US crude oil production has reversed a long term decline that started in 1970. The direct cause of recent increases has been rapidly growing tight oil supply, especially from the Bakken, Eagle Ford, and Permian Basins.
Since the late 1940s US law has prohibited significant exports of domestically produced crude oil. However, domestic production increases should encourage a review of the current prohibition on crude exports. The crude being produced today is more highly valued outside the US than inside it. From a policy perspective, why should domestic crude oil producers not be allowed to seek the highest value for their production by marketing it internationally?
If crude exports were permitted, the US would likely export the bulk of the new found light, tight oil and condensate. For the last 30 years or more, US refiners have been investing to process heavy, sour crude and the new production is a poor match for their refining configurations. Therefore, refiners could instead import heavy crude while producers could export light crude. Refiners avoid substantial capital investments while producers receive more economic rent.
If crude exports continue to be restricted, tight oil will be discounted far below international grades of similar quality only because they are ‘trapped’ by a decades old policy. This is essentially a wealth transfer from the producers to the refiners. In KBC’s opinion, the cost of production is sufficiently low that tight oil production will not end, but it may slow if producers’ economic return continues to be lowered. Therefore, price discounts from domestic US crude will continue until either refiners invest in new processing capability or exports are permitted.
International refined product trade flows have also been impacted by the supply flood of US tight oil. Growing domestic hydrocarbon supply, and thus low feedstock costs, has made US refiners globally competitive. While domestic US gasoline demand is declining, refiners are increasingly turning to product exports, especially to Latin America but now also to Africa and even Europe. The US has not only drastically reduced previous gasoline imports but has become a net exporter of gasoline.
Shale oil processing investments
One option for producers to avoid crude export restrictions is to process their material in a condensate splitter. Essentially, a very simple distillation column, a splitter divides condensate into its LPG, naphtha, diesel and fuel oil components. These crude components, or ‘intermediates’ require further refining, blending and/or treating, before they can be turned into finished products. However, merely by virtue of having been processed in a splitter, these components can be legally exported where the ‘whole’ crude, or condensate, could not.
Kinder Morgan is currently building two condensate splitters in the Houston area. The first 50 000 bpd splitter will startup in 2014. A second will follow in 2015. BP contracted virtually immediately for all of the capacity at both units.
This approach will work for some Eagle Ford producers, but most of the light, tight oil will still have to be processed in existing refineries. Tight oil quality is different than benchmark WTI and imported West African crudes that have filled US refineries for the last century. The differences in crude quality are significant enough that without modification, refinery capacity will be reduced.
Tight oils are sweet light crudes that have excellent yields. The current crude cost is low and the benefits are high. Overall, the refiner has significant drivers to process these crudes. The following are some of the issues surrounding tight oil crude quality that prevents the refiner from realising the full benefit. Shale oil is not dramatically different from the waxy crudes that have been processed in Asia Pacific for many years. These include Gippsland and Cossack from Australia, Bach Ho from Vietnam and Kutubu from Papua New Guinea. North American refiners can learn from the past refining challenges that have been overcome.
The US refining industry needs capital investment but the technology risk is low to process growing light tight oil supplies, the technology is already well understood. The challenge is simply finding the most cost efficient means of getting from point A to point B, converting existing equipment to the newly required configurations.
Several capital investments are likely required to allow existing refineries to process significant quantities of shale oil. Crudes from different sources are often mixed together to satisfy the refinery configuration and to maximise capacity. Mixing different crudes can have the consequence of being incompatible. Light and waxy crude may not be compatible with a refinery’s existing crude slate. Blending incompatible crudes results in precipitation of asphaltenes, which can foul heaters, pipes, desalters, and crude towers.
To manage crude compatibility issues, many refiners are investing in additional crude tankage and blending equipment. The waxy crudes may also required steam tracing and insulation to manage low pour point qualities. Another common issue is that light tight oil contains a significantly larger light fraction than incumbent crude slates. As a result, the crude heater often has insufficient capacity to lift the light fraction to the top of the crude tower. Conversely, the crude contains relatively little heavy fraction and the vacuum column heater is over sized. Heater reconfiguration may be required.
Additional investment in a preflash tower between the desalter and the crude tower may also be justified. Taking the light naphtha and lighter material to the saturated gas plant is another approach to unloading the top of the crude tower.
The paraffinic nature of shale oil can make it difficult to meet the cold flow property specifications (cloud point and cold filter plugging point) of distillate products. A typical operational response is adjusting tower cut points to drop the heavy tail of distillate products into the vacuum gas oil. Minor piping investments may be required to accommodate this operational adjustment. Further dewaxing of distillates requires special catalyst to selectively crack some of the paraffinic material away as off gas and to isomerises a portion of the waxy, normal paraffin stream into isoparaffin molecules. The result is a 10 °F to 15 °F increase in both cold flow properties.
Slick water hydraulic fracturing requires the addition of numerous chemicals, which are emulsification agents. Adjustments to desalter and waste water treatment plant operation are likely appropriate.
These are not all of the issues, but provide understanding as to the challenges faced.
Since the shale gas boom has taken hold over the last few years, natural gas has been priced at a historically low ratio relative to crude oil on an energy content basis. Natural gas is currently about US$ 4 /million Btu. To be equivalent to US$ 100 /bbl crude oil, natural gas would need to trade at US$ 17 /million Btu. NGLs trade at prices between natural gas and crude, which is why producers are focusing on the liquid rich, or ‘wet’ plays.
The qualities of shale gas are no different than conventional gas or associated gas that is coproduced with oil. Therefore, no special processing techniques are required for shale gas. Industry’s challenge is adding enough gas plant capacity to handle the growing production. Gas plant construction has been especially rapid in the Marcellus and Bakken areas.
The turnaround in US hydrocarbon production has been nothing short of spectacular. However, this success brings with it new challenges. Refiners and petrochemical producers are challenged like never before to respond to changing feedstock qualities, and prices. Producers need fair economic returns to continue finding and producing energy. Policy makers have been slow to realise they too need to make changes; export policies and less restrictive trade policies are to the benefit of energy producers and consumers alike.
Written by Matthew Kuhl, Mark Routt and Scott Sayles, KBC Advanced Technologies, USA. The full article can be found in the January issue of Hydrocarbon Engineering.
Adapted for the web by Emma McAleavey.
Read the article online at: https://www.hydrocarbonengineering.com/special-reports/13012014/flood_warning_40/