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.
This paper presents a multidisciplinary approach to evaluating reservoir drainage patterns and hydraulic stimulation interactions among a development of both existing and new wells. Analysis of an extensive diagnostic package focuses on the potential to capture stranded reserves via refracs and infill drilling within the black oil window of the Lower Eagle Ford Shale, DeWitt County, Texas. The project consists of a unique setup of primary (parent) wells, new infill wells, and a horizontal well devoted exclusively to observation. Liner refracs were performed in two of the primary wells, with the remainder receiving preloads. It also included the collection of a horizontal core, formation imaging and advanced lateral logs, sealed wellbore pressure monitoring (SWPM), downhole fiber-optics (both permanent and deployable), seven downhole pressure gauges, time-lapse geochemistry, and iterative production interference tests. This substantial dataset provides vital calibration for well spacing, completion strategy, and field development. With the ability to measure the impacts of completion design, order of operations, refracs, re-pressurization, and infill drilling, detailed knowledge has been gained into improving redevelopment around a depleted parent network. The monitor well acquired 420 ft of horizontal core through the Eagle Ford target interval and is positioned between parent wells 225 ft laterally adjacent on either side. A significant number of hydraulic fractures were encountered, but only 8% contained proppant, indicating the original 2013 vintage completions had a very low conductive to hydraulically stimulated rock volume ratio. Fiber-optic and downhole pressure gauges on the monitor well also indicated that less than half of the parent laterals were effectively preloaded prior to infill completions, and these re-pressurization efforts were not sustained through time. SWPM was employed during refrac and infill completions to observe the stimulation of 156 stages, and over 750 treatment-to-monitor well pairings were captured. These interactions, coupled with findings from fiber and other diagnostic tools, were used to rank 6 different completion designs and define the optimal approach for future activity. Understanding depletion networks and parent/child well interaction is crucial to the future viability of the oil and gas industry. The diagnostic data collected during this project yields important insight into capturing stranded reserves from sub-optimally designed fields, bolstering new well results with higher unit recovery factors, and ultimately achieving a more effective and economic development strategy.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.