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Hydraulic Fracturing Techbook 2018

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84 | August 2018 | hartenergy.com HYDRAULIC FRACTURING: CASE STUDIES After acquiring the pressure data in the moni - tor stages, poroelastic pressure responses must be differentiated from pressure responses caused by direct fluid communication or advective/diffusive fluid transport. Once identified, poroelastic signals can be used to estimate hydraulic fracture geometry by matching the observed responses in the monitor stages to a digital twin. The output, which is the frac- ture map, is the fracture dimensions of half-length, height, asymmetry and azimuth and how fast those dimensions grew. Case study An operator working in the Eagle Ford wanted to evaluate completion effectiveness in the Lower Eagle Ford (LEF) shale formation and to identify an appropriate completion strategy in the field. The LEF's physical and geomechanical properties vary significantly from east to west of the formation. Local variations in thickness, thermal maturity and pore pressure pose several challenges in designing a suitable fracture job. The operator conducted a study comprising 14 wells across multiple pads. Pressure-based fracture maps were acquired on all 14 wells. A test matrix was devel- oped to evaluate various completion parameters: fluid system, stage length, perforation clusters, fluid volume and proppant volume. These parameters were varied across the 14 wells and spread across the test pads to ensure good geologic and geomechanical sampling. The operator's goal was to evaluate the effect of stage length, number of perforation clusters, fluid systems, proppant loading and total fluid volumes on the resulting fracture geometry and production. With the pressure-based fracture map, the operator identi- fied the right completion strategy and well spacing. Increasing stage length. Historically, the operator had used a 200-ft stage length with six clusters per stage. Based on the right completion strategy from the pressure-based fracture map, the operator made the informed, better decision to increase the stage length 50 ft to 250 ft with nine clusters per stage. The fluid and proppant volumes were adjusted to provide the same fluid and proppant per cluster. Three fluid systems were evaluated: the company's standard historical design, slickwater and a hybrid cross-linked gel system. Reveal Energy Services' geoscientists and com- pletion engineers computed fracture maps for all 14 wells and analyzed them to understand the impor- tance of each completion parameter on the resulting fracture geometry. Figure 1 shows the effect of changing the stage length from 200 ft to 250 ft for various fluid systems. The results show that the new design with longer stage length and nine clusters provided the same geometry, measured by fracture half-length, as the historical completion design for all three fluid sys- tems. This resulted in a 20% reduction in the number of stages without compromising the effectiveness of the stimulation. Fluid volumes. Three different fluid volumes were evaluated to determine the optimal fluid loading: 25 bbl/ft, 32 bbl/ft and 40 bbl/ft. Figure 2 shows the results. Stages with 25 bbl/ft and 32 bbl/ft showed similar frac- ture half-lengths. Increasing the volume from 32 bbl/ft to 40 bbl/ft, a 25% increase, had a significant change in the resulting half-length. Half-lengths were 33% lon- ger with the 25% increase in fluid volume. Using these results, the operator was able to decide on various com- pletion design parame- ters for field development. The results were derived from the physics-based model of nonintrusive pressure data acquisition and analysis that offered FIGURE 1. By deciding on a 250-ft stage length for these fluid systems, based on the pressure-based fracture map, an Eagle Ford operator achieved the same fracture half- length as the historical 200-ft completion design. (Source: Reveal Energy Services)

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