The old proverb of “be careful what you wish for because it might come true” made famous in a play by W.W. Jacobs’ “The Tale of the Monkeys Paw,” looms over the heads of condensate-rich U.S. refiners planning investments beyond 2015. There’s now so much shale-related feedstock on the U.S. refining market, including condensate, a super-light oil (API > 58) from shale wet gas, that refiners seemingly don’t know what to do with it.
For the past 20 years, refiners have invested billions of dollars in refinery processing complexity (e.g., delayed cokers, FCC pretreaters, etc.) for processing heavy asphaltenic crudes from Canada, Venezuela and other overseas heavy crude sources. With their high complexity refining configurations, they got so good at processing heavy crudes, that they cannot efficiently process high volumes of sweet, paraffinic shale hydrocarbons, like condensate, less they encounter problems with unit heat balances, insufficient VGO feed to the FCC, etc.
To deal with these complications, the onus is on processing a blend of heavy crudes and limited quantities of condensate and other shale feedstocks, but this still doesn’t answer the problem of dealing with surplus condensate. Some options include re-purposing condensate production, particularly from the Bakken Shale play in North Dakota as a diluent in the pipeline shipment of very heavy Canadian bitumen-based crude in (the form of diluted bitumen [dilbit]) down to the U.S. refining market. Another viable option would be to export condensate, particularly condensate from the Eagle Ford Shale in South Texas. For example, in early August, a tanker with 400,000 barrel of Eagle Ford condensate set sail from the port of Corpus Christi, Texas to the SK refinery near Seoul, South Korea. This world-scale refiner processes an opportunistic blend of heavy crudes and vacuum resid that can be more easily processed by blending with condensate.
Increasing volumes of condensate will therefore be blended as dilbit once the Keystone Pipeline is completed (if it ever is). But it is the export of condensate that is the big game changer for exploration and production companies. They are all excited about the opportunity to export condensate. It’s a different story for refiners. Some refiners see condensate exports as an opportunity to rid their operations of very light crude production that interferes with refinery operations. Other refiners and their midstream partners have invested in condensate splitters to better separate the condensate from natural gas. A condensate splitter is basically a low-end refinery that typically costs about $350 million, including tank storage, etc. for producing about 50,000 bpd of condensate. But the $350 million cost is a bargain considering the multi-billion cost to build a high complexity refinery with hydrotreaters, FCC units, cokers, etc.
High complexity refiners like Valero, say they can send Eagle Ford condensate from the Corpus Christi, Texas Terminal to its 265,000 bpd Quebec refinery, where the condensate can be blending with heavy Canadian crudes. This strategy is partly influenced by the fact that the Valero Three Rivers, Texas refinery, in the heart of the Eagle Ford shale play, is already at maximum capacity.
Other refiners, like Marathon, have invested heavily in a pair of condensate splitters to process 60,000 bpd of condensate into feedstock for its refineries in Cattlesburg, Kentucky and Canton, Ohio. Both condensate splitters will run condensate from midcontinent Utica shale plays, which are isolated form export markets.
The U.S. Department of Commerce approved exports of a limited quantity of shale condensate, by reclassifying it as a refined product instead of a crude (by way of some simple in-the-field upgrading through a stabilizer). Unfortunately, refiners took this as a de facto government approval for industry wide export of condensate that would erode U.S. refiners’ global advantage, particularly the independent refiners, and undermine Greenfield condensate splitter investments.