plant condensate

Several oil-sands expansion projects committed to when crude oil prices were double what they are today are finally coming online, and midstream companies active in Alberta are building new crude/diluent pipelines and storage capacity to keep pace. New storage caverns for natural gas liquids are also in the works, giving a much-needed boost to Canada’s Energy Province. Today we conclude our series on midstream infrastructure under development in or near Western Canada’s oil sands region that move and store hydrocarbon liquids.

Oil-sands expansion projects coming online and the resulting need for more diluent are among the drivers behind a number of midstream infrastructure projects in the province of Alberta, including natural gas processing plants and fractionators; oil and diluent pipelines; and oil/NGL storage facilities. The total volume of work is surprising, considering the fact that oil-sands production economics are iffy right now, if not downright upside down. Today, we continue our look at midstream projects under development within Canada’s Energy Province, this time focusing on gas processing and fractionation facilities.

More midstream projects than you might expect are “goin’ on” in the Western Canadian province of Alberta, considering the challenges that bitumen/crude oil and natural gas producers there continue to face. There are several drivers behind the relatively long list of oil and diluent pipelines; gas processing plants and fractionators; and oil/NGL storage facilities being built in Canada’s Energy Province, but much of the work is being done to meet the expected needs of oil-sands expansion projects approved during better times and set to come online soon. Today we begin a blog series on Alberta midstream projects with an overview of where the province’s energy sector stands today.

Production of lease condensate at the wellhead and plant condensate from processing natural gas liquids (NGLs) has increased rapidly in the Ohio Utica over the past two years. Timely investment by local refiner Marathon and infrastructure developments to ship condensate to Gulf Coast refiners have proved the primary market for Utica condensate so far. The proximity of the region to diluent pipelines to Canada has also prompted infrastructure projects. Today we describe projects to deliver condensate to Alberta.

According to the Energy Information Administration (EIA), liquids production from the Utica shale in Ohio (identified as crude oil but more likely all lease condensate) has more than trebled since January 2014 from 19 Mb/d to a projected 64 Mb/d in May 2015. Regional production of plant condensate from natural gas processing has also increased with the build out of gas processing capacity in the Utica and nearby Marcellus plays and could reach 50 Mb/d by the end of 2015. Midstream companies have been busy developing infrastructure to get this condensate to market. Today we look at developing infrastructure and markets for Utica condensate.

The U.S. has a surplus of light hydrocarbon liquids – much of it in the form of field condensate produced at the wellhead and plant condensate extracted from natural gas at processing plants. Declining domestic demand leaves both field and plant condensate increasingly reliant on export markets. Trouble is those export markets are far from secure and the oil price crash isn’t making things any easier. Today we preview RBN’s latest Drill Down report – a deep dive into the supply and demand balance for field and plant condensate.

Recent rumors coming out of Washington DC suggest that changes to US regulations that severely limit exports of US crudes are being discussed with a view to changes – perhaps even repeal. One idea that keeps popping up is a change to allow the export of lighter hydrocarbons that have a high API Gravity (above 55 or some other number), classified by the US rules as crude, but known to the rest of the world as condensate. Allowing the export of such field condensates could alleviate an oversupply glut of these lighter hydrocarbons that US refineries are not best configured to process. Today we ponder the impact of an end to the prohibition of condensate exports.

Growing Canadian production of oil sands bitumen requires diluent to blend it to pipeline flow specifications. The resulting demand for diluent exceeds local Canadian supply from plant condensate production (aka, natural gasoline) – leading to imports from the US of more than 150 Mb/d in 2013 – a figure expected to grow to 460 Mb/d by 2018. That expectation for future import growth is based on the assumption that Canadian condensate supplies would remain relatively flat at about 140 Mb/d. But could the developing Duvernay gas shale play in Western Alberta turn those estimates on their head? Today we investigate the consequences for US condensate demand.

Supplies from the three main branches of the US condensate family are increasing faster than demand can keep up. Field condensate production from shale basins is nearing 1 MMb/d - headed to 1.6 MMb/d by 2018. Plant condensate – aka natural gasoline - will increase from just over 0.3 MMb/d in 2013 to more than 0.5 MMb/d in 2018. Because field condensates cannot be exported to overseas markets, more of this material will be refined traditionally or using a splitter – pushing out existing refinery demand for natural gasoline and creating an excess of naphtha range material. Petrochemical demand for natural gasoline has dried up in the face of cheap ethane feedstocks. Canadian demand for natural gasoline as diluent will soak up some but not the entire natural gasoline surplus. With US gasoline demand declining, the only outlet for excess naphtha and natural gasoline will be more exports (beyond Canada). Today we look at changing condensate demand patterns.

When Forrest Gump famously said, “Life is Like a Box of Chocolates – you never know what you are going to get”, he might as well have been talking about condensates. The shale revolution has doubled US condensate production since 2011 and we expect those numbers to continue to increase. And like chocolates, condensates come in many varieties. Not just field condensate production from oil and gas wells in basins like the Eagle Ford, but its cousins natural gasoline from natural gas liquids (NGL) processing plants and light naphtha from petroleum refineries. These growing volumes of light hydrocarbons are joined at the hip by their “C5” chemistry and finding a home for them all is proving disruptive to traditional supply/demand patterns.