By Myra Pinkham, Contributing Editor

For Shale Sign’s Out for OCTG

Despite the recent controversy over the environmental risks of “fracking” in the nation’s abundant shale plays, the future looks bright for suppliers of oil country tubular goods.

The energy sector continues to be one of the strongest in the U.S. economy, in large part due to the technical breakthroughs that have made drilling for oil and natural gas in the nation’s shale plays economical. While such drilling methods as hydraulic fracturing or “fracking” have been challenged by some environmentalists, the need for domestic sources of cheap energy is likely to take precedence—fueling demand for oil country tubular goods for years to come, say the experts.

“The shale plays have been the savior of the energy pipe and tube industry,” says Kurt Minnich, partner with Tulsa, Okla.-based Spear & Associates Inc., the publisher of Pipe Logix. “If it weren’t for the shale plays, the industry would be on its knees.”

Consumption of energy tubulars—both OCTG and line pipe—tends to track with the drill rig count, which is clearly trending upward. According to Houston-based oilfield services company Baker Hughes Inc., a total of 1,974 drill rigs were operating in the United States as of Aug. 19, a 19 percent increase from a year ago and more than double the number operating in the depth of the recession.

Of the rigs currently drilling in the United States, 97 percent or 1,921 are on dry land and 40 to 45 percent of them are extracting oil and natural gas from the nation’s shale deposits, says Vicki Avril, president and chief executive officer of TMK-IPSCO, Downers Grove, Ill.   

Not only has the U.S. rig count increased in the past two and a half years, largely on the back of increased shale drilling, but consumption of pipe per rig has also increased, Avril notes. “This is largely because of the new techniques that energy companies are using, including fracking, and the use of longer strings or multiple strings of pipe with horizontal and directional drilling.” [Fracking is a process in which fluids are pumped deep underground at high pressures to fracture the shale and release the oil and gas within it.] Thus demand for pipe, especially premium pipe and premium pipe connections, remains strong despite the uncertain economic conditions, she adds.

The number of rigs drilling horizontal wells—currently 1,138 or 57.6 percent of all the operating rigs in the United States—continues to rise at a steady clip, up 27 percent year on year. This is good news for OCTG suppliers, says Rick Preckel, partner with the Preston Pipe Report, Ballwin, Mo. The longer laterals used in horizontal and directional drilling require 10,000 feet or more of OCTG, compared with 2,000 feet or less in a traditional vertical well, he notes.

“On average, a directional rig may consume as much as 4,200 tons of OCTG per year, while the average for all types of drilling is closer to 3,000 tons per year,” Avril says.

Different types of pipe are used for different parts of the well. Seamless pipe, sometimes made of alloy or stainless, is often specified for the more demanding applications deep in the well, while commodity steel pipe is used closer to the surface.

“Shale drilling has had, and will continue to have, a significant impact on the OCTG and line pipe business,” Avril says. “New drilling techniques have changed the business model, lowering the cost of drilling for fuel in the shale reserves. Not only has shale drilling taken off in the United States, but it is likely to do so internationally as well, including in such countries as Poland, France and Germany.”

Christopher Plummer, managing director of Metal Strategies Inc., West Chester, Pa., estimates the shale plays in the Northeast account for 63 percent of the nation’s natural gas reserves. Of that, the Marcellus shale play in Pennsylvania, New York and Ohio accounts for 55 percent. Meanwhile, the shale plays in the Southeast, South Central and Southwest—including the Haynesville, Barnett and Woodford shale plays in Texas and Oklahoma—account for another 31 percent of U.S. shale natural gas reserves.

U.S. dry shale gas production increased from 1 percent of total natural gas production in 2000 and 6 percent in 2007 to 17 percent last year, Plummer says. Shale natural gas will account for an estimated 35 percent of all U.S. natural gas production by 2020.

Oil’s well that ends well

Oil drilling is also playing a bigger role in the nation’s domestic energy strategy, both in traditional oilfields and shale plays, says Gregg Eisenberg, president and chief executive officer of Boomerang Tube LLC, Chesterfield, Mo.

While drilling in the United States has traditionally been about two-thirds natural gas, “today the ratio has dramatically shifted, with oil drilling accounting for 54 percent and gas 46 percent” Avril says. Drilling is a function of price, she explains. Gas has declined to around $4 per MMBtu, which is a relatively low level, while oil remains relative high at about $85 a barrel.

Oil drilling in the United States was healthy until late 1998 when the price fell through the floor, says Preckel at Preston Pipe Report. “What the shale plays have done for oil is make it economical to drill for it in the United States again.”

Sixty-four percent of the nation’s oil reserves are in the Monterrey-Santos shale formation in Southern California, Plummer notes, although there has been limited exploration there to date. The Bakken play in North Dakota, Montana and southern Canada is the next largest at 15 percent of total U.S. shale oil reserves. Bakken, with its combined shale and conventional oil deposits of 3.5 billion to 4.3 billion barrels, is the largest oil find in U.S. history outside of Alaska.

Philip Budzik, operations research analyst for the Office of Petroleum, Natural Gas and Biofuels Analysis of the U.S. Energy Information Administration, says Bakken has helped North Dakota become the third largest oil-producing state in the country, producing about 385,000 barrels per day from its 176 operating rigs. Just 10 years ago, North Dakota was one of the lowest-producing states.

Other oil shale plays include the Niobrara in Colorado and Wyoming, the Eagle Ford in Texas and the Utica under the Marcellus in Ohio, New York, Pennsylvania, Kentucky, Maryland, Tennessee, West Virginia, Virginia and Ontario, Canada. Among those looking to drill in the Utica, which is yet to have producing wells, is Chesapeake Energy, which recently confirmed that it has made a major new liquids-rich discovery in the eastern Ohio region.  

These shale plays not only contain oil, but also natural gas liquids, which are more desirable in the current economic environment than dry natural gas. “If the well contains liquids [oil or natural gas liquids], the driller will get a higher value,” Minnich says. Natural gas liquid can be sold as an oil product, which adds a dollar or two to its selling price.

A question of cost vs. price

The big question for energy suppliers today is whether it is cost effective to drill for natural gas at current pricing levels [$4.02 per MMBtu as of early August]. “Natural gas has been a victim of its own success with prices going down along with drilling in the shales,” Minnich says.

Even though drilling for natural gas has declined to 45.6 percent of the total, compared with 59.7 percent a year ago and about 80 percent just prior to the recession, current pricing levels continue to spur some natural gas exploration, Preckel says. In some cases, that drilling is done by companies whose leases stand to revert back to the landowner if there is no development within the first three years—which adds further pressure on natural gas prices. “People are drilling for and producing natural gas even if the business environment
doesn’t support the increased production,” Preckel adds.

Also prompting exploration where there was none in the past is the efficiency of the new drilling techniques. “The breakeven point for natural gas drilling has gone down,” Avril says. “One analyst’s report estimates that drilling in a number of the major shales, including the Marcellus, Haynesville, Eagle Ford, Fayetteville and Woodford, can produce a 10 percent return at natural gas prices below $4.50 per MMBtu. Some in the industry have even quoted numbers as low as $2.30 as being the breakeven point.”

For years, the industry knew about the Marcellus shale, but did not know the extent of its natural gas resources because it had not been economical to explore it, she adds.

New drilling techniques, particularly fracking, have changed the economics of oil and gas exploration. But fracking has drawn the scrutiny of environmentalists and regulators, who question whether the cocktail of chemicals used in this process could pollute the groundwater. Eisenberg calls this “an unfounded fear,” maintaining that “there has been precious little evidence of that ever happening or that it has a high risk of occurring.”

Minnich maintains that much of the concern about fracking comes from a lack of education and communication. “The drillers aren’t communicating with the communities about what they are doing because they believe to reveal the secrets behind their process would open the door to competition. However, because of this, they look like they are hiding something.”

Environmental concerns have had a dampening effect on drilling in the shale plays, but it has varied region by region, Avril says. “For example, in Texas, where fracking techniques have been used for many years, there are over 850 rigs operating. In Pennsylvania, even though the development of the Marcellus shale has been more recent, the state has been very proactive in defining and setting up drilling standards, and therefore there are over 100 rigs operating there. In contrast, in New York, which is also in the Marcellus shale, there is currently a moratorium on drilling due to environmental concerns.” [Editor’s note: At press time, New Jersey also placed a one-year ban on the practice to allow time for further study.]

Even if the drilling moratorium is lifted in New York, as expected, it will have very little effect, she adds, especially if regulators add red tape to the process. “Drillers still won’t drill there. New York won’t be drilling-friendly.”

Proposed recommendations by the New York Department of Environmental Conservation for lifting the moratorium contain a number of restrictions, including that drilling continue to be banned in the watersheds that serve New York City and Syracuse, as well as within primary aquifers, and that surface drilling be prohibited on state-owned land, including parks, forest areas and wildlife management areas.

The U.S. Environmental Protection Agency is also studying the fracking controversy. “I can’t say what the EPA will ultimately do,” EIA’s Budzik observes, but it could come down to an issue of state vs. federal oversight. The U.S. EPA could leave regulation of drilling, or certain aspects of drilling, to the individual states, he says.

In August, a key U.S. Department of Energy advisory panel, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board, issued a report indicating that fracking could continue safely as long as companies disclose more about their drilling practices, both to the public and to regulators, and if they are required to do more monitoring of their environmental impact.

If new regulations are imposed on shale drilling, it may not affect how much drilling occurs, but rather where it occurs. “Drillers will move to states that have been supportive of drilling and away from those that have not,” Avril predicts. “Restrictions that are put in place and do not have environmental benefits will only add costs and time to drilling. This will incentivize drillers to move to other locations where it is more economical and easier to operate. Regulation that actually protects the environment will have a positive impact. As all drillers follow the same rules and the local population finds comfort in the drilling practices, they will welcome development in their region and be able to share in the employment and economic growth that result.”

Prospects for pipe and tube suppliers remain positive. “I think the strong activity in the shale plays should continue for a long time and that it will have a big impact on the steel industry, both because of increased flat-rolled steel demand and demand for seamless and welded pipe,” Plummer says.

Several new tubular mills, including producers of line pipe as well as OCTG, are positioning themselves to take advantage of this shale trend. Among them are:

n Northwest Pipe Co., which is beginning production at its Bossier City, La., welded OCTG and line pipe facility;

n Tenaris SA, which continues to ramp up its new seamless energy tubulars mill in Veracruz, Mexico;

n Vallourec SA, whose new seamless mill in Youngstown, Ohio, is expected to be hot commissioned in December;

n Evraz Inc. North America, which is in the midst of a multimillion dollar investment in energy tubulars at its Portland, Ore., pipe mill;

n TPCO America Corp., which plans to build a seamless pipe mill in Gregory, Texas;

n Bri-Chem Corp., which is about to start producing seamless OCTG and line pipe at its new mill in Edmonton, Alberta; and

n Wheatland Tube Co., which is upgrading its Warren, Ohio, facility.

Large-diameter line pipe isn’t getting as large a boost from the shale activity, as most drilling is occurring in areas that have been in development for some time and the infrastructure to transport the oil and gas is already in place. “There was an amazing amount of pipeline activity through 2008,” Minnich says, but new interstate pipeline activity has begun to decline.

Much of the current demand is for smaller-diameter line pipe, diameters of 12 inches or less, used to upgrade the gathering and distribution systems that connect the wells to existing large-diameter pipelines, Preckel notes.

Eisenberg at Boomerang Tube estimates that overall OCTG consumption this year could be up 20 percent from 2010 and that it could increase another 10 percent next year. n
Source: U.S. Energy Information Administration, INTEK Inc.
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Monday, February 19, 2018