The present disclosure provides a system and method for estimating fracture density within a subsurface formation from S-wave seismic data. In one embodiment, the S-wave seismic data is separated into fast (“S.sub.1”) and slow (“S.sub.2”) data. A computer is used to compute local similarity of the S.sub.1 and S.sub.2 data and to compute a cumulative time-difference by which the S.sub.2 data lags the S.sub.1 data from the local similarity. Based on the computed cumulative time-difference, the fracture density of a subsurface formation is estimated.

A device for evaluating characteristics of a target ground containing a metal component is proposed. The device includes: a penetration probe having a main frame and a pair of side frames respectively installed at opposite side ends of the main frame, wherein each side frame has a lower end thereof extending downward from the main frame; a plurality of electrodes installed to be exposed to outside on the main frame; an electrode measurement part for measuring apparent chargeability of the target ground by applying power for measurement to the plurality of electrodes; and a main processor for calculating a weight ratio of a metal component of the target ground on the basis of the apparent chargeability measured by the electrode measurement part and calculating a volume ratio of the metal component of the target ground on the basis of the calculated weight ratio of the metal component.

A subaqueous underground survey system using a reflection seismic survey method includes: multiple sound sources 1 for generating sound waves in the water; a controller 2 for controlling phases of the sound waves; a geophone 3 for receiving reflected waves of the sound waves; and an observation ship 4 equipped with the sound sources 1, wherein the controller 2 controls phases of the sound sources 1 so that the sound waves generated from the respective sound sources 1 have a phase difference at a water bottom surface B, thereby controlling generation of shear waves to propagate into the ground.

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.

Predicting elastic parameters of a subsurface includes modelling changes in the shear modulus and changes in the bulk modulus of the subsurface as a combination of a host medium shear modulus and host medium bulk modulus and a plurality of inclusion shear moduli and inclusion bulk moduli. Each inclusion shear modulus and inclusion bulk modulus associated with a unique inclusion geometry. An inclusion-based rock physical model is used to solve the models for changes in shear modulus and changes in bulk modulus to predict an effective shear modulus of the subsurface and an effective bulk modulus of the subsurface.

A method is described that includes obtaining a multicomponent seismic data set for a subterranean region of interest and determining, using a computer processor, a PP stacked time-domain seismic image and a PS stacked time-domain seismic image from the multicomponent seismic data set. The method further includes transforming a recording-time axis of at least one of the PP stacked time-domain seismic image and the PS stacked time-domain seismic image to produce a pair of coarsely-registered PP and PS seismic images and filtering at least one of the pair to produce a pair of spectrally-matched PP and PS seismic images. Further, the method includes dynamically warping at least one of the pair of spectrally-matched PP and PS seismic images to produce a pair of fully-registered PP and PS seismic images.

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.

Various embodiments include apparatus and methods to operate to record a plurality of acoustic waveforms, to generate an objective function based on the plurality of acoustic waveforms, and to estimate a global minimum of the objective function. The plurality of acoustic waveforms can correspond to a plurality of acoustic dipole receivers azimuthally disposed around a tool to which the receivers are attached. Additional apparatus, systems, and methods are disclosed.

PP and PS seismic data are jointly inverted in a stratigraphic grid, using different time axes for PP and PS reflections. A ratio of PP and of PS waves'travel times inside a same layer cell maintained to be a function of a ratio of a P-wave propagation velocity and of an S-wave propagation velocity therein. Since PP and PS seismic amplitudes and travel times are due to elastic properties of the same structure, they can be inverted at the same time to provide better estimates of these elastic properties.

A method for estimating a fluid pressure required to stimulate a subsurface formation includes using seismic signals detected by a plurality of seismic sensors disposed proximate the subsurface formation. Spatial positions and times of origin (“hypocenters”) of each of a plurality of microseismic events induced by pumping fluid into the subsurface formation are estimated. Magnitudes and directions of principal stresses are estimated from the hypocenters and from amplitude and phase of the detected seismic signals for each of the microseismic events. Shear and normal stresses of induced fractures are from the estimated principal stresses. A fluid pressure required to cause formation failure on each fracture is estimated using the estimated shear and normal stresses.