In the Dec. 15, 2011, issue of The Energy Strategist Weekly, America’s Overlooked Energy Advantages, I highlighted one of North America’s greatest assets: large quantities of natural gas and crude oil found in shale fields and other unconventional formations. Production from these plays has afforded US consumers a degree of insulation from rising energy prices–a huge economic advantage relative to households in Asia and Europe.

At the same time, North American producers and services firms have amassed unparalleled, real-world experience in extracting oil and gas from unconventional fields. Access to this knowledge, coupled with a benign operating and political environment, has prompted major investments from international oil companies such as BP (LSE: BP, NYSE: BP), Total (Paris: FP, NYSE: TOT), Reliance Industries: (Bombay: 500325) and Statoil (OSLO: STL NYSE: STO). (We highlighted some of these deals in The Future of Shale Gas is International  and Wheeling and Dealing in the Utica Shale.)

A number of innovations have enabled producers to unlock the oil and gas resources trapped in unconventional fields such as the Bakken Shale in North Dakota and the Marcellus Shale in Appalachia. But two breakthroughs catalyzed the shale oil and gas revolution: horizontal drilling and hydraulic fracturing.

Horizontal Drilling Explained

This diagram from the North Dakota Petroleum Council illustrates the benefits of horizontal wells, compared to traditional, vertical wells.

Source: North Dakota Petroleum Council

The Bakken Shale formation is located roughly 8,000 feet to 11,000 feet below the surface in many of the play’s most-productive regions. This image omits several other rock strata above and below the Bakken: the Madison Group, which rests above the Bakken; the Three Forks, another oil-producing deposit below the Bakken; and the Birdbear, Duperow, Prairie and Interlake formations.

­­­­­Not all these rock formations contain commercial quantities of oil and gas. Let’s say a producer is targeting a productive layer that’s about 150 feet to 200 feet thick. If the producer were to drill a vertical well through the formation, only a 150- to 200- foot section of the well would yield oil.

The well would be far more productive if the producer were to drill a 10,000-foot horizontal well off the vertical shaft to increase exposure to the productive region of the play. Horizontal wells–particularly those with longer laterals (the horizontal segment)–are usually more expensive to drill than traditional wells and require advanced equipment.

But these additional costs and complexities don’t prevent operators in the Bakken and other prolific plays from earning internal rates of return in excess of 100 percent.

Hydraulic Fracturing Explained

Conventional oil and gas fields occur in rock formations with some degree of permeability. Check out this image of sandstone, a common reservoir rock in conventional oil and gas plays.

Source: Geology.com

As you can see, the porous and permeable sandstone includes plenty of chambers in which oil and gas can accumulate and plenty of channels through which the hydrocarbons can flow.

Shale plays and other “tight” oil and gas fields lack permeability; that is, the hydrocarbons can’t flow through the reservoir rock.

Source: Geology.com

Hydraulic fracturing is a process whereby producers pump a liquid into a shale reservoir under such tremendous pressure that it cracks the reservoir rock. This creates channels through which hydrocarbons can travel, improving permeability. Over the past several years, US producers have honed this technique in a number of prolific shale gas plays, increasing the number of fracturing “stages” along the lateral portion of a horizontal well.

Fracturing fluid is primarily composed of water and sand or ceramic particles (proppants) that enter the cracks and “prop” them open when the fluid is removed.

The exact composition of fracturing fluid differs depending on local geologic conditions, and producers often arrive at the best cocktail after a period of experimentation. Not surprisingly, some in the industry have been loath to tip their hand and lose their competitive advantage.

Some states have mandated that producers disclose the composition of their fracturing fluid to regulators, while some producers have shared the basic components of their secret sauce.

For example, Canada-based Talisman Energy’s (TSX: TLM, NYSE: TLM) website lists the ingredients in the typical fracturing fluid that the company would use in a 10-stage well in the Marcellus Shale. Water makes up 90.71 percent of the mixture, with sand accounting for 9.12 percent of the mixture and assorted chemicals accounting for the remaining 0.17 percent.

The recipe calls for about 1 gallon of friction reducer for every 2,000 gallons of water; 1 gallon of scale inhibitor for every 10,000 gallons of water; 1 gallon of a biocide for every 2,000 gallons of water; and 3,000 gallons of acid (diluted to 7.5 percent) for the entire well.

Here’s a look at some of the chemicals that make up the last 0.17 percent of Talisman Energy’s fracturing fluid.

FRP-121 is a polyacrylamide (PAM) that acts as a friction reducer. Outside the energy industry, PAMs are sprayed on the ground to reduce erosion caused by storm-water runoff. PAMs are also used in the manufacture of paper and soft contact lenses.

Dibromo-3-nitrilopropionamide (DBNPA) is a pesticide, algicide and bactericide used to prevent the buildup of slime in fracturing fluid. DBNPA is also used to disinfect lab equipment and as a slimicide in cooling systems and papermaking. The Food and Drug Administration regulates its use in food packaging.

Surfactants reduce the surface tension of water and are used primarily in detergents. Talisman Energy doesn’t disclose the surfactants in its fracturing fluid.

Ethylene glycol is an organic compound widely used as antifreeze in automobiles and to produce certain synthetic fibers.

Although you wouldn’t want to drink a glass of these chemicals everyday to start your morning, the media tends to overhype the health risks associated with fracturing fluids, often citing the industry’s secrecy regarding these proprietary mixtures. However, many individual investors aren’t aware of the relatively small concentrations of these chemicals in fracturing fluid.

During the Live Chat on Dec. 15, 2011, many subscribers asked whether the US Environmental Protection Agency (EPA) would attempt to ban fracturing outright or increase regulation to the extent that the practice is no longer economically viable. Environmentalists have long expressed concern that either the fracturing fluid or hydrocarbons could seep into and contaminate the supply of drinking water.

On Dec. 8, 2011 the EPA released a draft of Investigation of Ground Water Contamination near Pavillion, Wyoming, an inquiry prompted by residents’ complaints of unpleasant odors in their drinking water supplies. This report, which is currently open to public comment, suggests that nearby wells may have contaminated the drinking water and, predictably, elicited a chorus of calls to ban hydraulic fracturing.

But this EPA draft isn’t the smoking gun environmentalists have sought. Moreover, a ban on or restrictive regulation of hydraulic fracturing is unlikely in the current economic and political environment.

Background

Pavillion is located in west-central Wyoming, about 230 miles northeast of Salt Lake City. The town is surrounded by ranch and farmland and has a population of about 175 people.

Canada-based EnCana Corp (TSE: ECA, NYSE: ECA) acquired its Pavillion assets from another firm in 2004 and produced about 10 million cubic feet of natural gas per day from 125 producing wells. The wells in this mature field represent roughly 0.25 percent of EnCana’s 2010 oil and gas output. The company sank 44 of these wells between 2004 and 2007, but depressed natural-gas prices prompted management to discontinue further investment in the area.

Producers have drilled in this conventional field since 1960. More recent wells near Pavillion used hydraulic fracturing to bolster production rates.

Most of the major unconventional natural gas fields in the US are located at least 8,000 feet to 10,000 feet beneath the Earth’s surface. However, the typical gas well in Pavillon only penetrates 1,000 feet to 1,500 feet into the ground. According to the EPA, EnCana sank its shallowest, fractured well to a depth of about 1,250 feet.

In addition to its shallow reservoir rock, the field also lacks a “cap rock”–an impermeable rock layer that prevents the gas from migrating upward–between the reservoir rock and levels closer to the surface.

The EPA report notes that household and livestock drinking wells in the area go as deep as 800 feet. However, most drinking wells in the Pavillion area are 300 feet to 500 feet deep; in fact, it would be unusual for wells in much of the country to go deeper than 800 feet to 1,000 feet.

Both EnCana and the EPA have acknowledged that the area includes a number of surface- production pits in associated with older drilling operation that were used to store and dispose of drilling waste and fluids. In 2005 ECcana identified all of the pits on its acreage and launched a remediation program in cooperation with the state to limit groundwater contamination from these sites.

To test for potential contamination of drinking water, the EPA conducted four sampling events:

• Phase I involved collecting groundwater samples from residential wells and two municipal wells in the town of Pavillion;

• During Phase II, the EPA collected a second round of samples from residential wells;

• Phase III involved collecting samples from two monitoring wells drilled by the EPA, the 784-foot deep MW01 and the 980-foot deep MW02; and
• Phase IV entailed further sampling from the monitoring wells and expanding the range of compounds and chemicals for which the EPA was testing.

Study Results

The media and environmental groups have latched on to one statement from the report’s abstract:

Alternative explanations were carefully considered to explain individual sets of data. However, when considered together with other lines of evidence, the data indicates likely impact to ground water that can be explained by hydraulic fracturing.

This marks the first time a significant study has linked groundwater contamination to fracturing. A previous EPA study conducted while George W. Bush was in office concluded that the practice posed “little to no threat” to nearby drinking water supplies.

Quite simply, the results from such a shallow field are hardly a nail in the coffin for hydraulic fracturing in the large-scale developments underway in the Bakken Shale, the Eagle Ford Shale and other plays.

However, the findings might be applicable to efforts to exploit coal-bed methane, or natural gas that’s been trapped in seams of coal deposits. These formations are often located only 1,000 feet to 1,500 feet from the surface. In the US, producing coal-seam gas is generally uneconomic in the current pricing environment.

Moreover, the EPA’s tests revealed the presence of natural gas and other chemicals, but the agency noted that the levels found in water wells didn’t exceed established standards:

Detections in drinking water wells are generally below established health and safety standards. In the fall of 2010, the U.S. Department of Health and Human Services’ Agency for Toxic Substances and Disease Registry reviewed EPA’s data and recommended that affected well owners take several precautionary steps, including using alternate sources of water for drinking and cooking, and ventilation when showering. Those recommendations remain in place and EnCana has been funding the provision of alternate water supplies.

Notably, even in water wells less 90 feet deep, neither the EPA nor EnCana found levels of contamination that exceed health and safety standards. Over the course of seven rounds of tests conducted in conjunction with the Wyoming Dept of Environmental Quality between 2005 and 2007, the oil and gas found only small amounts of gas in local drinking water.

Natural-gas migration is another potential explanation, particular in such a shallow formation. This phenomenon isn’t without precedence–the eternal flame at the famed Oracle of Delphi in ancient Greece was from natural gas flowing to the surface. The first commercial oil well drilled by Colonel Edwin Drake in Titusville, Pa., was in an area where oil had naturally seeped to the surface for decades. In many parts of the country, natural gas has been found in well water long before major gas production and certainly before the widespread use of hydraulic fracturing.

With regard to Pavillion, reports of poor-quality drinking water predate the oil and gas inventory’s advent in the region. According to studies from the US Geological Survey (USGS) cited by EnCana, complaints about water quality date back to the 1880s–80 years before producers started drilling for gas in the area.

In 1959, the year before producers spudded the first well in the area, a USGS report documented Pavillion water as unsatisfactory for domestic use because of its high pH and elevated amounts of dissolves solids and sulfates. In that light, one shouldn’t be surprised that EPA identified these same issues more than 50 years later.

Another possible issue causing gas to seep into shallower wells is the inferior drilling technology used decades ago. To its credit, the EPA report discusses wells that have improper casing or cementing in place. A casing is a heavy metal pipe used to isolate producing parts of a well from other formations such as water aquifers located at shallower intervals.

There’s evidence that reports of ground water contamination with gas in other areas of the country, including the Marcellus, is more likely to be the result of older wells drilled at much shallower depths than newer wells. Drilling technologies and techniques have improved dramatically over the past several decades.

Moreover, the EPA’s monitoring wells, which reached greater depths than virtually all water wells in the area, were the ones that evinced elevated levels of natural gas and chemicals. This finding should hardly come as a surprise: Producers drilled to similar depths to tap into the productive part of the formation.

The EPA acknowledged as much in the draft released on Dec. 12:

A review of open-hole geophysical logs obtained from the WOGCC [Wyoming Oil and Gas Conservation Commission] internet site indicates the presence of gas-filled porosity at three locations at 198, 208, and 252 m[eters] between the years 1965 – 1973 suggesting the presence of natural gas in ground water at depths used for domestic water supply prior to extensive commercial development.

In other words, drilling results from the late 1960s and early 1970s found gas at depths of 198 meters to 252 meters (about 650 feet to 826 feet); the monitoring wells of 784 feet and 980 feet sunk by the EPA were drilled in an area where producers traditionally encountered gas.

In a refutation of the EPA report, EnCana summarize its counterargument succinctly: “Natural gas developers didn’t put natural gas at the bottom of EPA’s deep monitoring wells, nature did.”

Based on these irregularities, the EPA report is all smoke and no gun. We don’t expect the preliminary findings in this draft to lead to an outright ban on hydraulic fracturing or prohibitive regulation.

The Political Equation

For better or worse, the EPA is prone to political bias and influence, as the president appoints the agency’s administrator. The environmental regulator came under criticism when George W. Bush was in office, deeming a 2004 report on hydraulic fracturing too industry-friendly; under the Obama administration, Republicans have charged that the activist EPA has become overly aggressive in its attempts to regulate the energy industry. In each case, there’s a kernel of truth.

Although some environmental groups have lobbied for increased use of natural gas–the relatively clean-burning fuel emits less carbon dioxide than coal and virtually no mercury or sulfur dioxide–hydraulic fracturing is an undeniably controversial issue. Groups hostile to natural gas and fracturing often champion solar and wind power as suitable alternatives.

Consider this June 27, 2011, blog post by Phil Radford, executive director of Greenpeace:

Top decisionmakers in Washington seem to have forgotten that “natural” gas is a fossil fuel, with some of the same damning negatives as coal and oil.

For instance, unlike renewables, “natural” gas is an energy source we will exhaust – possibly sooner than previously thought. Let’s not forget that the recent rise of hydraulic fracturing (fracking) couldn’t have happened if we hadn’t nearly exhausted easily extracted gas supplies already. And now it turns out that this fracking boon may be partly a matter of industry hype.

The extraction of natural gas–especially via fracking–is incredibly harmful to the environment and people’s health. If you aren’t alarmed by increasing instances of flammable tapwater from methane leaks caused by drillers messing with geology, then maybe diesel and cancerous chemicals in the water will sound a few bells.

Unfortunately, Congress exempted the “natural” gas industry from practically every type of pollution law, and there are no plans to remove this special treatment. Now, the EPA and DOE want to study the damages of fracking, a little after the fact. But one thing they aren’t studying is whether fracked gas can legitimately be called a transition fuel from coal to renewables. Burning gas creates half the CO2 of coal combustion, but a recent study shows that fracked gas may release so much of a worse global warming pollutant (methane) into the air that it cancels out any benefit to the climate.

One thing is certain about the “natural” gas industry. They need no support from politicians.

In this except, Radford alludes to a series of articles published by the New York Times that questioned the sustainability of US shale oil and gas revolution, though the claims in the articles have been widely discredited in subsequent months. I addressed these articles in a Flash Alert from June 30, 2011, Don’t Believe the Hype.

Subscribers should be well aware of the shortcomings of wind and solar power, a topic I addressed at length in the Nov. 1, 2011, issue of The Energy Strategist Weekly, Popping the Green Bubble.

Unfortunately, the intermittent nature of wind and solar power–the sun doesn’t always shine and the wind doesn’t always blow–prevents these alternative sources from becoming viable sources of baseload power. In fact, the addition of wind- and solar-power capacity often requires utilities to construct shadow capacity–often natural gas-fired power plants–to make up for the inevitable shortfalls.

To be fair, President Barack Obama has expressed support for increasing the nation’s use natural gas. In a March 30, 2011, speech at Georgetown University, the president highlighted the role natural gas could play in reducing the nation’s dependence on imported oil:

The potential for natural gas is enormous. Last year, more than 150 members of Congress from both sides of the aisle produced legislation providing incentives to use clean-burning natural gas in our vehicles instead of oil. And–and that’s a big deal.

President Obama has also taken some flak from his own party for being too soft on climate change and other issues.

With the presidential election around the corner and an economy that continues to flounder after the excesses of the credit boom, any policy that would potentially increase energy costs would be a major blow to the subpar recovery and the president’s reelection bid. Restrictive regulations on hydraulic fracturing would eliminate the low natural gas prices enjoyed by US households and send oil prices to the moon, as the nation would be forced to import even more crude oil.

This would have ripple effects throughout the economy. Petrochemical producers, for one, would likely mothball plans to build new facilities to take advantage of the nation’s newfound abundance of ethane, a product of liquids-rich shale plays. In short, such a surge in energy prices would likely send the US economy spiraling into recession.

The Bottom Line

The shoddy conclusions in the EPA’s draft report on groundwater contamination in Pavillion, Wyo.–a unique situation, to say the least–shouldn’t prompt restrictive regulation of hydraulic fracturing in commercial-scale plays such as the Bakken Shale, the Eagle Ford Shale or the Marcellus Shale. Moreover, the current political and economic climate makes such a move untenable. Investors should regard investment opportunities pegged to this “eventuality” with the utmost skepticism.