Tulsa-based Williams continues to be primed for solid natural gas infrastructure expansions in North America, with the biggest still planned for the Marcellus Shale, CEO Alan Armstrong said Wednesday.
Williams’ long-term exploration and production (E&P) forecast has the Marcellus Shale accounting for about 25% of total output, which in turn would help to expand its massive pipeline infrastructure. The rapid build-up in the play has led to infrastructure delays and a lack of takeaway capacity and that has led to “a lot of strains on infrastructure,” said the CEO.
The recent start-up of the 450 MMcf/d Laser Northeast Gathering Co. project, which runs 30 miles across Susquehanna County, PA, and Broome County, NY, has alleviated some pressure in northeastern Pennsylvania, where Williams had shut-in some production.
“We should have 80 MMcf/d coming on over the next several weeks of the month with the Laser start-up,” said Ralph Hill, who is in charge of the company’s exploration and production (E&P) business. By the end of the year production should be at “normal” levels,” he added.
On the drawing board are supply-driven infrastructure projects in all of Williams’ market areas, including the Marcellus, where its proposed Confluence Pipeline, designed as a 36-inch diameter rich gas gathering trunkline with a series of hydrocarbon dew point processing plants, basically would run vertically along a designated demarcation line that “separates” the rich gas in the western part of Pennsylvania with the dry gas production to the east. Confluence would offer blending and then tie into long-haul transmission lines.
Once Confluence is on track Williams wants to build a centralized cryogenic processing plant in Pennsylvania to strip out ethane, which then could either go into a long-haul pipeline to the Gulf Coast or Canada, or to provide feedstock for cracker facilities (see Shale Daily, Sept. 21). The cryogenic facility could be ready in 2016.
Rory Miller, vice president of the Midstream unit, was asked his reaction to the news on Wednesday that Enterprise Product Partners LP has secured Chesapeake Energy Corp. as an anchor shipper on its proposed ethane pipeline from the Marcellus and Utica shales to the Gulf Coast (see related story). Are two or more projects to carry ethane from the Marcellus necessary?
“Right now I think one is a big first step,” said Miller. “The pipeline to Sarnia [Ontario] that MarkWest is working on is the first tranche that would carry ethane from the area,” he noted. Project Mariner West by MarkWest Liberty Midstream & Resources LLC and Sunoco Logistics Partners LP would deliver up to 65,000 b/d of ethane from MarkWest’s Houston, PA, processing and fractionation complex to Sarnia using new and existing pipelines (see Shale Daily, Sept. 8).
“If one long-haul gets to the Gulf Coast, another tranche is cleared,” Miller explained. Based on independent research, he noted that the Marcellus could be producing “17.5 Bcf/d by 2020. When you start doing the math, you could get two pipeline projects” to the Gulf Coast. “But that’s a long ways down the road. It’s so far out in the future that it’s not much of a concern right now.”
Williams’ ethane strategy in the Marcellus is to “actively use the blending part with the pipeline projects,” said Miller. The proposed Confluence Pipeline would offer blending and then tie into long-haul transmission lines.
Confluence, which is to have 1.1 Bcf/d of capacity, is “Williams’ ethane solution, something that would build a runway to a more complete answer, be it petrochemical crackers in the Northeast or one that Enterprise is proposing,” Miller said. “Getting solutions up there is a good thing. If you unlock the value in ethane, drillers are drilling more. As a gatherer and future processor, that’s good to get drilling going. We see that any solutions up in the Northeast as a positive for the area.”
Williams also will get some relief once Williams Partners LP’s 33-mile, 24-inch diameter Springville gathering pipeline is completed. The pipeline would connect a northeast Pennsylvania gathering system to its Transcontinental Gas Pipeline (Transco) interstate gas pipeline, which traverses the Marcellus. Transco has several expansion projects on the drawing board including the Atlantic Access project, with a forecasted in-service date of 2014.
The new pipelines and other infrastructure should help when Williams spins off its E&P business at the end of this year, said Hill, who was tapped to helm the new unit last month. WPX Energy Inc., which is scheduled to debut by the end of this year, would be a stand-alone publicly traded company.
Williams had been planning to run eight or nine rigs in the Marcellus in 2012, but it lowered that forecast to six or seven. The lower rig count, said Hill, is a “function of a lower gas price and living within our means,” but he added that the company’s new fit-for-purpose rigs were more efficient “than we thought we’d be.”
Marcellus output should be about one-quarter of WPX production “in the next couple of years,” said Hill. “We’re very confident in that.” The company “just started” work in Susquehanna County and continues to develop a leasehold in Westmoreland and Clearfield counties. In 2012 four rigs are scheduled to drill in Susquehanna, with two in Westmoreland County and one or two in Clearfield County.
In the Bakken Shale, Hill said the company had planned oil production to be priced at around a $10 discount to West Texas Intermediate but “we’re seeing it less than that, more like the $5 range. We’re planning $9.80 in [Williams] data book. Through rail, pipelines, trucking, we’re keeping up with production. We have the capacity to keep up with the build-up in volumes.”
Some operators have talked about rising cost pressures in some of the shale plays, including the Bakken. However, those pressures haven’t affected Williams, said Hill.
“We have established relationships with Halliburton for stimulation services and our directional is contracted for whole new fit-for-purpose rigs,” he said. Another advantage for Williams is that the Bakken isn’t its first tight oil and gas play. “We’re taking what we learned in the Piceance [Basin] and moved it up there. As that model kicks in it will drive costs down. There’s a lot of pressure up there no doubt, but our relationships with vendors will keep us in good shape.”
Asked whether Bakken well costs in 2012 may be higher than this year, Hill said Williams was spending $9.5 million per well now and costs likely would be flat in the coming year.
“We’ve heard some talking about well costs of $10-11 million,” he said. “We won’t see that. We think they will be flat at $9.5 million, which is where we are now. We’d like to see them driven down but we’re not sure yet. We already have a couple of new rigs out there,” which could help to reduce drilling and completion expenses.
© 2020 Natural Gas Intelligence. All rights reserved.
ISSN © 2577-9877 | ISSN © 2158-8023 |