recommendations to improve the safety and environmental performance of natural gas hydraulic fracturing from shale formations.

The group -- part of the Secretary of Energy's Advisory Board-- reviewed and identified steps that can be taken to improve the procedure's safety. Their report, intended to offer advice on practices for shale extraction to protect human and environmental health, was completed in Dec. 2011.

The report's recommendations cover four areas:

  • Making information about shale gas production operations more accessible to the public, including full disclosure of all chemicals used in hydraulic fracturing fluids. The report said no economic or technical reason exists to prevent disclosing all chemicals. It also called for creating a national database of all public information about shale gas and government funding for existing multi-stakeholder mechanisms such as the non-profit Ground Water Protection Council's Risk Based Data Management System and the State Review of Oil and Natural Gas Environmental Regulation.

  • Pursuing measures to reduce "as quickly as practicable" emissions of air pollutants, ozone precursors and methane. The report also recommended that a federal interagency planning effort be launched to acquire data and analyze the greenhouse gas footprint of shale gas operations throughout the lifecycle of natural gas use, and compare it to other fuels. The report urged adoption of a systemic approach to water management based on consistent measurement and public disclosure. The report also recommend field studies on methane leakage from hydrofractured wells to water reservoirs and adopting requirements for background water quality measurements to record existing methane levels in nearby wells prior to drilling.

  • Creating a shale gas industry operation organization with external stakeholders and dedicated to continuous improvement of best practice through the development and sharing of standards and the assessment of member compliance.

  • Commissioning research and development to improve safety and environmental performance. The report said that while the majority of shale gas R&D will be done by the oil and gas industry, there is a role for the federal government.

I would add the following to this list:

  • Recycle/treat 'flow back' waters

  • Establish Background of Water Quality before 'Fracking'

  • Continuous Monitoring Flow Back waters

  • Professional Engineer to Design and Seal Cement well casing -- avoid spill e.g. BP Oil Spill GOM

The tremendous volumes of water required (typically two to five million gallons per well), of which 25% to 100% may be returned to the surface as flowback water, must be recovered and disposed of responsibly (or recycled for further industrial usage) before gas production can commence. For western US states, in particular, freshwater supplies are already extremely scarce; thus, hydraulic fracturing can further strain existing water resources. Water used for drilling and fracking active wells in.

The industry, recognizing the water usage issues associated with hydraulic gracturing are improved their technologies. For example, Halliburton has recently commercialized a RapidFrac system uses a metering process that enables a single ball to open multiple sleeves isolated within an interval by swellable packers. Each RapidFrac sleeve can be tailored to specific fracture requirements along a horizontal wellbore so as to enhance post-frac production. Up to 90 sleeves can be incorporated into any one horizontal completion, ensuring maximized stimulated reservoir volume. By facilitating continuous pumping, the RapidFrac system reduces stimulation cycle time from days to hours and reduces the volume of water consumed. Besides attracting private sector investment and creating new jobs, Non-conventional Shale Gas projects are developing improved technology to address evolving environmental issues.

Technically Viable Environmental Regulation -- Shale Gas

The Shale Gas industry may have learned a lesson regarding bureaucratic ineptitude from the Gulf of Mexico Macondo Oil Spill. Their fear may be that lack of expertise in tight shale gas formations would create a 'One-Size Fits All' federal regulatory menu. The variation in geological formation from one region to another (i.e. Permian vs. Marcellus) is being dealt with at the state level. Introduction of USEPA federal mandate, lacking expertise and site specific knowledge, could lead to unnecessary delays.

Rather than generating technically insufficient National Standards, USPA could simply review the applicants proposed methodology -- asking questions regarding areas of concern. Such a review would occur on the regional level and would include state regulators and project applicants. This approach has worked well in other federal review processes e.g. Coal Ash Disposal Sites.


Over reliance on Natural Gas to supply base-load power plants introduces a risk dependency relationship. Duke Energy Corp. CEO James E. Rogers said the U.S. should be careful about relying on natural gas for energy. The electric utilities' increased demand for Natural Gas may cause a price revision by late 2012. Commodity traders expect to see buying opportunities through 2013 while sellers are advised to wait until mid-2012 at the earliest.

So for a few more years Natural Gas prices [Shale Gas induced] will remain close to $4/MMBTU. Afterwards Shale Gas could be blamed for inducing a false sense of price stability because cost of electricity may increase.


Bagawabdoss,K.M.; "Hydraulic Fracturing and its Impacts"; Pollution Engineering Webinar, December 8, 2011

Energy Central Webcast "Harnessing Disruption -- A Conversation with Daniel Yergin"; Dec 15, 2011

Goodwin R.W.; "Natural Gas Power Plants' Fuel of Choice; Energy Pulse Weekly; July 26, 2011

Solomon, D. and Gold, R.; "EPA Ties Fracking , Pollution"; The Wall Street Journal' December 9, 2011

Wood, V.; "Natural Gas Price Picture May Change by Late 2012"; Pipeline & Gas Journal; September 2011

Yergin, D.; "America's New Energy Security"; The Wall Street Journal; December 12, 2011