A system includes a first instrumented bridge plug positionable in a downhole wellbore environment. The first instrumented bridge plug includes an acoustic source for transmitting an acoustic signal. The system also includes a second instrumented bridge plug positionable in the downhole wellbore environment. The second instrumented bridge plug includes an acoustic sensor for receiving a reflected acoustic signal originating from the acoustic signal. The reflected acoustic signal being usable to interpret wellbore formation characteristics of the downhole wellbore environment.

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.

Uncertainty of microseismic monitoring results can be reduced to improve hydraulic fracture modeling. A computing device can use a fracture model to determine a predicted geometry of a hydraulic fracture in a subterranean formation based on properties of a fracturing fluid that is introduced into the subterranean formation. An uncertainty index of the predicted geometry of the hydraulic fracture can be determined based on an uncertainty value of the predicted geometry and a trend of uncertainty values. When the injection flow rate of the fracturing fluid is less than a maximum flow rate, it can be increased from an initial injection flow rate to an increased injection flow rate in response to determining the uncertainty index exceeds a pre-set maximum.

A method of performing single trace inversion to characterize changes in a subsurface region includes obtaining a base seismic trace and a monitor seismic trace of the subsurface region at different respective times. The method includes generating a predicted monitor seismic trace from the base seismic trace by a process including applying a time shift to the base seismic trace, the time shift being derived from estimated velocity perturbations occurring between the base seismic trace and the monitor seismic trace, compensating for amplitude changes between the base seismic trace and the monitor seismic trace, wherein the time shift is applied to the amplitude changes, and minimizing a difference between the predicted monitor seismic trace and the monitor seismic trace by iteratively estimating the velocity perturbations to obtain final estimated velocity perturbations. Changes of at least part of the subsurface region may be characterized using the final estimated velocity perturbations.

Systems and methods for estimating well production performance in fractured reservoir systems using real-time down-hole temperature and stress information from advanced monitoring techniques.

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.

Described herein are methods and techniques for determining one or more characteristics of a hydrocarbon source. The method comprises obtaining a hydrocarbon fluid sample, determining at least one measured clumped isotope signature or measured position specific isotope signature for at least one hydrocarbon species of interest in the hydrocarbon fluid sample, determining at least one expected clumped isotope signature or expected position specific isotope signature for the hydrocarbon species of interest, comparing the measured clumped isotope signature or measured position specific isotope signature with the expected clumped isotope signature or expected position specific isotope signature, and determining at least one characteristic of the source of the hydrocarbon sample based on the comparison.

The present invention provides a technique to separate compressional seismic waves from shear seismic waves and to determine their direction of propagation to enhance the seismic monitoring oil and gas reservoirs and the seismic monitoring of hydrofracturing in oil and gas wells. The invention utilizes various combinations of multi-component linear seismic sensors, multi-component rotational seismic sensors, and pressure sensors. Sensors are jointly deployed in arrays of shallow monitoring wells to avoid the complicating effects of the free surface of the earth. The emplacement of sensors in the shallow monitoring wells may be permanent. The method has a wide range of application in oil and gas exploration and production. This abstract is not intended to be used to interpret or limit the claims of this invention.

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.