API

Wells operated by a half-dozen E&Ps in eastern Ohio’s Utica Shale are now churning out more than 100 Mb/d of superlight crude oil — aka condensate — more than twice as much as they were just three years ago, and there’s talk that condensate production in the play’s “volatile oil window” could increase significantly over the next few years. This surge in condensate output raises three relevant questions: (1) how is the condensate being transported to market, (2) where is it headed and (3) what is it being used for? In today’s RBN blog, we continue our series on Utica condensate with a look at the approaches used to transport the commodity to refineries and others in the Midwest and points beyond. 

Condensate production in the Utica Shale’s volatile oil window in eastern Ohio has more than doubled over the past three years, and plans by the handful of E&Ps that focus on the super-light crude oil suggest that output will increase further this year and next. Who are these producers, why do they see such promise for condensate growth in the Utica, and how are they measuring their success? In today’s RBN blog, we continue examining rising condensate production in eastern Ohio with a look at the leading E&Ps in this space. 

The Marcellus/Utica is a natural-gas-and-NGLs play, right? Almost entirely, yes. But a handful of dogged, innovative E&Ps have been producing fast-rising volumes of superlight crude — better described as condensate — in the Utica Shale’s “volatile oil window” in eastern Ohio. In today’s RBN blog, we discuss recently ramped-up drilling-and-completion activity in that swath of the Buckeye State, the potential for more growth through the second half of the 2020s, and the impact of increasing output on Midwest midstreamers and refiners. 

In the far western reaches of the Permian Basin lies Orla, TX — a town steeped in history and significance. Orla, which can be fittingly translated into “border” in Spanish, is about 40 miles north of Pecos, near the New Mexico border in Reeves County. Founded in 1890 as a section house for the Pecos Valley Railroad, Orla evolved from a modest stop along the tracks to a bustling oil supply hub — not your typical hub with lots of tank farms close together but still a heavy throughput area — by the 1960s. Though often considered a ghost town today, with a population thought to be in the single digits, Orla remains a vital player in the oil industry. As the origin region for several major takeaway pipelines in the Permian, this once-thriving community continues to serve as a crucial link in the region’s vast network of oil exploration, extraction and transportation, particularly along heavily traveled U.S. Highway 285. In today’s RBN blog, we look at the role that Orla plays in crude oil takeaway from the prolific Permian Basin. 

The Energy Information Administration (EIA) recently raised a few eyebrows across the energy industry with a report that producers in three key shale states — including Texas, the nation’s #1 oil producer — seem to be extracting larger amounts of “heavier” crude oil. Of course, the oil is only heavier relative to the light and superlight grades that have been produced in copious amounts since the dawn of the Shale Revolution. But these denser, lower-API volumes have recently helped drive growth in total crude output. In today’s RBN blog, we unpack what the EIA discussed in its writeup, explore some of the possible drivers behind the apparently heavier oil production, and discuss what it might mean for the domestic market. 

The impending startup of Canada’s government-owned Trans Mountain Expansion Project, better known as TMX, will add exit capacity for Western Canadian crude oil production and is expected to redirect at least some of Alberta’s output toward California and Asia and away from its traditional North American markets, including complex refiners in Eastern Canada and the U.S. Midwest and Gulf Coast. Among them, Gulf Coast refiners, who have become the “price-setting” consumers of heavy Western Canadian crude, are expected to be the hardest hit. In today’s RBN blog, we examine the Gulf of Mexico production and imported grades that might become stand-ins for the “lost” Canadian barrels. 

Much has been written about the run-up in U.S. crude oil exports over the past five-plus years, and rightly so. Who would have guessed a dozen years ago that the U.S. would soon be producing as much as 13 MMb/d, and exporting one-quarter of it? Exports are only half of the story though. In fact, for every barrel of crude shipped or piped out of the U.S. today, two barrels of crude are shipped, piped, or railed in. Put simply, the U.S. refining sector still needs imported oil — or, more accurately, it can’t use all of the light, sweet crude that’s produced in the Permian and other shale/tight-oil plays in the Lower 48, and it still requires large volumes of the heavier crude that’s produced in Canada, Mexico, and overseas. Today, we begin a blog series on U.S. oil imports with a big-picture look at how crude sourcing for the refining sector has morphed in the Shale Era.

To say that Permian crude oil quality varies is an understatement at best. In fact, there’s as much variety in the crude coming out of West Texas as there is in the arsenal of a major league pitching ace. Handling those varied crude qualities is the challenge of midstream operators, who, like batters facing down a Randy Johnson or Pedro Martinez in their prime, need to do the best they can with what they’re given. With the start of spring training only a month away, we begin a series detailing the current mix of Permian crude oil qualities, how pipelines are handling them, and what it means for exports, the end destination for much of today’s incremental Permian oil production. Today, we discuss Permian crude quality variations and the steps new pipelines are taking to deal with it.

Refineries along the U.S. Gulf Coast (USGC), which account for half of the country’s total refining capacity, are generally among the most sophisticated and complex anywhere, with configurations that enable them to break down heavy, sour crude oil into high-value, low-sulfur refined products. However, over the past eight years, the USGC has been flooded with increasing volumes of light, sweet crudes produced in the Eagle Ford, the Permian and other U.S. shale plays as new pipelines were constructed or reversed to the coast for domestic refining or export. Still more pipelines will be coming online over the next year. Today, we evaluate how much domestic crude oil has been absorbed into the USGC refining system, the implications to the overall crude slate qualities, and options for increasing domestic crude oil processing in the near term.

Only a few years ago, pretty much all the natural gas flowing through pipelines in the southeastern U.S. was headed north to serve demand in the Northeast and the Midwest. But that’s all been changing — and fast. Gas production in the Marcellus/Utica has soared and now meets the needs of the Northeast and more. And, as LNG exports from the Gulf Coast ramp up and Southeast gas demand for power generation rises, more and more Marcellus/Utica gas is flowing south, raising the question of whether pipes in the Southeast can handle it all over the long term. Today, we discuss the findings of RBN’s work in preparing a study for the American Petroleum Institute (API) on the adequacy of regional gas pipeline infrastructure.   RBN’s work discussed here is the current analysis being used to inform and develop stakeholder briefings.  We anticipate API will release the final version in report form, after its completion.