Methods and mediums for estimating stimulated reservoir volumes are disclosed. Some method embodiments may include obtaining microseismic event data acquired during a hydraulic fracturing treatment of the formation, the data including event location and at least one additional attribute for each microseismic event within the formation; filtering the microseismic events based on the at least one additional attribute; determining a density of filtered microseismic events; weighting the filtered microseismic events based on the density; and determining a stimulated reservoir volume estimate based on filtered and weighted microseismic events.

In accordance with some embodiments of the present disclosure, a method of modeling a downhole drilling tool is disclosed. The method may include obtaining microseismic data corresponding to a treatment of a subterranean region, the microseismic data including a microseismic event time for each of a plurality of microseismic events, and a microseismic event location for each of the plurality of microseismic events. The method may additionally include calculating a plurality of fracture planes based upon the microseismic event times, and calculating a closed boundary enclosing a first subset of the plurality of fracture planes. The method may further include identifying a microseismic supported stimulated reservoir volume (μSRN) for the treatment based on the closed boundary.

A method can include receiving acoustic emission data for acoustic emissions originating in a formation, performing a moment tensor analysis of the data, thereby yielding acoustic emission source parameters, determining at least one acoustic emission source parameter angle having a highest number of associated acoustic emission events, and calculating an in situ stress parameter, based on the acoustic emission source parameter angle. A system can include multiple sensors that sense acoustic emissions originating in a formation, and a computer including a computer readable medium having instructions that cause a processor to perform a moment tensor analysis of the data and yield acoustic emission source parameters, determine at least one acoustic emission source parameter angle having a highest number of associated acoustic emission events, and calculate an in situ stress parameter, based on the acoustic emission source parameter angle.

Disclosed herein are various embodiments of methods and systems for optimizing the analysis of the source locations of microseismic sources, comprising recording microseismic data using patches of sensors. Each patch contains multiple sensors, arranged as a grid or a line segment. This approach uses fewer sensors and can cover a larger area than previous techniques for acquiring microseismic data. The data recorded in this way can be filtered using directional filters, such that each patch may be targeted at a specific point in the subsurface. The microseismic source-scanning algorithm benefits from having data filtered to include directional signals only from pairs of patch locations and subsurface locations. This produces an improved estimate of the locations of microseismic events. The patches may be disposed about a horizontal well bore, and aligned such that directional filtering enhances data from hydraulic fracturing operations in the wellbore.

A method including selecting a forward model based on a modeled well structure and including a single modeled acoustic source located in a modeled wellbore and a plurality of modeled acoustic sensors located in a modeled source area, simulating an acoustic signal generated by the single modeled acoustic source and received by each modeled acoustic sensor, calculating phases of the simulated acoustic signals received at each modeled acoustic sensor, obtaining with a principle of reciprocity a plurality of modeled acoustic sources in the modeled source area and a single modeled acoustic sensor in the modeled wellbore, calculating phase delays of the simulated acoustic signals between each modeled acoustic source and the single modeled acoustic sensor, detecting acoustic signals generated by a flow of fluid using acoustic sensors in a wellbore, and processing the acoustic signals using the phase delays to generate a flow likelihood map.

Disclosed are tools, systems, and methods for detecting one or more underground acoustic sources and localizing them in depth and radial distance from a wellbore, for example, for the purpose of finding underground fluid flows, such as may result from leaks in the well barriers. In various embodiments, acoustic-source detection and localization are accomplished with an array of at least three acoustic sensors disposed in the wellbore, in conjunction with array signal processing.

The application describes methods and apparatus for seismic monitoring using fiber optic distributed acoustic sensing (DAS). The method involves interrogating a first optical fiber (102) deployed in an area of interest to provide a distributed acoustic sensor comprising a plurality of longitudinal sensing portions of fiber and also monitoring at least one geophone (107) deployed in the area of interest. The signal from the at least one geophone is analyzed to detect an event of interest (105). If an event of interest is detected the data from the distributed acoustic sensor acquired during said event of interest is recorded. The geophone may be co-located with part of the sensing fiber and in some embodiments may be integrated (307) with the sensing fiber.

Disclosed are tools, systems, and methods for detecting one or more underground acoustic sources and localizing them in depth and radial distance from a wellbore, for example, for the purpose of finding underground fluid flows, such as may result from leaks in the well barriers. In various embodiments, acoustic-source detection and localization are accomplished with an array of at least three acoustic sensors disposed in the wellbore, in conjunction with array signal processing.

According certain aspects, embodiments of the invention consider the problem of microseismic event localization from a parameter estimation perspective, and include a method and system for computing and displaying characteristics of event localization errors. According to certain other aspects, embodiments of the invention include techniques for deriving aggregate statistics from a set of event location estimates, including methods for computing and displaying the probability that an event occurred in any given volume, and methods for describing and displaying the smallest volume that contains a specified percentage of the event probability or expected to contain the specified percentage of the events.

An interrogation system includes a light signal switch and a reflection signal switch. The light signal switch may be communicatively coupled to an optical light source. The light signal switch may route a light signal generated by the light source downhole in a wellbore through a single-mode optical fiber cable or a multi-mode optical fiber cable. The reflection signal switch may be communicatively coupled to the single-mode optical fiber cable and the multi-mode optical fiber cable. The reflection signal switch may route a reflection of the light signal from the signal-mode optical fiber cable or the multi-mode optical fiber cable to an optical detector.