Physical Scaling of Oil Production Rates and Ultimate Recovery from All Horizontal Wells in the Bakken Shale

Abstract

A recent study by the Wall Street Journal reveals that the hydrofractured horizontal wells in shales have been producing less than the industrial forecasts with the empirical hyperbolic decline curve analysis (DCA). As an alternative to DCA, we introduce a simple, fast and accurate method of estimating ultimate recovery in oil shales. We adopt a physics-based scaling approach to analyze oil rates and ultimate recovery from 14,888 active horizontal oil wells in the Bakken shale. To predict the Estimated Ultimate Recovery (EUR), we collapse production records from individual horizontal shale oil wells onto two segments of a master curve: (1) We find that cumulative oil production from 4845 wells is still growing linearly with the square root of time; and (2) 6401 wells are already in exponential decline after approximately seven years on production. In addition, 2363 wells have discontinuous production records, because of refracturing or changes in downhole flowing pressure, and are matched with a linear combination of scaling curves superposed in time. The remaining 1279 new wells with less than 12 months on production have too few production records to allow for robust matches. These wells are scaled with the slopes of other comparable wells in the square-root-of-time flow regime. In the end, we predict that total ultimate recovery from all existing horizontal wells in Bakken will be some 4.5 billion barrels of oil. We also find that wells completed in the Middle Bakken formation, in general, produce more oil than those completed in the Upper Three Forks formation. The newly completed longer wells with larger hydrofractures have higher initial production rates, but they decline faster and have EURs similar to the cheaper old wells. There is little correlation among EUR, lateral length, and the number and size of hydrofractures. Therefore, technology may not help much in boosting production of new wells completed in the poor immature areas along the edges of the Williston Basin. Operators and policymakers may use our findings to optimize the possible futures of the Bakken shale and other plays. More importantly, the petroleum industry may adopt our physics-based method as an alternative to the overly optimistic hyperbolic DCA that yields an ‘illusory picture’ of shale oil resources.

Generalized Extreme Value Statistics, Physical Scaling and Forecasts of Oil Production in the Bakken Shale

“…We accounted for well re-fracturing and/or changes in downhole pressure. It turns out that the 12 well prototypes obtained with our hybrid GEV -physical scaling method are as good in duplicating the total field rate as the super-precise scaling of each individual well in our previous work [2]. Since our results are not subject to bias, policy-makers should beware of assuming that the production boom in the Bakken shale will last decades longer.…”

“…We assumed that the rig count in the Bakken will not significantly change from the current value, and 120 wells will be drilled per month will be drilled between now and 2041 ( Figure 9a). By looking at the current trend, many operators narrow their drilling choices to only the core areas to avoid spending money on less productive wells with high watercuts typical of the noncore areas [2]. Thus, it is reasonable to create a drilling schedule that exhausts all potential wells in the core areas before moving out to the less productive noncore areas.…”

“…The most common assumption is that well productivities in shales are log-normally distributed. In this paper, we adopt a hybrid data-driven and physics-based method of predicting oil or gas production in shales that has been introduced in our previous work [1,2]. Here, we will deal only with black oil production.…”

“…The physical scaling curves are based on an analytical solution of the pressure diffusion equation in the hydrofractured horizontal shale well geometry. In previous papers, we comprehensively detailed the physical scaling solutions for shale gas wells [4,5] and shale oil wells [2,20]. The late-time flow from the outer reservoir encompassing the stimulated reservoir volume (SRV) [6] was also quantified.…”

“…years of production data. In a previous paper [2], we scaled well-by-well all ∼15,000 wells in the Bakken. We accounted for well re-fracturing and/or changes in downhole pressure.…”