The day-in and day-out reports from operators ready to build new natural gas pipelines and natural gas liquids (NGL) midstream infrastructure generally have had one thing in common over the past couple of years: most are for the Marcellus Shale. And that’s not going to change anytime soon, according to industry executives.
Many of the biggest pipeline systems now carry gas to U.S. East Coast markets. That has to change, according to Rusty Braziel of RBN Energy LLC. He spoke Tuesday at the 92nd Annual Gas Processors Association Convention in San Antonio.
Marcellus gas supplies have grown from about 2 Bcf/d in 2005 and are tracking to hit 18 Bcf/d in 2017, he said. The increase in supplies from the Marcellus, and potentially from the Utica, will turn off gas imports from Canada and lead to more streams being reversed in the Lower 48 states.
“A lot of replumbing is going to be required” for pipelines and storage, Braziel told the packed audience. He elicited some laughter with a “suggestion” that some of the west-to-east pipes eventually could be turned into water slides.
Domestic gas production is at an all-time high, with 16.2 Bcf/d of incremental growth in the Lower 48 states in a little more than two years, he noted. However, the Marcellus Shale’s output today eclipses any other producing U.S. basin and will change the maps for gas infrastructure.
Why? Up to now, the Northeast needed gas supplies. The big pipes run east. Trying to reverse what has been in place for years is going to take more years.
The inventory of drilled but nonproducing wells in northern Pennsylvania, which stood at just under 1,200 wells last May, “will take five years to clear,” Braziel told the audience. There’s just not enough infrastructure to process the gas or carry it to other markets.
In January 2011, total gas production in the Marcellus was about 4 Bcf/d, he explained. Today it’s more than 10 Bcf/d and rising. Producers are obtaining high rates of return in the wet gas window from NGLs, but they also have an inventory backlog of wells in the dry gas window — so output could be much stronger today if infrastructure could accommodate it.
RBN research found that the Pennsylvania gas well backlog began in 2009, and last May Pennsylvania’s Bradford County had close to 400 wells awaiting completion. Big backlogs also are in Lycoming, Tioga, Susquehanna and Clearfield counties.
Even with the slowdown in the gas patch, overall domestic dry gas production is forecast to grow another 9 Bcf/d, or about 1.8 Bcf/d every year from 2012 to 2018, according to research compiled by RBN and Bentek Energy. By comparison, U.S. dry gas output between 2005 and 2012 grew about 2.3 Bcf/d every year, Braziel noted.
Areas also expected to show the biggest jump in output to 2018 are Texas, to about 22 Bcf/d from 18 Bcf/d; the Midcontinent market, to 1.1 Bcf/d-plus from 0.6 Bcf/d; and Midcontinent producing, to nearly 8 Bcf/d from just under 6 Bcf/d.
The Southwest and Rockies producing areas should see output remain basically flat over the period, while in the Southeast and offshore, gas output is forecast to decline.
So what happens to the current pipeline trajectory? A lot of repurposing of gas pipelines and once proposed gas pipeline projects is underway to carry growing crude and NGL supplies, including the:
Crude pipelines also are considering reconfigurations; Enbridge Inc. and Enterprise Products Partners LP plan to double the capacity of the Seaway Pipeline to 850,000 b/d by mid-2014 to allow new flow paths to market.
RBN’s intra-regional flow analysis shows a stunning reversal of gas supplies from Eastern Canada to the Northeast, moving from a high of close to 3 Bcf/d in 2011 to almost nothing by the middle of 2014.
Midcontinent market gas to northeastern demand centers also slides into reverse, from more than 2 Bcf/d in 2010 to a deficit by 2015. Southeast supplies are forecast to fall steadily through 2017, as well as Western Canada gas carried to the Midcontinent market. Also falling is Rockies gas to the Midcontinent production and market areas.
Rockies gas supplies to the Pacific Northwest will be relatively flat to 2017 from 2012 figures. However, Texas gas to the Southwest is predicted to increase over the period, with exports to Mexico steadily rising.
NGL processors have a lot of business coming their way, but there has to be infrastructure in place before the money can be made. U.S. NGL output could jump by 1.3 million b/d from 2012 to 2018, according to Braziel. There’s no region of the country where NGL output is forecast to decline over the next four years.
The capacity for NGL fractionation is growing, but there’s still a gap between processing capacity and the ability to export the liquids.
“It seems like a new fractionator is announced about every two weeks,” Braziel said, citing a recent decision by Phillips 66 to build a plant in Old Ocean, TX, to process up to 100,000 b/d (see Shale Daily, April 4). But it’s not yet enough.
Peter Fasullo of EnVantage, who shared the panel discussion, said “midstream companies are exercising greater leverage in contracts with producers…At the same time, midstream companies are trying hard to get their facilities contractually full.”
Fractionation facilities had the capacity to extract 2.6 million b/d in 2012, up from 1.7 million b/d in 2005, Fasullo noted. By 2015, about 1.3-1.7 million b/d more of NGL capacity is expected to be online. However, he agreed with Braziel: ethane rejection may continue for years.
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