匹兹堡——Enkon Energy Advisors 负责人 Amol Wayangankar 表示，将阿巴拉契亚天然气推向市场是该地区未来产量增长的主要挑战之一。

然而，Wayangankar 在 11 月 30 日举行的 Hart Energy DUG 阿巴拉契亚会议上表示，仔细观察阿巴拉契亚中游产能情况会发现生产商现在和未来可以利用的一些机会。

Wayangankar 表示，阿巴拉契亚地区的天然气产量于 2012 年开始发展，产量不足 10 Bcf/d。随着 Marcellus 和 Utica 页岩的进一步开采，到 2021 年，即使国内和国际对 LNG 的需求持续增长，产量仍将达到平均 35 Bcf/d 左右。

“造成这种情况的主要原因不仅是生产者维持生产的纪律，还与缺乏外卖能力有关，”他说。“阿巴拉契亚地区难以产出更多天然气，其他盆地正在占领市场。”

过去 24 个月，阿巴拉契亚天然气产量增长了 0.3 Bcf/d，而海恩斯维尔页岩产量增长了 2.5 Bcf/d，二叠纪盆地天然气产量增长了 5 Bcf/d。

“因此，阿巴拉契亚盆地在与海恩斯维尔和二叠纪盆地竞争时，面临着失去市场份额的重大风险，”韦扬安卡说。“这增加了增加更多管道的重要性。”

Wayangankar 进一步打破了阿巴拉契亚生产的天然气进入市场的位置。有四个管道走廊将产品从马塞勒斯和尤蒂卡盆地运出：美国东北部、美国中西部、墨西哥湾沿岸和加拿大，其中所占比例很小。中西部和东北部地区的抽水量约为 7.7 Bcf/d，墨西哥湾沿岸的抽水量约为 10.8 Bcf/d。

“所以你可以从这里的计划中看到，市场确实是美国墨西哥湾沿岸，”他说。

从阿巴拉契亚到墨西哥湾的管道产能利用率约为 96%，这并没有给生产商很大的余地来扩大已输送的产能。

随着 Mountain Valley 管道的开通，预计明年第一季度将增加 2 Bcf/d 的产能，阿巴拉契亚地区将得到一些缓解。目前正在建设或联邦能源管理委员会审查的其他项目明年可能会增加 1.4 Bcf/d 的产能，预计从 2025 年开始上线的项目将增加 2.1 Bcf/d 的产能。

“幸运的是，这里正在进行一些项目，最终将把来自山谷管道的天然气输送到墨西哥湾沿岸，并最终以液化天然气的形式装在运往全球的船舶上，”瓦扬安卡说，他预测阿巴拉契亚的原天然气产量到 2030 年可能达到 41 Bcf/d。 

他说，与美国其他页岩盆地相比，阿巴拉契亚生产商具有优势，因为一些土地可以生产湿气和干气。

湿气在加工厂中与甲烷分离，需要付费。因此，阿巴拉契亚生产商可以根据液化天然气的市场价格和生产它们的加工费来决定是生产干气还是湿气。

Wayangankar 指出，自 2020 年第三季度以来，液化天然气的价值一直在增加，并且湿气经济性在 2023 年第二季度始终高于干气经济性。

“我们确实预计，随着该盆地增加更多的管道容量，您将看到液化天然气和天然气的显着增加，”他说。

PITTSBURGH — Moving Appalachia gas to markets is one of the major challenges for the region’s future production growth, said Amol Wayangankar, principal of Enkon Energy Advisors.

However, a closer look at the Appalachian midstream capacity picture shows some opportunities that producers can exploit now and in the future, Wayangankar said at the Hart Energy DUG Appalachia Conference on Nov. 30.

Wayangankar said the development of gas production for the Appalachia region started in 2012 at less than 10 Bcf/d. With further exploitation of the Marcellus and Utica shales, by 2021 production averaged about 35 Bcf/d, even as domestic and international demand for LNG has continued to rise.

“A primary reason for that is not just producer discipline to maintain production, but it also has to do with lack of takeaway capacity,” he said. “As Appalachia struggles to put more gas out, other basins are capturing the market.”

Over the past 24 months, Appalachia gas production grew 0.3 Bcf/d, while production in the Haynesville Shale grew 2.5 Bcf/d and 5 Bcf/d in the Permian Basin.

“So there's a significant risk for the Appalachian Basin in terms of losing the market share as they compete with the Haynesville and the Permian basins,” Wayangankar said. “It increases the importance of adding more pipelines.”

Wayangankar further broke down where gas produced in Appalachia goes to market. There are four pipeline corridors moving product out of the Marcellus and Utica basins: the Northeast U.S., the Midwest U.S., the Gulf Coast and Canada, which takes a small percentage. The Midwest and the Northeast both pull about 7.7 Bcf/d and the Gulf Coast takes about 10.8 Bcf/d.

“So you can see from the plan here, the market really is the U.S. Gulf coast,” he said.

Pipeline capacity from Appalachia to the Gulf has been at about 96% utilization, which doesn’t give producers much leeway to expand the capacity of volumes already being sent.

Some relief is coming for Appalachia with the expected opening of the Mountain Valley Pipeline adding 2 Bcf/d capacity in the first quarter of next year. Other projects currently under construction or Federal Energy Regulatory Commission review could bring an additional 1.4 Bcf/d capacity next year, with an additional 2.1 Bcf/d capacity in projects expected to come online starting in 2025.

“Luckily, there are some projects underway here that will eventually take the gas coming from the Mountain Valley Pipeline towards the Gulf Coast, and eventually ending up on ships going globally as LNG,” said Wayangankar, who forecasted that Appalachia raw gas production could hit 41 Bcf/d by 2030. 

Appalachia producers have an advantage over other shale basins in the U.S., in that some acreage holdings produce wet and dry gas, he said.

Wet gases are separated from methane at a processing plant for a fee. Appalachia producers can therefore decide whether to produce dry gas or wet gas, depending on the market price for the NGL and the processing fee to produce them.

Wayangankar noted that since third-quarter 2020, the value of NGLs have been accretive, and the wet gas economics remained above dry gas economics for all second-quarter 2023.

“We do expect, as the basin adds more pipeline capacity, you'll see a significant increase in NGLs along with natural gas,” he said.