With Proper Spacing and Enough Time, Shale Wells May Produce Much More Gas

Abstract

In 1947, the ‘hydrafrac’ process in the No.1 Klepper well in the Hugoton Field, Kansas, combined four cubic meters of naphthenic acid and palm oil with gasoline and sand to stimulate the flow of natural gas from a limestone formation. In 1973, Amoco introduced massive hydraulic fracturing in the Wattenberg gas field of the Denver Basin to recover gas from a low-permeability sandstone. The injection of 50 cubic meters of water and 90 tons of sand proppant succeeded in recovering much greater volumes of gas than had been previously possible. In 1974, Amoco performed the first million-pound frac job, injecting more than 450 tons of proppant into a well in the Wattenberg field. Between 1981 and 1998, a Texas company, Mitchell Energy and Development, experimented with multistage hydrofracturing of horizontal wells in the Barnett gas shale formation. Commercial success came when the company applied slick water, a low viscosity mixture that could be rapidly pumped down a well to deliver a much higher pressure to the rock than before. Today, about half of US natural gas comes from gas shales, with the Marcellus play being the dominant producer and Haynesville a distant second. The oldest play in the US, Barnett, has had up to 18 years of production from hydrofractured horizontal wells that today may show signs of late-time radial flow. Because of public availability of data in the US, one can study gas production well by well for about 70,000 horizontal shale wells. I will present a field data-driven solution for long-term shale gas production from a horizontal, hydrofractured well far from other wells and reservoir boundaries. Our approach is a hybrid between an unstructured big-data approach and physics-based models. We extend a previous two-parameter scaling theory of shale gas production by adding a third parameter that incorporates gas inflow from the external unstimulated reservoir. This allows us to estimate for the first time the effective permeability of the unstimulated shale and the spacing of fractures in the stimulated region. From an analysis of wells in the Barnett shale, we find that on average, stimulation fractures are spaced every 20 m, and the effective permeability of the unstimulated region is 100 nanodarcy. We estimate that over 30 years on production the Barnett wells will produce on average about 20% more gas because of inflow from the outside of the stimulated volume. There is a clear tradeoff between production rate and ultimate recovery in shale gas development. In particular, our work has strong implications for well spacing in infill drilling programs. A bad early decision on how to develop a lease can affect negatively the long-term production from that lease and ultimate recovery.

AAPG Datapages/Search and Discovery Article #90333©2018 AAPG Middle East Region, Shale Gas Evolution Symposium, Manama, Bahrain, December 11-13, 2018