Applying Hydraulic Fracture Diagnostics To Optimize Stimulations in the
Woodford Shale

Vulgamore, Travis; Clawson, Timothy; Pope, Charles E.; Wolhart, S.L.; Mayerhofer, Michael; Machovoe, Sean; Waltman, Charles

doi:10.2523/110029-ms

Cited by 9 publications

(5 citation statements)

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“…Vulgamore et al 3 examined the effects of existing faults and natural fractures' interaction with fracture stimulation. By using microseismic mapping for three fracture treatments, they observed fracture half lengths ranging from 1,360-3,300 ft, and by defining stimulated reservoir volume (SRV) as the product of fracture network area and stimulated pay thickness, they reported a stimulated reservoir volume of 29,247 acre-ft in a fracture treatment with three stages.…”

Section: Introductionmentioning

confidence: 99%

“…The formation is slightly under pressured with pressure gradients in the 0.35 to 0.44 psi/ft range. 3 In a bid to optimize gas production from this shale play, horizontal wells are drilled in the direction of minimum principal stress and multiple hydraulic fractures are placed in close proximity to each other. Recent advances in hydraulic fracturing coupled with the need for production increase due to high gas prices in 2008 revitalized drilling activities from single drilling with 640 acre spacing to a pad drilling of 5 to 6 wells with inter-well spacing as low as 10 acres using lateral lengths extending as long as 5,287 ft.…”

Section: Introductionmentioning

confidence: 99%

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Interference Study in Shale Plays

2012

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Advances in drilling and fracturing technologies in Woodford Shale have attracted the operators to drill horizontal wells with long laterals (up to 5,000 ft), and to fracture using multiple stages (up to 22) using large amounts of slickwater and sand.It has been observed that exploitation of shale plays relies on the ability to contact as much of the reservoir as possible using fracturing techniques by creating a network of interconnecting fractures between laterals placed as close as 660 ft apart. As the spacing gets closer, the operators have a vested interest in knowing the optimal spacing of infill wells. Ideally, an infill well should have as little interference with the existing wells as possible.In this paper, we examine fracture data, and daily gas and water production data of 179 horizontal gas wells over five years in the Arkoma Basin to quantify the impact of interference between wells on their performance. We quantify the lost gas production from the surrounding wells; calculate the probability of interference as a function of distance and age of the surrounding well; determine the preferential direction of interference, and develop a new measure of spacing to understand the relationship between performance of the well and its surrounding wells. Finally, we provide recommendations regarding the spacing of infill wells.

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Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Interference Study in Shale Plays

2012

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“…For this approximation to be reasonable, the spacing between natural fractures should be much smaller than the height of the overall hydraulic fracture. Since the Woodford Shale formation has a typical thickness of 15 to 90 m , the 1D solution could be reasonably applied for average natural fracture spacing 2 h of up to 9 m.…”

Section: Example Analysis On the Woodford Shalementioning

confidence: 99%

Anisotropic porothermoelastic solution and hydro‐thermal effects on fracture width in hydraulic fracturing

Abousleiman

Hoang

Liu

2013

Num Anal Meth Geomechanics

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SUMMARYIn this study, the effects of the temperature difference between hydraulic fracturing fluid and rock formation on the time-dependent evolution of fracture width were investigated using a newly derived one-dimensional anisotropic porothermoelastic analytical solution. The solution is shown to correctly reproduce existing solutions for special cases and corrections for an earlier publication are provided. An analysis of time-dependent fracture width evolution using Woodford Shale data was also presented. It was found that when the fracturing fluid has the same temperature as the shale formation, the fracture gradually closes back after the initial opening due to the invasion of the fracturing fluid. Practically, in this scenario, proppants should be pumped into the fracture as soon as possible to obtain maximum fracture conductivity. On the other hand, with a fracturing fluid 60°C colder than the formation, the thermal contraction of the rock dominates the fracture aperture evolution, resulting in a fracture aperture approximately 70% larger than that produced by the hotter fracturing fluid. Consequently, in this case, it is beneficial to delay proppant placement to take advantage of the widening fractures. Finally, it was found that the fracture aperture is directly controlled by the spacing of natural fractures. Therefore, the presence of natural fractures in the shale formation and their spacing influence not only the type of hydraulic fractures created but also what kind and size of proppants should be used to keep them open.

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“…Microseismic mapping is a technology that has proven valuable for monitoring stimulations in unconventional reservoirs, such as gas shales and tight-gas sandstones (Hart et al 1984;Warpinski et al 1990;Walker et al 1998;Fisher et al 2002;Maxwell et al 2002;Griffin et al 2003;Fisher et al 2004;Warpinski et al 2005;Cipolla et al 2005;Mayerhofer et al 2005;Wolhart et al 2005;Wolhart et al 2006;Shemeta et al 2007;Vulgamore et al 2007;Daniels et al 2007;King et al 2008;Potapenko et al 2009;Waters et al 2009). It is performed by fielding a large array(s) of highly sensitive and high-frequency-response three-component geophones or accelerometers in an offset well(s) in close proximity to an interval that is being stimulated.…”

Section: Introductionmentioning

confidence: 97%

Source-Mechanism Studies on Microseismicity Induced by Hydraulic Fracturing

Warpinski¹,

Du²

2010

All Days

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While microseismic mapping has proven to be a valuable technology for understanding hydraulic-fracture growth and behavior, the seismic waves generated by the microseismic event also contain information that has potential value for understanding the reservoir, natural fractures, stress state, and fracturing mechanisms. Extracting information from the microseismic data requires the use of a source model, which in its most general form is represented by a symmetric moment tensor having six components. Difficulties arise when attempting to invert for the components of the moment tensor if only a single monitor well is available, but in principle the full moment tensor can be extracted for multiple monitor wells. The primary information derived consists of the slippage-plane orientation, the slip direction, and the moment (strength) of the event. Presumably, these slippages occur on existing planes of weakness, such as natural fractures, bedding planes, or potentially even fracture planes induced by the hydraulic fracture, thus providing information about the reservoir and the process. An approach for performing the moment-tensor inversion is discussed for both single and multiple monitor wells, along with methods to estimate various parameters. Both synthetic and field examples are provided to demonstrate what can be extracted from the data set under various conditions.

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Applying Hydraulic Fracture Diagnostics To Optimize Stimulations in the Woodford Shale

Cited by 9 publications

References 0 publications

Interference Study in Shale Plays

Interference Study in Shale Plays

Anisotropic porothermoelastic solution and hydro‐thermal effects on fracture width in hydraulic fracturing

Source-Mechanism Studies on Microseismicity Induced by Hydraulic Fracturing

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