Abstract: Methods and systems are provided for rapidly estimating the hydrocarbon production potential of a subsurface hydrocarbon shale prospect or prospects. In short, the methods disclosed herein provide rapid mechanisms to determine sorbed gas storage of a shale reservoir with minimal delay and resource expenditure to aid operators in determining which prospects to exploit. In certain embodiments, an empirical implemented method for rapidly assessing hydrocarbon content of a shale reservoir comprises extracting one or more shale samples, performing a rock eval pyrolysis on the shale samples to determine certain geochemical properties of the shale, using the geochemical properties to determine a thermal maturity of the shale, determining a Langmuir volume of the shale, generating a adsorption isotherm of the shale, and determining a gas storage capacity of the shale. Advantages of the methods include a more efficient and rapid determination of shale gas storage with a minimal expenditure of resources.

Abstract: Mechanical properties of formation rock from a subsurface reservoir are measured with a computerized system while a core sample from the formation is being cut, during a process known as slabbing, for other analytical purposes. Forces exerted during cutting of the slab from the original core sample are sensed and stored in the computer system. The recorded force data, cutting time and dimensions of the core sample and the cut slab are processed in the computer system. Measures of characteristics and mechanical properties of the rock, such as rock strength and angle of internal friction, are obtained with the computer system. Separate and specialized testing procedures performed on test core plugs using samples specially extracted from the original core sample are not required.

Abstract: A technique that is usable with a well includes providing a model so predict measurements that are received by receivers due to transmissions by sources based on estimated positions of the receivers relative to the sources. The estimated positions each have at least two dimensions. At least some of the receivers and the sources are located in the well. On a computer, the estimated positions are automatically refined based on a comparison of the predicted measurements and actual measurements that are obtained by the receivers.

Abstract: The gas trap collects formation gases from oil well fluid flow in real time. Gases are released by the fluid when agitated by an agitating pipe which stirs the fluid flow; the gases are then collected and separated from the fluid to be analyzed. The gas trap does hinder the flow of formation cuttings in the drilling fluid flow line, but allows the formation cuttings to flow around the agitator pipe and out to the sample box.

Abstract: A method for determining at least one characteristic of a geological formation having a borehole therein may include collecting first and second dataset snapshots of the geological formation from the borehole. The method may further include generating a differential dataset based upon the first and second dataset snapshots, determining a multi-dimensional space based upon the differential dataset, and generating a first hybrid dataset based upon the first dataset snapshot by projecting the measurement data from the first dataset snapshot parallel to the multi-dimensional space and onto a complementary multi-dimensional space not parallel to the multi-dimensional space.

Abstract: A method for indicating the presence of free gas charged sands, and/or hydrates over free gas, and/or hydrates not over free gas, the method using well log data and a rock physics model. Velocity and density of background clays and sands are extracted from the well log data. The extracted velocities and densities are used to build a rock physics model. An AVO response is generated that is representative of free gas-charged sands. An AVO response is generated that is representative of hydrates over free gas-charged sands. An AVO response is generated that is representative of hydrates devoid of free gas. The generated AVO responses are used to construct an AVO crossplot diagram that is further used to distinguish deposits of free gas charged sands from hydrates over free gas, from hydrates not over free gas.

Abstract: A method, a system, and an apparatus are described for the data acquisition in the well-logging of a borehole wall during the investigation of formation properties. Data acquisition is conducted by either an adaptive phase compensation processing or a modulus mode processing, both of which use in-phase and out-of-phase current components to obtain current values. Adaptive phase compensation employs a calculation of a phase shift compensation value, which may then be applied to subsequent acquisitions and can be further processed in the generation of an image of the borehole wall.

Abstract: A method and apparatus for determining the location of a material located behind an obstruction. A plurality of acoustic resonators (6) having a known resonant frequency are dispersed in the material (3), the material to be located on a first side of the obstruction (2). An instrument (5) is provided at an opposite side of the obstruction to the material. The instrument emits an acoustic signal and measures a response. If the resonant frequency is detected, it is determined that the material is located substantially adjacent to the instrument. The apparatus may be used for determining the height of cement slurry located between a well casing wall and a borehole.

Abstract: An apparatus for estimating a bubble point of a fluid in an earth formation penetrated by a borehole includes: a pump configured to pump fluid from the earth formation through an extendable probe into a volume; and a processor. The processor is configured to perform a pressure-volume test on the fluid sample. The test includes: increasing the pressure of the fluid sample above formation pressure and logging the pressure and volume of the fluid sample; calculating a reference compressibility of the fluid sample; decreasing the pressure of the fluid sample and logging the pressure and volume; calculating a compressibility of the fluid sample using the logged pressure and volume obtained from during the decreasing; comparing the calculated compressibility to a threshold; and estimating the bubble point as the current fluid sample pressure when the calculated compressibility first meets or exceeds the threshold factor.

Abstract: A method for correcting formation properties due to effects of a borehole is disclosed. The method includes obtaining voltage measurements using a logging tool disposed in a borehole penetrating a subsurface formation. The method further includes using a processor to: determine a tensor for the formation using the voltage measurement. For a given set of parameters, the processor determines, based upon the voltage measurements, a parameter value for each parameter in a subset of the set of parameters.

Abstract: Computational methods and systems for monitoring a petroleum reservoir are disclosed. A baseline survey is used to generate baseline data for a petroleum reservoir. Subsequent monitor surveys generate monitor data at different stages of production on the reservoir. The baseline data is reconstructed as if it was acquired at the locations of the sources and receivers of the monitor surveys, and the monitor data is reconstructed as if it was acquired at the same locations of the sources and receivers of the baseline survey. For each monitor survey, two four-dimensional (“4D”) difference data sets are generated from the baseline and monitor data and from the reconstructed data. The 4D difference data sets are combined to reduce background and produce 4D signal data that provides reliable and accurate interpretation of production activity on the reservoir.

Abstract: A method for measuring an enhanced electromagnetic field response, especially in a submarine environment, for the purposes of subsurface data acquisition and processing. An electromagnetic field is applied to subterranean strata at two or more different frequencies, a response at each frequency is detected, and the responses at different frequencies are resolved. The differences in the phase and/or amplitude of the responses are analyzed and the nature of the strata is determined. The same method can be used to determine the hydrocarbon content of a reservoir via the use of a borehole.

Abstract: A method of interpreting petrophysical measurement data include arranging measurements of at least one physical property of formations into a matrix representing the measurements and selecting a range of number of unobserved factors or latent variables for factor analysis. Factor analysis is performed on the measurement matrix and comprises performing factorization of measurements matrix into a number of factors and performing rotation of the factorization results. Whether the factor loadings for each factor have achieved a “simple structure” is determined and either each of the selected number of factors is associated with a physical parameter of the formations, or one is added to the number of factors and factor analysis and rotation are repeated until factor loadings of all factors have achieved “simple structure” such that the each of the number of factors is associated with a physical property of the formations.

Abstract: A system and method for monitoring the permeability of a well structure defining a bore hole. The system comprises a wave generator, a sensor adapted to receive current wave data, and a processor programmed to compare the current wave data to prior wave data in order to determine the permeability of the well structure. The processor can calculate a correlation value and/or a decay value that reflects changes between the current wave data and the prior wave data, and these values can be displayed for the user. The method comprises creating a pressure wave in the bore hole, sensing current wave data, and comparing the current wave data to prior wave data in order to determine the permeability of the well structure. The step of comparing can include calculating a correlation value and/or a decay value that corresponds with the change in the data, and the values can be displayed.

Abstract: The present disclosure relates to borehole logging methods and apparatuses for estimating formation properties using nuclear radiation, particularly an apparatus and method for estimating bulk density of a formation. The method may include using gamma ray count rate information to model bulk density. The method may include using time-dependent ratios with a pulsed radiation source. The method may also include dividing gamma ray information by time and/or by energy window. The apparatus includes a processor and storage subsystem with a program that, when executed, implements the method.

Abstract: Method for reducing artifacts in a subsurface physical properties model (120) inferred by iterative inversion (140) of geophysical data (130), wherein the artifacts are associated with some approximation (110) made during the iterative inversion. In the method, some aspect of the approximation is changed (160) as the inversion is iterated such that the artifacts do not increase by coherent addition.

Abstract: The magnitude of asphaltic precipitation when injecting a viscosity reducing diluent into a reservoir formation, notably to assist oil recovery therefrom, is forecast by (i) determining a relationship between asphaltic precipitation and a solubility parameter for the diluted oil, and then (ii) utilizing that relationship to forecast the magnitude of asphaltic precipitation when injecting a predetermined viscosity reducing diluent into the formation. Making this forecast may be followed by injecting a viscosity reducing diluent into the formation to assist oil recovery. The diluent may in particular be supercritical carbon dioxide or other asphaltene precipitant mixed with a more polar material in proportions designed by forecasting asphaltic precipitation by candidate materials in possible proportions.

Abstract: A method and apparatus for determining the fluid permeability of an earth formation is described. An instrument comprising an acoustic source and acoustic and electrokinetic sensors is located in a borehole at a site of interest. The acoustic source is fired and the resulting variations in pressure and electric field generated are measured and recorded. The Biot equation, and an equation for the streaming potential coupled to fluid displacement terms, is solved using finite element analysis to give an expected pressure waveform and electrokinetic waveform based on estimated earth formation properties. By comparison of the measured waveforms and those calculated from the equations, the actual permeability of the earth formation can be deduced.

Abstract: An electromagnetic energy transmitter is provided for borehole to surface electromagnetic (BSEM) surveying. The transmitter is lowered into a well borehole to a desired location in a well borehole to emit electromagnetic energy for the surveys. The transmitter affords more accurate measurements of its position in the well borehole. The transmitter also senses pressure and temperature conditions at its borehole location to provide indications of detected potential problems in the well from the survey or other sources, and to reduce risks and enhance safety and quality of the operations.

Abstract: A method and apparatus for geobaric analysis. The method may include acquiring an in situ gas volume of a subterranean formation, acquiring a drilling fluid characteristic, determining a volume of gas excavated from the subterranean formation utilizing the drilling fluid characteristic, and estimating the formation pressure utilizing the in situ gas volume and the excavated gas volume.

Abstract: A Bayesian methodology is described for designing experiments or surveys that are improved by utilizing available prior information to guide the design toward maximally reducing posterior uncertainties in the interpretation of the future experiment. Synthetic geophysical tomography examples are used to illustrate benefits of this approach.

Abstract: A system and a computer implemented method for performing simultaneous petrophysical analysis for composition and texture of a rock formation. The method includes inputting a set of response equations for sand, shale and fluid that are present in the rock formation, wherein the shale comprises laminated shale, dispersed shale and structural shale; determining simultaneously a solution of the set of response equations, the solution describing composition and texture of the rock formation; and determining from the solution volume fractions for sand, shale and fluid and a texture of the shale including fractions of laminated shale, dispersed shale and structural shale.

Abstract: Cross-well electromagnetic (EM) imaging is performed using high-power pulsed magnetic field sources, time-domain signal acquisition, low-noise magnetic field sensors, spatial oversampling and super-resolution image enhancement and injected magnetic nanofluids. Inter-well images are generated mapping electromagnetic (EM) signal speed (group velocity) rather than conductivity maps. EM velocity maps with improved resolution for both native and injected fluids are provided.

Abstract: Methods and systems are provided for allocating production among reservoir compartments by way of compositional and isotopic analysis. That is, where individual reservoir compartments contribute differing amounts of fluid to a commingled production stream, the methods herein determine the relative contribution of fluid volume from each reservoir compartment. Both a composition-based relative contribution and an isotope-based relative contribution of fluid from each reservoir compartment may be determined to allocate production to each reservoir compartment, the determinations respectively being based on composition mass balances and stable carbon isotope mass balances of components. The combination of both allocation analysis provides quality checks on the results that identify improper allocations that may arise. In addition to production allocation, other applications include, among others, determining the effectiveness of intervention operations and providing feedback for adjusting operations.

Abstract: Calculating a fault throw. At least some embodiments are methods of determining an underground surface or horizon including: identifying an occluded zone residing between a first and second faults, the occluded zone not penetrated by an actual borehole, and the first and second faults intersect an expected location of the surface; calculating a fault throw for the first fault; and calculating the underground surface using the fault throw. Calculating the fault throw may include: calculating a first pseudo depth at a first end of the first fault, the calculating the first pseudo depth using at least one actual depth value that resides across the first fault from the first end; calculating a second pseudo depth at a second end of the first fault, the second end distinct from the first end; and determining the fault throw using the first and second pseudo depths.

Abstract: Method for evaluating cement quality in a cased well. A density log of the well is obtained using, for example, a GammaRay sources and detectors (51). The detector count rates are inverted to provide initial estimates of cement density and thickness (53). Acoustic waveform data are obtained from the well using an acoustic logging tool (52). The acoustic data are inverted (54-56), using the initial estimates of cement density and thickness obtained from the density logs, and an updated density log is inferred. Cement images are obtained from the updated density log, and cement bond quality can be estimated (57).

Abstract: A computer system and method for monitoring at least one performance aspect of a plurality of well stimulation operations conducted on a production well penetrating a subterranean formation. The computer system and method involves calculating seismic moments of the microseismic events based upon the shear and compressional waves of the microseismic signal data, totalizing the seismic moment values to a form a cumulative moment of the microseismic events occurring during the time period, and normalizing the seismic moments with the cumulative moment to transform the seismic moments into a normalized seismic moment data set. The microseismic signal data is indicative of shear and compressional waves having amplitudes and frequencies of microseismic events induced by the plurality of well stimulation operations over different time periods.

Abstract: Application of nonlinear resonance interferometry is introduced as a new geophysical approach to improve predictability in characterization of subsurface microseismic event analysis and propagation of fracture. In contrast to reflection methods that remove random information noise, nonlinear resonance interferometry exploits the full microseismic acquisition spectrum. In some examples, systems and techniques implement novel computational interactions between acquired microseismic wavefield attributes and a nonlinear system in software to amplify distortions in microseismic noise and exploits injection of synthetic noise, in software format, to fracture events.

Abstract: A method and a system is disclosed for determining RON and/or MON values from constant volume combustion chamber apparatuses capable of producing pressure versus time combustion profiles having a fast combustion region and a slow combustion region, where data from the two regions is used to compute RON and/or MON values for light distillate fluid samples using a series expansion equation.

Abstract: A method of passive surveying comprises generating one or more detected signals by passively detecting a signal generated within a subsurface earth formation due to a seismoelectric response or an electroseismic response in at least one porous subsurface earth formation containing at least one fluid, and processing the one or more detected signals to determine at least one property of the subsurface earth formation.

Abstract: A method performed with a computing system for determining well integrity includes receiving a selection of a well configuration of a well comprising one or more casing strings and a production tubing extending from adjacent a wellhead of the well to adjacent a bottom of the well; receiving a selection of a wellbore operation performed with the well configuration; determining, based on the well configuration and the wellbore operation, a characteristic of the well at or adjacent the one or more casing strings and the production tubing during the wellbore operation; modifying the well configuration to remove the production tubing; and determining, based on the modified well configuration and the wellbore operation, the characteristic of the well at or adjacent the one or more casing strings during the wellbore operation.

Abstract: Hydrocarbon recovery strategy development. At least some of the illustrative embodiments are methods including: selecting a set of attributes regarding a first undeveloped hydrocarbon reservoir; identifying a first group of developed hydrocarbon reservoirs, the identifying based on the set of attributes of the first undeveloped hydrocarbon reservoir, and the identifying by a computer system; calculating a first set of statistical data based on the first group of developed hydrocarbon reservoirs, the calculating by the computer system; scaling the first set of statistical data in reference to the set of attributes of the first undeveloped hydrocarbon reservoir to create a second set of statistical data, the scaling by the computer system; and implementing at least one hydrocarbon recovery strategy for the first undeveloped hydrocarbon.

Abstract: A simple, applicable in the field, and extra-equipment free method is provided for determining steam dryness directly in a thermal recovery of high-viscosity oil. A non-condensable gas is added into a saturated steam being injected into a well. The presence of non-condensable gas changes partial steam pressure. Correspondingly the steam condensation temperature also changes. The borehole temperature or pressure measurements can be used to evaluate the steam dryness.

Abstract: The present disclosure describes systems and methods for performing stratigraphic modeling using production data density profiles. At least some illustrative embodiments include a production logging tool data processing method that includes measuring one or more characteristics of a formation within a borehole, of fluids within the formation or of fluids within the borehole, calculating a density profile of each of the one or more characteristics, and defining a boundary between two reservoir simulation cells based at least in part upon the density profile. The method further includes performing a simulation of a production field including the borehole using said simulation cells and presenting the simulation results to a user.

Abstract: Models of fluid flow in wells in formation of a subsurface earth reservoir are formed by computers based on measurements obtained by well logging tools run in the wells and measurements of formation rock characteristics obtained from laboratory data. The models so formed are used to form measures of injection/production profiles and assist reservoir engineers in allocation of production and injection wells for the reservoir, and in other reservoir production planning and analysis.

Abstract: Mechanical properties of formation rock from a subsurface reservoir are measured with a computerized system while a core sample from the formation is being cut, during a process known as slabbing, for other analytical purposes. Forces exerted during cutting of the slab from the original core sample are sensed and stored in the computer system. The recorded force data, cutting time and dimensions of the core sample and the cut slab are processed in the computer system. Measures of characteristics and mechanical properties of the rock, such as rock strength and angle of internal friction, are obtained with the computer system. Separate and specialized testing procedures performed on test core plugs using samples specially extracted from the original core sample are not required.

Abstract: A method of calibrating a measurement device includes: compiling historical calibration data for the measurement device, the historical calibration data including values corresponding to outputs of the measurement device over a first operating duration in environmental conditions associated with an operating environment; projecting the historical calibration data over a subsequent operating duration to generate predictive calibration data; disposing the measurement device in the operating environment and generating measurement signals during the first operating duration and the subsequent operating duration; and generating measurement values from measurement signals generated during the subsequent operating duration based on the predictive calibration data.

Abstract: A method of completing a hydrocarbon lateral well in a target shale formation. The method uses a data log generated from an optical flow cell assembly to identify areas in the lateral well of high free gas porosity. By evaluating such data, an operator can group “like” rock, determine stage length and variation in stage length, and determine perforation cluster spacing and location. The flow cell assembly can also be used in a completion program to assist in the steering of a lateral well being drilled below the target formation.

Abstract: A method for estimating principal stresses of a subterranean formation from seismic data. In one embodiment, rock strength parameters from seismic data of the formation is first determined to calculate the anisotropic elastic properties of the formation. The three principal stresses of the formation: vertical stress, minimum horizontal stress, and maximum horizontal stress, is determined using at least the calculated anisotropic elastic properties and the rock strength parameters of the formation. From the estimated principal stresses, the differential ratio of the maximum and minimum horizontal stresses can be determined to indicate optimal zones for hydraulic fracturing. In another embodiment, a tectonic strain term is introduced to calibrate the estimated principal estimated stress to a known reference point. In yet another embodiment, hoop stress is incorporated to estimate the fracture initiation pressures.

Abstract: The computer readable medium causes a gas processor with gas processor data storage to implement computer instructions to receive device data in various device protocols simultaneously information from rig based sensors and gas analysis devices, calibrate the devices and graphically present the data using both time events and depth events. The computer readable medium can scale the data and form the geological-hydrocarbon executive dashboard for transmission to various client devices to present real time streaming data, real time calibration information, real time alarms while enabling users to add and remove detection devices and sensors, including rig servers and remote servers, online without shutting down the operation of the computer readable medium.

Abstract: A method of determining anisotropy in a borehole is disclosed. An array of measurements along the borehole is obtained and a first depth in the borehole is selected. An arbitrary plane oriented with respect to the borehole at the first depth is designated and an anisotropy for the first depth with respect to the arbitrary plane is determined. The arbitrary plane is repositioned at the first depth and an anisotropy for different positions of the arbitrary plane at the first depth is determined. A minimum anisotropy coefficient with respect to the arbitrary plane at the first depth is identified based on anisotropy for different positions of the arbitrary plane. An anisotropy tensor for the first depth is then identified.

Abstract: In accordance with an embodiment of the present invention, a method of processing large volumes of data to allow for real-time reservoir management is disclosed, comprising: a) acquiring a first data series from a first reservoir sensor; b) establishing a set of criteria based on reservoir management objectives, sensor characteristics, sensor location, nature of the reservoir, and data storage optimization, etc.; c) identifying one or more subsets of the first data series meeting at least one of the criteria; and optionally d) generating one or more second data series based on at least one of the subsets. This methodology may be repeated for numerous reservoir sensors. This methodology allows for intelligent evaluation of sensor data by using carefully established criteria to intelligently select one or more subsets of data. In an alternative embodiment, sensor data from one or more sensors may be evaluated while processing data from a different sensor.

Abstract: A downhole logging tool is equipped with a modified Helmholtz resonator for facilitating acoustic formation evaluation and reservoir characterization. The resonator permits calculation of sound speed and viscosity of the fluid in the resonator cavity. The presence of gas bubbles in the fluid may also be detected. The modified Helmholtz resonator includes at least two openings so that fluid can flow through the resonator cavity. Because fluid can flow through the resonator cavity, local fluid can be measured under local conditions, e.g., downhole temperature, pressure, and gas influx from formations. Further, the modified Helmholtz resonator utilizes an acoustic signal at or near the frequency of interest for at least some acoustic logging tools.

Abstract: Application of nonlinear resonance interferometry is introduced as a new geophysical approach to improve predictability in characterization of subsurface porosity, rock and fluid properties. In contrast to reflection methods that remove random information noise, nonlinear resonance interferometry exploits the full seismic acquisition spectrum to assess how low frequency and high-frequency noise is differentially and directly modulated by varying levels of porosity and hydrocarbon content in the lithologies of interest. In some examples, systems and techniques implement novel computational interactions between acquired seismic wavefield attributes and a nonlinear system in software to amplify distortions in seismic noise and exploits injection of synthetic noise, in software format, to detect hydrocarbon traps and lithology changes at spatial scales below seismic resolution, thereby increasing the information value of low-resolution data.

Abstract: A method of automatically interpreting well log data indicative of physical attributes of a portion of a subterranean formation which include some portion of samples with known facies classification to be used as training data, dividing the training data into two subsets, a calibration set and a cross-validation set, using an automated supervised learning facies identification method to determine a preliminary identification of facies in the subterranean formation based on the calibration set, calculating a confusion matrix for the supervised learning facies identification method by comparing predicted and observed facies for the cross-validation set, calculating a facies transition matrix characterizing changes between contiguous facies, and using the preliminary identification, the facies transition matrix, and the confusion matrix, iteratively calculating updated facies identifications.

Abstract: Described herein are embodiments of a method for generating a refined depofacies classification corresponding to a subsurface reservoir. The method includes analyzing a plurality of rock cores obtained from a plurality of wells drilled in the reservoir or field, analyzing a plurality of well logs comprising a plurality of different well log types obtained from the plurality of wells, and determining an initial depofacies classification for at least portions of the oil or gas reservoir or field. It is then determined whether at least one diagenetic, heavy, light or anomalous mineral is present in some of the analyzed rock cores, and if so, whether at least one well log type from among the plurality of different well log types is capable of substantially accurately identifying the presence of the mineral present. The initial depofacies classification is re-analyzed and reclassified to produce a refined depofacies classification.

Abstract: Systems and methods for quickly determining wettability using a derived relationship between the two Nuclear Magnetic Resonance (NMR) relaxation times T1,oil and T2,oil combined with downhole or laboratory based NMR measurements. The derived relationship between T1,oil, T2,oil and wettability can be developed empirically for example from core-sample data. Once the relationship is defined, it can be used in the field or laboratory to quickly determine wettability from NMR measurements that measure T1,oil and T2,oil directly, or a function depending on them.

Abstract: Disclosed herein is a method of locating and quantifying friction between a drillstring and a wellbore. The method includes, positioning a plurality of sensors within a wellbore, communicatively coupling the plurality of sensors, monitoring signals from the plurality of sensors, logging the sensed signals versus time versus depth of each of the plurality of sensors, locating at least one friction zone along the drillstring within the wellbore based on the logging and quantifying friction in the at least one friction zone based on the logging.

Abstract: A method for structural dip removal. The method includes converting a seismic volume to a depth domain, extracting seismic dips from the seismic volume in the depth domain along a borehole trajectory, analyzing a borehole using the seismic dips to obtain structural dip data, and in response to determining that the seismic dips and borehole dips obtained from borehole imagery are consistent, generating a three dimensional (“3D”) structural model using the structural dip data. The method further includes performing a structural restoration using the 3D structural model to obtain depositional geometry data, removing structural dip from the borehole imagery using the 3D structural model to obtain sedimentary dip data, and performing a stratigraphic interpretation using the depositional geometry data and the sedimentary dip data.

Abstract: A method for updating an earth model with fractures or faults using a microseismic data using mechanical attributes of an identified faults or fracture by matching a failure criterion to observed microseismic events for an identified fault or fracture.