Reports of dropping crude oil prices negatively impacting the level of investment or amount of oil produced from the Williston Basin are being floated around this week. The general sentiment is that as Brent crude continues to drop into the $80/barrel range (with the possibility of dropping into the $70/barrel range or lower) exploration and production firms heavily invested into the Bakken will have to cut back investments or plans for 2015 because the payback on new wells won’t happen at a quick enough rate or large enough amount because of teh smaller monetary amount they recieve for Bakken crude. Also worth noting is that Bakken crude, most closely tied to West Texas Intermediate, typically trades below the Brent crude price, sometimes with a very wide spread. North Dakota sweet crude sold to the Flint Hills refinery was below $70/barrel this week.
Although it is fact that crude prices have dropped quite noticeably since June 2014, and they may continue to drop, the question of whether production, investment or development into the Williston Basin will slow based on falling crude prices is only answerable through an incredibly complex set of circumstances.
First, consider the recent oil and gas impact study from KLJ Engineering. The study indicates that certain factors greatly impact an exploration and production company’s decision to drill and frack a well. The list of factors includes expected initial production rates for a given well, well completion costs associated with drilling and fracking the well and the price for which Bakken crude can be sold for.
IP rates can depend on a number of factors, including the drilling and completion company’s ability to execute a pre-determined drilling and fracking plan; well location; the intial flow rate that the well head is opened too; and the formation to which the well will be focused on.
Well completion costs vary from operator to operator. In some cases, an operator may report well costs as low as $6 million or as high as $14 million. Proppants and water make up the majority of the cost to frack a Bakken well in many cases. Fracking methodology commonly deployed five years ago has vastly evolved, most notably through the amount of water, sand and number of discrete fracture stages placed into the horizontal lateral. Operating costs, the costs associated with maintaining wells, powering well site, disposing of water and other materials, are not calculated into well costs.
There are too many factors to consider when explaining the current price for oil. But, here are a few that are impacting the price of oil that have been well documented. U.S.-based shale oil production is at an all-time high and will continue to be at the pace for a long time. Global demand for oil in the near-term future is lowering. Middle Eastern oil producers are not cutting production in an effort to keep oil prices around the $100/barrel mark. In short, the global supply of oil is quite possibly outpacing demand, and, the U.S. does not currently have access to outside markets other than Canada to sell U.S.-based crude into.
All three of the aforementioned factors will play a role into the development of the Williston Basin in a complex way.
So, to the question, How will dropping crude prices impact the Bakken, consider this.
First, start with IP rates. According to the KLJ study, a $7.5 million well with a 500 IP rate in a world with $70/barrel oil will never recover the costs for completing the well. But, if the IP rate is in the 1,000 bopd range, the picture for the E&P firms is much different:
“In stark contrast, modeling sensitivity scenarios such as large drops in prices down to $35 per barrel with high IP wells, which are common in parts of the Bakken/Three Forks, still have positive economic returns. Based on modeling outputs, IPs of 500 bpd or less will not be attractive to companies if well costs equal $7.5 million, and oil prices are in the vicinity of the 2014 average price of $85 per barrel. Conversely wells in the 500 to 750 bpd IP range are attractive, but susceptible to oil price fluctuations. Wells having at least 1,000 bpd IPs are attractive at current or higher oil prices, and for the most part, will still be attractive even with a reduction in oil prices.”-KLJ
As the KLJ study shows, IP Rates can be a guiding factor for well development. But, IP rates are tricky. The expected IP rate of a well—often determined by the geographical location into which the well will be drilled—can help determine the time period for which the well can be paid off. But, the expected IP rate can also be impacted by the type of completion methodology used to complete the well. A better design and fracking process (which we’ve written about extensively on pieces focused on cemented liners, slickwater fracks and most recently coiled tubing), can, however, bump up the expected IP rate if the better completion methodology is used regardless of the geographical location of the well.
So, although the price of oil will force operators to look at expected IP rates before investing in a well, IP rates can change, showing that judging oil price’s role on development when linked to IP rates, is complex. Higher IP rates mean operators can withstand lower oil prices. But, getting to higher IP rates may cause well costs to rise.
In part 2, we will consider how well costs, along with operating costs, and crude prices impact oilfield development.