The Anadarko Basin is located within a strike-slip faulting regime (SHMax>Sv>Shmin) which results in large, planar fracture geometries created during the hydraulic stimulation of low permeability formations. The Meramec formation is dominated by siltstones as part of a series of prograding, stacked clinoforms. The geomechanical properties and the regional stress regime are first order drivers in controlling fracture growth rates, size, and ultimately the drainage area. Net pressure and stress shadowing play a significant role in the design of cluster spacing, proppant selection, fluid selection, and resulting fracture geometry. This paper will review an operator’s case study designed to quantify stress shadowing and fracture net pressure using multiple bottomhole pressure gauges (BHPGs) in a horizontal, multi-stage stimulation in the Meramec formation of the Anadarko Basin. The case study will review the measurements taken from two permanently installed BHPGs placed along a horizontal wellbore during a hydraulic stimulation. The first BHPG is located at the toe of a horizontal wellbore being stimulated and is in communication with hydraulic fractures created during the first stage; the second BHPG is located near the heel of the same well being stimulated. The BHPG at the toe of the well is used to measure the poroelastic pressure responses generated as stages are completed uphole from the first stage. Optical fiber is analyzed to evaluate Near Wellbore (NWB) and far-field fracture interactions. The measurements have been integrated into a fracture simulator to calibrate the far-field stress during hydraulic fracture growth. Measured stress shadowing in this pilot allowed the authors to develop an equation that can be solved to estimate net pressure. The results are aligned with measurements obtained from DFITs in the area. Historically, net pressure and stress shadow values have been difficult to measure with high confidence due to various pressure losses between the wellhead and formation. Net pressure is a key for optimal cluster spacing design, and a critical matching parameter for hydraulic stimulation models, small errors in net pressure matches can have significant impacts in the resulting simulated fracture geometry. This paper will detail the integration of empirical data to advance an analytical model that quantifies net pressure and poroelastic stress transfer from a hydraulic fracture.

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Summary The pressure decline data after the end of a hydraulic fracture stage are sometimes monitored for an extended period of time. However, to the best of our knowledge, these data are not analyzed and are often ignored or underappreciated because of a lack of suitable models for the closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that are available in unconventional horizontal wells with multistage, transverse hydraulic fracturing. The methods presented in this study allow us to quantify closure stress and average pore pressure inside the stimulated reservoir volume (SRV) and to infer the uniformity of proppant distribution without additional data acquisition costs. For the first time, field data of diagnostic fracture injection test (DFIT), flowback, and pressure decline of main fracturing stages from the same well are compared and analyzed. We found that the early-time main fracturing stage pressure decline trend is controlled by fracture tip extension, followed by progressive hydraulic fracture closure on the proppant pack, whereas late-time pressure decline reflects linear flow. When DFIT data are not available, pressure decline analysis of a main hydraulic fracturing stage can be a substitution if it can be monitored for an extended period to allow fracture closure on proppants and asperities.