Using Distributed Optical Sensing to Constrain Fracture Models and Confirm Reservoir Coverage in the Permian Basin

Abstract

Low-permeability basins present a tremendous challenge to effective completion and reservoir drainage, especially in known heterogeneous environments that present additional complexity. Several robust diagnostic techniques exist in the market currently that are identified as guides to improve completion and stimulation efficiency in basins that require hydraulic fracturing to make low-permeability environments viable. Some of these techniques include fracture modeling, microseismic mapping, diagnostic fracture injection test (DFIT) analysis, radioactive and chemical tracers, and pressure matching. During the past decade, fiber-optic sensing has been identified as an additional tool that can provide significant benefit to complement the more traditional approaches listed previously. In current commercial applications, this includes distributed temperature sensing (DTS), distributed acoustic sensing (DAS), distributed strain sensing (DSS), and optical point pressure and temperature solutions that can define wellbore characteristics through the entire well life cycle.This case study focuses on optical data acquired from a vertical well drilled in Ector County, Texas in the Permian Basin. The well was stimulated using a limited entry approach as a cased and cemented completion. The project attempted to resolve questions pertaining to the distribution of stimulation fluid to each interval, total hydraulic height growth association to each stimulation treatment, and total production contribution from each interval. This paper focuses on using the fiber-optic results in conjunction with other tools to define the stimulation treatment and completion effectiveness.A fiber-optic cable was deployed permanently behind the casing to acquire both DTS and DAS data during stimulation treatment, flowback, and production to review the entire well life cycle. Complementing the distributed optical measurements, fracture modeling was performed using data acquired by fiber optics to constrain the model, as well as openhole logging results to compare to the distributed optical results. A review of the post-job fracture model was compared to the DTS fracture height estimates. If a large discrepancy was observed between these two values, the post-fracture model was revisited to assess if other interpretations of the fracture model were reasonable. Distribution of fluid along the near wellbore was also assessed using DTS results to define hydraulic fracture height growth.

Virginia City Cole Surface/Borehole Microseismic Monitor Program

“…This method is primarily utilized to gain a better understanding of fracture height growth and has been proven very successful in industry, as well as in many deployments at Devon (Warpinski, 2014, Holley, 2014, Smith, 1989. The results from the VC-32 well DTS indicate a fairly contained fracture, as shown by the temperature warmback signature from 7,957ft to 8,091ft (134ft.).…”