Over the past decade the hydraulic fracturing industry has been working to increase oil production from low-permeability or "tight" sands formations by applying the experience and techniques gained from shale oil and gas well completions. The shale-based completion approach calls for the creation of complex but short-length fracture networks via the use of low-viscosity fluid systems combined with pumping at higher rates than a conventional stimulation. This paper is a case study of an oil-producing basin in Mexico. It evaluates the impact on cumulative production from stimulations assumed to have a greater fractured length compared to stimulations of the complex fracture network type with their associated shorter fractures. This paper uses data from a 13-year period (2003 to 2016) comparing wells in two tight sands fields with varying characteristics such as well design, vertical and horizontal configuration, fracture fluid systems and completion techniques.

Due to the studied fields' petrophysical characteristics, hydraulic fracturing was necessary in all cases to economically produce hydrocarbons. Beyond this common characteristic, key properties varied across fields, with high heterogeneity due to the characteristics of the turbidite reservoirs. Natural fractures were not always present, permeability varied from 0.3 to 5 mD, while average porosity was 15% with low changes in vertical stress. Microseismic data acquired in the Basin provided information critical to understanding fracture behavior and, when combined with fracture simulation software, estimating propped geometry.

Among the central observations of this study is that the stimulated reservoir volume (SRV) has certain limitations when oil-bearing compact turbidites are being stimulated. This was especially observed in lateral wells where the minimum horizontal stress (Shmin) increased gradually towards the heel of the well, making it more difficult to generate a complex fracture.

The study area's stimulated wells showed a strong correlation between fracture half-length and cumulative hydrocarbon production. This proved true even among wells with complex fracture networks that typically had higher initial production. The critical conclusion of this study is that an oil well in low-permeability compact turbidites with greater fractured length can generate cumulative production up to 60% greater than a well with a complex but shorter half-length fracture network.

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