Low Brent crude prices reveal complexities of Bakken production

By The Bakken Magazine Staff | November 12, 2014

With crude prices trading at yearly lows and global supply potentially outpacing demand, consider this: Bakken operators consider two main factors when determining the financial breakeven point for new or existing wells: initial production rates and water production, said Lynn Helms, director of North Dakota’s Oil and Gas Division.

IP rates can change depending on multiple factors, including: the drilling or completion company’s ability to execute a pre-determined drilling or fracking plan; well location within the Williston Basin; targeted formation; and, the manipulation of a well choke to increase or decrease well pressure. Depending on the size of choke, a well’s IP rate can go up or down as a larger choke allows more hydrocarbons and pressure to flow to the surface.

Operators use IP rates of previous wells to estimate future production in new wells that will be brought online in similar conditions as the previously completed wells. Based on a well’s IP rate, an operator can determine how long it will take the well to break even under a wide range of oil prices.

But IP rates are not always exact. Although the geographical formation and surface location for a given well are always the basis for understanding possible IP rates, completion methodologies can alter production. In some cases, new fracking designs that utilize higher volumes of sand and water can increase a well’s IP rate above other wells brought online in the same geographic formation and surface location. Operators must determine the economics of increased completion investments and the correlation to better IP rates.

Water production can increase the amount of operating costs associated with a given well or field. If the total amount of liquids retrieved from below ground includes a high percentage of water to oil, operators are forced to dispose of the water. Doing so adds costs and cuts into the overall profits of the well. In areas with high water cuts and average IP rates, low oil prices do not offer an attractive enough financial incentive to invest the $7 million to $12 million it takes to bring a well online.

For the North Dakota portion of the Williston Basin, low oil prices could potentially slow oil production in roughly 10 percent of the play, Helms said.  Areas that offer IP rates on the low-end of the entire play and also produce high water cuts will not be economical if oil trades in the $70/barrel range.

Operations costs—the cost to power a well site or transport produced water—will be the first area operators look to for cost cutting measures. After that, some may consider laying drilling rigs down, but in most cases, operators have already contracted out for long-term drilling rig use.

If oil prices continue to decrease, the state of North Dakota could implement tax triggers designed to keep oil production happening in times of low oil prices. If the price of West Texas Intermediate falls below $52.06 per barrel for five consecutive months, the state will implement a trigger that that drops the tax rates for horizontal wells in the Bakken or Three Forks formations down to 2 percent instead of the current 6.5 percent. “That would be the most significant tax trigger in terms of incentive for the oil and gas industry to continue drilling and producing but it would be an enormous impact on state revenue,” Helms said. “If it triggers, then it’s in place for a minimum of five months.”