A method for steering a well based on rock properties and obtaining natural fracture information includes inducing tube waves in the well during drilling the well. Acoustic energy is measured in the well. The energy comprises tube wave reflections from formations adjacent to the well. The measured acoustic energy is inverted to determine at least one of a rock property, a near wellbore hydraulic conductivity, and natural fracture occurrence. A trajectory of the well is adjusted to maintain the at least one of a rock property, near wellbore hydraulic conductivity and natural fracture occurrence. An n optimized, well-customized hydraulic fracturing design may be created based on the measured natural fracture properties. A method to optimize hydraulic fracturing treatment based on measured natural fracture properties during drilling.

Downhole measurement systems and methods include deploying a bottomhole assembly having a multipole transmitter into a formation and transmitting acoustic signals into the formation. The multipole transmitter is of order n ≥ 2. Acoustic signals are received at respective receivers that are circumferentially aligned with the multipole transmitter, and are axially offset from the multipole transmitter, and axially offset from each other. The order of the first and second multipole receivers are equal to the order of the multipole transmitter. A controller is used to obtain first and second acoustic multipole data from the first and second multipole receivers at one or more azimuthal angles of a rotation of the bottomhole assembly in a formation during a drilling operation. Acoustic azimuthal anisotropy of the formation is determined from the first acoustic multipole data and the second acoustic multipole data.

A method for identifying a pore and a fracture based on a two-dimensional (2D) scan image of a core includes: scanning a core to acquire an initial 2D image of the core; filtering the initial 2D image of the core to acquire a first 2D image of the core; segmenting the first 2D image of the core to acquire a second 2D image of the core; extracting center coordinates of all pixel points in each void space to acquire a centroid of the void space, and establishing a pore-fracture identification function of the void space; identifying the void space as a fracture if a value of the pore-fracture identification function is greater than a preset characterization value; and identifying the void space as a pore if the value of the pore-fracture identification function is not greater than the preset characterization value.

Systems and methods are disclosed for identifying and displaying geostructural properties as a function of lithology, horizons, and faults interpreted from well and seismic data. Exemplary implementations may include obtaining an initial fracture distribution grid model; obtaining training structural deformation data; obtaining training subsurface lithology parameter data; obtaining training fracture attribute data; and training the initial fracture distribution grid model to generate a trained fracture distribution grid model.

The present disclosure provides a physics-based and data-driven integrated method for rock burst hazard assessment, including the following steps: determining an initial stress concentration coefficient by conducting grid discretization on an assessment region, and assigning a value to each of grid nodes using a Weibull distribution function; obtaining a stress concentration coefficient value of each grid node under physics-based models; introducing seismic wave CT detection data to obtain stress concentration coefficient distribution in the assessment region under the integration of a seismic wave CT detection and its derived characterization stress model; introducing microseismic data to obtain stress concentration coefficient distribution in the assessment region under the integration of a microseismic damage reconstruction stress model; and assessing the degree of rock burst hazard according to the size of the stress concentration coefficient value.

A method for monitoring hydraulic fracturing range of a surface vertical shaft is provided by the present disclosure, belonging to the technical field of ultrahigh-pressure hydraulic fracturing monitoring of the coal mine vertical shafts. The method comprises the following steps: connecting, by an eight-thread communication cable, a high-precision portable micro-seismic monitoring acquisition instrument to a high-sensitivity deep hole sensor, and performing uphole-crosshole-downhole monitoring simultaneously, specifically as follows: providing uphole-crosshole-downhole monitoring holes respectively, and installing deep hole geophones in the monitoring holes; then laying communication cables uphole-crosshole-downhole to connect the geophones to the portable high-precision micro-seismic acquisition instrument respectively; then performing high-precision positioning on the fissure development range by monitoring recorded events and time, thus determining the directions and ranges of a main fracture and secondary induced fractures of hydraulic fractures.

Methods and systems for measuring cluster efficiency for stages of wellbores are provided herein. One method includes selecting a frequency band for generating broadband tube waves within the fluid column of the wellbore and generating the broadband tube waves within the fluid column of the wellbore using a pressure pulse generator that is hydraulically coupled to the wellbore. The method also includes recording data corresponding to the broadband tube waves and reflected broadband tube waves using pressure receivers that are hydraulically coupled to the wellbore. The pressure receivers are arranged into arrays with two or more pressure receivers in each array. The data recorded by the pressure receivers relate to characteristics of reflectors (including perforation cluster/fracture interfaces) within the wellbore. The method further includes processing the recorded data using interferometry and performing full waveform inversion(s) on the processed data to determine frequency-dependent, complex-valued reflection coefficients at each perforation cluster/fracture interface.

A method of detecting an event by: obtaining a first sample data set; determining a frequency domain feature(s) of the first sample data set over a first time period; determining a first threshold for the a frequency domain feature(s) using the first sample data set; determining that the frequency domain feature(s) matches the first threshold; determining the presence of an event during the first time period based on determining that the frequency domain feature(s) matches the first threshold; obtaining a second sample data set; determining a frequency domain feature(s) of the second sample data set over a second time period; determining a second threshold for the frequency domain feature(s) using the second sample data set; determining that the frequency domain feature(s) matches the second threshold; and determining the presence of the event during the second time period based on determining that the frequency domain feature(s) matches the second threshold.

The present invention proposes a method to represent seismic fault damage zones and fracture density in the geological models of reservoirs in a simple, agile and automated way, so that it can be easily replicated by geologists in any production design. It was developed as a group of workflows, inserted in the commercial software Petrel, widely used in the company for the 3D numerical modeling of reservoirs.

A computer-implemented geological modeling method is disclosed. Hydraulic fracturing includes pumping fluids through a wellbore/casing and into a formation through perforations, creating fractures that can improve well productivity. Geological modeling may be used to model pumping of fluids into the subsurface to achieve a desired fracturing result. However, the grid used may affect the fracture propagation calculations used for geological modeling. Thus, a methodology is disclosed which reduces the grid dependence when determining various aspects of fracturing, such as pressure and/or aperture. The methodology uses a first correction factor that is based on the grid used to determine fracture propagation and a second correction factor that is not based on the grid used to determine fracture propagation (such as based on an ideal grid). In this way, the two correction factors are derived from different aspects, which when combined, may be used to reduce grid dependence when determining fracture propagation.