Fiber-Optics Approach Monitors Drainage Profile of Multistage Stimulation
Authors: Carpenter Chris 
Published: January 2024

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212364, “Can You Feel the Pressure? Strain-Based Pressure Estimates,” by Kyle Haustveit, SPE, and Jackson Haffener, SPE, Devon Energy. The paper has not been peer reviewed.

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The combination of horizontal wells and hydraulic stimulation has been key in unlocking vast unconventional resources across North America and elsewhere, but much remains to be understood regarding how the reservoir is drained across the miles of laterals accessing a resource. The density of pressure gauges required to accurately measure the drainage pattern from a horizontal multistage stimulation is currently not realistic economically or technologically. In this case study, the authors describe a method of monitoring the drainage profile of a horizontal multistage stimulation using optical fiber.

Introduction
An advanced subsurface diagnostic project was deployed as part of the Hydraulic Fracture Test Site I, Phase 3, funded by the Department of Energy. A lateral observation well was positioned approximately 225 ft away from the nearest two stimulated and producing horizontal wells. Using optical fiber and Raleigh frequency-shift distributed strain sensing (RFS-DSS), strain change was measured in the far field as the offset well was stimulated and first produced. RFS-DSS provides a spatial resolution of 20 cm, allowing for the monitoring of strain changes at finer spatial resolution than can be sensed accurately with low-frequency distributed acoustic sensing. The strain change during the interference test correlated with both the strain change during the crosswell refracturing monitoring and the pressure-gauge change along the monitor well during the interference test. The strong correlation between crosswell refracturing and interference strain monitoring suggests that the magnitude of crosswell strain responses is directly proportional to the intensity of strain change when the offsetting wells are put online. The comparison of data recorded from RFS-DSS and six reservoir-sensing pressure gauges displayed a strong correlation between the total strain change and total pressure drawdown. Three gauges positioned in regions of large negative strain change during first production, interpreted as drawdown, showed large pressure declines; the other three gauges, positioned in areas of small strain change, saw small pressure declines. The correlation was applied to the total length of the wellbore based on the strain change to estimate a pressure along the entire lateral, including areas without pressure gauges.

Pilot Design
Located in DeWitt County, Texas, the project consisted of a combination of production infill wells (12H and 13H), pre-existing primary wells (2H, 4H, 6H, and 8H), liner refracturing wells (3H and 5H) and one unstimulated observation well (14H). The wells are landed in the lower Eagle Ford formation. While drilling the observation lateral, horizontal core was collected and used to investigate the frequency of hydraulic and propped fractures created from the 4H and 5H original stimulations. The 14H lateral was equipped with permanent optical fiber, one internal pressure-sensing gauge used for sealed wellbore pressure monitoring, and nine reservoir-sensing pressure gauges to monitor fracture interactions and pressure drawdown from the offset wells. Three of the gauges failed to show connection to the reservoir and were discarded for this analysis.