Shale gas revolution in the US presents regulatory and infrastructure challenges

17 January 2011 08:59  [Source: ICB]

While the US chemical industry hails shale gas as the key to sustainable competitive advantage, infrastructure and regulatory challenges could kill the golden goose

Large-volume production of shale ­natural gas in the US could depress the ethane price in the coming years, providing a boon for local petrochemical and polymer producers in the form of cheap feedstock. However, the energy sector has its own brambles to trim to make ethane's path to market viable.

Gareth JJ Burgess
The recent run for shale opportunities - ­likened to the Gold Rush of 1849 - will result in a huge increase in the production of untapped ethane resources. But certain shale plays rich in product, particularly the Marcellus formation, in the Northeast, lack infrastructure for processing or transporting ethane to chemical markets.

In the next five years, additional storage could become necessary to accommodate the growing ethane inventories, says Anne Keller, president of US-based consultancy Midstream Energy Group. But conversion of underground caverns for ethane service is not a time-­consuming project.

The swelling supply, as governed by the rules of economics, would lower the ethane price, Keller says. But the price drop will be limited by the costs of extracting ethane from natural gas streams and processing it. If prices fall below the costs of separating the ethane from natural gas, producers would choose to leave the ethane in the natural gas stream.

Keller says the historical average cost for fractionation and ethane extraction has run at about 10-11 cents/gal (7.5-8 euro cents/gal), but in the last quarter of 2010, it was about three times the average.

The escalation resulted from higher US exports of ethylene derivatives, which have put a strain on fractionation and extraction capacity. The US cost advantage of ethylene produced from cheap natural gas liquids (NGLs) has allowed chemical companies to take advantage and market more ethylene derivatives to countries with production based on more expensive crude oil-based feedstocks.

Northeast shale plays, such as the Marcellus formation, face an ethane supply glut with no foreseeable method to transport ethane to market for at least a year, and likely longer.

"Previously, the natural gas produced in the East Coast region generally had a fairly low NGL content," notes Ron Gist, senior analyst for international energy consultancy Purvin & Gertz. "However, producers found a 'sweet spot' in the Marcellus play in western Pennsylvania and nearby West Virginia that has higher NGL content."

There is no infrastructure - such as fractionators or ethane pipelines - in the Northeast to process ethane gas, so producers have nowhere to sell or use the ethane.

"New-build projects [for ethane] will take 18-24 months if the dirt was turned tomorrow," Keller says. "So unless another solution is in place fairly soon, drillers won't be able to produce from those high-ethane-content wells."

Midwestern and Southern shale developments, such as the Barnett in Texas and Haynesville in Louisiana, do not face this problem as they are closer to the chemical market. In addition, other shale plays have not found "hot spots" of ethane product to cause transportation issues.

With the low price of natural gas, averaging less than $4/MMBtu in the US, ethane gas from the wells cannot be wasted. Producers need to sell the product for additional revenue to maintain their shale operations.

The projected volume of ethane gas production in Marcellus could be as much as 100m bbl/day. More realistically, the production would yield 50m-80m bbl/day when the ability to blend ethane gas into natural gas streams is taken into account, as well as the likelihood of drilling slowing down if natural gas prices don't pick up, Keller says.

The amount of ethane in the wellhead of hot spots exceeds the threshold that can be removed from the natural gas stream in a liquid state, and thereby moved with other liquefied natural gas.

The amount of ethane that can be mixed into the NGL stream for fractionation or transportation by truck or rail is limited to 15% - and with that, most or all of the propane must be removed. In some instances, more than 50% of the ethane needs to be removed from the NGL stream.

As for the option to keep ethane in the natural gas stream, ethane substantially increases the energy content beyond pipeline specifications. "The ethane in [natural] gas raises its heating value to the point that the residue gas leaving the gas processing plants cannot meet the specifications of the local gas pipelines," Gist says.

Typically, gas pipeline specifications for British thermal units (Btu) range from 1,050-1,125Btu/ft³. Natural gas usually ranges from 950-1,150Btu/ft³, while ethane alone has 1,783Btu/ft³. When ethane is mixed with the natural gas stream, it substantially increases the heat content.

Much of the global natural gas market does not face the heat restrictions on ­pipelines, and therefore does not have the same problem with NGLs when tapping into shale reserves.

"Outside of the US, the gas markets have more flexibility around the Btu level they'll accept into a pipeline, so I don't see ethane as an issue in the global market the way it is in the Marcellus region," Keller explains.

Japan, for instance, has a gas distribution grid that requires gas with a higher energy level, to the extent that it will add NGLs to the gas stream to increase the heat content. And countries just developing their gas grids can accommodate higher heat levels as well, Keller says.

As for the restriction on heat levels for US pipelines, there are several projects on the table for moving the ethane out of the Northeast.

Likely the cheapest project of nearly a dozen proposed is the joint venture of Canada-based NOVA Chemicals and US pipeline company Buckeye Partners for an ethane pipeline to Sarnia, Ontario, Canada, where there is underground storage and existing petrochemical facilities.

"The Buckeye Pipeline proposal to build an ethane pipeline to Sarnia makes the most sense," says Dan Lippe, president of US-based energy consultancy Petral Worldwide. "­Sarnia is 400-500 miles [640-970km] from ­southwest Pennsylvania and it has lots of ­storage. More importantly, ethylene ­capacity has an approximate total of about 2.5bn lb/year."

Other proposed projects include US-based pipeline company El Paso's plan for a pipeline to the Louisiana ethane grid using some existing infrastructure; US-based gas processor MarkWest Liberty Midstream & Resources and US-based refiner Sunoco's partnership to move ethane by sea from Philadelphia to the US Gulf; and US-based energy companies Williams Companies and Dominion Resources' plan for a pipeline from the Northeast through the Rocky Mountains.

"Each option has some merits and some disadvantages," Gist says. "Eventually, one of the projects will probably become the preferred choice. We doubt that more than one or perhaps two options will be built."

Shale gas could supply the US for a century, but proposed regulations threaten to reveal trade secrets, delay operations and drive up the price of natural gas.

"One of our highest priorities in this country is to establish energy security and to reduce our dependence on imported oil," says Cal Dooley, president of the American Chemistry Council (ACC). "We see a game-changer here with our ability to capitalize on what is estimated to be a 100-year supply of natural gas in shale deposits."

Abundant domestic supplies of natural gas feedstock have given the US chemical industry an edge for competing in overseas markets, and are a source for industry, commercial use, electrical generation, and residential heating.

"My overwhelming view is that [regulations on fracturing] are under political influence. You see 60 Minutes, and you see CSI: New York and you read about or see Gasland, and then there's the pressure from the White House. There's political motivation in the EPA"
Dan Steinway, partner, Baker Botts
"Developing domestic natural gas will mean billions of dollars in government revenue and reductions in greenhouse gas emissions," says Sara Banaszak, senior economist for the American Petroleum Institute (API).

To access oil and gas in shale formations about a mile below the surface, the industry uses a 60-year-old technology called hydraulic fracturing (fracking). This involves high-pressure injections of water, sand and chemical additives to free oil and natural gas from deep rock formations. The fracking happens thousands of feet below the water table, which is where groundwater settles.

Environmentalists homed in on the 0.5% of chemical additives in the fracking process - mainly biocides and corrosion inhibitors that help prevent contamination of the oil and gas.

"[Fracking] has been found responsible for contamination of well water, filling a basement with methane and blowing up a house in Ohio, and poisoning 17 crows in Louisiana," according to a statement from US environmental group Sierra Club.

Dan Steinway, partner at US law firm Baker Botts and specialist in environmental and ­experimental law, says every incident he has examined concerning contamination of groundwater by fracking has a plausible ­alternative explanation.

The initial study of fracking began in the mid-1990s with the possible contamination of a well in Alabama. However, the court in 1997 determined there was no connection to the process. In 2008, a Colorado nurse was exposed to the clothing of a drill operator in the emergency room and had medical problems, but that was also shown to have no relation to fracking chemicals, Steinway recalls.

"My overwhelming view is that [regulations on fracturing] are under political influence. You see 60 Minutes, and you see CSI: New York and you read about or see Gasland, and then there's the pressure from the White House," he says, referring to the US TV shows and a documentary movie. "There's political motivation in the EPA [Environmental Protection Agency]."

A 2004 study by the EPA found no evidence of water table contamination. The study said 80% of the chemicals degrade underground or are recovered. The agency recently began a new two-year study of hydraulic fracturing, which is expected to be completed in 2012.

States had already started to regulate fracking as communities worried over water contamination and the boom of drilling in their backyards. But the federal government jumped in.

US Representative Diane Degette (Democrat, Colorado) introduced a bill in 2009 that would regulate fracking with a second attempt to control it under the Safe Drinking Water Act. This became known as the Frac Act.

Under this bill, producers would be required to disclose chemical identities of all constituents of the fracturing fluid, making it available on a website. This would allow emergency crews and first responders to have access to the chemical identities in the case of an emergency.

The oil and gas industry has taken greatest issue with laws requiring the disclosure of chemical identities.

"Everyone likes Coca Cola, but we don't actually know the formula of Coke," Steinway says. "So the industry felt chemical identities were a powerful trade secret and shouldn't be required to be disclosed." With a sigh of relief from the industry, many think the Frac Act is less of a threat now that Republicans control the House of Representatives.

Most state legislation - more than 30 states have varying degrees of shale production - has been based on rules laid down by Colorado after a year of stakeholder discussions.

The Colorado laws include development of a comprehensive drilling plan, ways to minimize the effect on communities and the environment, drilling at a required distance from residences and reporting chemical identities in case of a related environmental or medical need to a state commission. The information would be kept confidential.

New York, Wyoming and Pennsylvania have been active in creating similar regulations, and Pennsylvania passed regulations on fracking in November 2010.

Regulations in Pennsylvania require disclosure of a Material Safety Data Sheet (MSDS) with a list of additives used in drilling. Wyoming also requires MSDS reporting but companies must disclose the main ingredient of chemical additives.

New York tried to place a temporary stop on fracking, so environmental impacts could be studied. In early December, the New York legislative body, the state Assembly, passed a moratorium on fracking until May 2011. However, the governor vetoed the bill.

The industry has taken action to regulate itself as a preemptive move against state and federally imposed regulations.

The Ground Water Protection Council, which includes several oil and gas majors, has developed a voluntary chemical registry for drilling operations. Chemical disclosure requirements vary from state to state, so this would provide uniformity to reporting. The disclosure of chemicals on shale jobs to this database would not be required.

In addition, US-based energy services company Halliburton has been experimenting with ultraviolet light as an alternative to chemicals to kill bacteria down the well.

A study last year by global consultancy IHS Global Insight said experience has shown that increased regulations cause a drop in wells year on year. The new restrictions could cause the US to lose up to 27bn ft3 (764m m3)/day of natural gas production.

The regulations will cause additional red tape and more time to receive permits, and the delays in shale production could tighten gas supply, driving the price higher.

Industry professionals believe the price of natural gas will rise to an average of around $6/MMBtu, according to a 2010 survey by global consultancy Deloitte.

The cost of fracking with horizontal wells, including leases and taxes, requires natural gas to be sold at an average of $7.50/MMBtu.

However, through hedging the price of natural gas, about half of the proven shale gas reserves can be produced at almost $4/MMBtu. The total proven reserves as of the end of 2009 for US shale plays were 60.6 trillion ft3, according to the US Energy Information Administration (EIA).

Furthermore, if construction materials and additional safety requirements are put in place, such as changing the well casing from steel to concrete, this would also add to the cost of shale drilling.

The Independent Petroleum Association of America and industry research estimates that complying with federal oversight would add around $100,000 (€70,067) to the cost of each new natural gas well in the US.

"Significant capital investment in infrastructure is necessary to develop domestic shale resources fully," says Matthew Armstrong and Jason Hutt of US law firm Bracewell & Giuliani's Environmental Strategies Group, based in Washington, D.C. "While regulation may not render domestic shale gas drilling uneconomical right now, attention is warranted to whether additional regulations without actual environmental benefits will raise costs to a point that the balance of shale gas exploration and development moves overseas."

By: Sheena Martin
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