Abstract: Examples of methods and systems are disclosed. The methods may include obtaining seismic data associated with a subsurface region of interest, wherein the seismic data comprises a plurality of time-space waveforms. The methods may also include determining a plurality of mechanical parameters corresponding to a formation of the subsurface region based, at least in part, on the plurality of time-space waveforms. The methods may further include generating a filtering region based on an artifact identified in the plurality of time-space waveforms. The methods may still further include determining a plurality of attenuation parameters based, at least in part, on the filtering region, the attenuation parameters being configured to attenuate the artifact. The methods may further include filtering the time-space waveforms to generate a plurality of filtered time-space waveforms.

Abstract: Examples of methods and systems are disclosed. The methods may include obtaining a seismic data regarding a subsurface region of interest, wherein the seismic data comprises a plurality of time-space waveforms. The methods may also include obtaining a seismic velocity model. The methods may further include determining a migrated seismic image based on the plurality of time-space waveforms and the seismic velocity model. The method may still further include generating a filtered seismic image by applying a depth-dependent attenuation operator to the migrated seismic image and determining a drilling target in the subsurface region based on the filtered seismic image.

Abstract: Techniques for determining an uptake capacity of a core sample include measuring a nuclear magnetic resonance (NMR) spectrum signal of a test fluid at a particular pressure and entrained in a core sample enclosed in a test cylinder of an NMR pressure cell such that an annulus is defined between the core sample and the test cylinder; deconvolving the NMR spectrum signal into a first NMR spectrum signal portion that is associated with a first portion of the test fluid in the annulus and a second NMR spectrum signal portion that is associated with a second portion of the test fluid entrained in the core sample; and determining a mass of the second portion of the test fluid based at least in part on the first and second NMR spectrum signals.

Abstract: A method and system for determining a mass of an absorbed gas and a mass of a pore gas in a sample using NMR spectroscopy is provided. The method includes acquiring a baseline NMR spectrum of a pressure cell containing the sample, saturating the sample with a gas, acquiring a saturated NMR spectrum and determining a differential NMR spectrum of the sample by subtracting the baseline NMR spectrum from the saturated NMR spectrum. The method also includes separating the differential NMR spectrum into an absorbed gas NMR spectrum to determine an absorbed gas NMR signal and a pore gas NMR spectrum to determine a pore gas NMR signal by performing a spectral deconvolution. The method further includes acquiring a normalization NMR spectrum of the pressure cell containing a gas to determine a gas calibration NMR signal and determining the mass of the absorbed gas and pore gas.

Abstract: Techniques for determining an uptake capacity of a core sample include measuring a nuclear magnetic resonance (NMR) spectrum signal of a test fluid at a particular pressure and entrained in a core sample enclosed in a test cylinder of an NMR pressure cell such that an annulus is defined between the core sample and the test cylinder; deconvolving the NMR spectrum signal into a first NMR spectrum signal portion that is associated with a first portion of the test fluid in the annulus and a second NMR spectrum signal portion that is associated with a second portion of the test fluid entrained in the core sample; and determining a mass of the second portion of the test fluid based at least in part on the first and second NMR spectrum signals.

Abstract: A method and system for determining a mass of an absorbed gas and a mass of a pore gas in a sample using NMR spectroscopy is provided. The method includes acquiring a baseline NMR spectrum of a pressure cell containing the sample, saturating the sample with a gas, acquiring a saturated NMR spectrum and determining a differential NMR spectrum of the sample by subtracting the baseline NMR spectrum from the saturated NMR spectrum. The method also includes separating the differential NMR spectrum into an absorbed gas NMR spectrum to determine an absorbed gas NMR signal and a pore gas NMR spectrum to determine a pore gas NMR signal by performing a spectral deconvolution. The method further includes acquiring a normalization NMR spectrum of the pressure cell containing a gas to determine a gas calibration NMR signal and determining the mass of the absorbed gas and pore gas.

Abstract: A method may include obtaining, using a gamma-ray detector, first acquired gamma-ray data regarding a first core sample. The first acquired gamma-ray data may correspond to various sensor steps. The method may further include determining a sensitivity map based on the first acquired gamma-ray data. The method may further include obtaining, using the gamma-ray detector, second acquired gamma-ray data regarding a second core sample at the sensor steps. The method further includes generating a gamma-ray log using the sensitivity map and a gamma-ray inversion process.

Abstract: A method for determining maximum recoverable hydrocarbon (EMR) in a tight reservoir is disclosed. The method includes determining, based on downhole logs, a total measure of hydrocarbon amount within the tight reservoir, determining, by at least attributing fluid loss during core surfacing of the core sample to hydrocarbons, a non-recoverable measure of hydrocarbon amount within a core sample of the tight reservoir, and determining an EMR measure based on the total measure of hydrocarbon amount and the non-recoverable measure of hydrocarbon amount, wherein during the core surfacing pore pressure reduces from a reservoir condition to a surface condition.

Abstract: A method may include obtaining, using a gamma-ray detector, first acquired gamma-ray data regarding a first core sample. The first acquired gamma-ray data may correspond to various sensor steps. The method may further include determining a sensitivity map based on the first acquired gamma-ray data. The method may further include obtaining, using the gamma-ray detector, second acquired gamma-ray data regarding a second core sample at the sensor steps. The method further includes generating a gamma-ray log using the sensitivity map and a gamma-ray inversion process.

Abstract: A method for determining maximum recoverable hydrocarbon (EMR) in a tight reservoir is disclosed. The method includes determining, based on downhole logs, a total measure of hydrocarbon amount within the tight reservoir, determining, by at least attributing fluid loss during core surfacing of the core sample to hydrocarbons, a non-recoverable measure of hydrocarbon amount within a core sample of the tight reservoir, and determining an EMR measure based on the total measure of hydrocarbon amount and the non-recoverable measure of hydrocarbon amount, wherein during the core surfacing pore pressure reduces from a reservoir condition to a surface condition.

Abstract: In an example implementation, first seismic energy is generated using first seismic sources positioned on an earth's surface. First data including measurements of the first seismic energy is obtained from first geophones positioned at a first depth below the earth's surface. Second data including measurements of the first seismic energy is obtained from second geophones positioned on the earth's surface. Second seismic energy is generated using second seismic sources positioned on an earth's surface and proximal to the second geophones. Third data including measurements of the second seismic energy is obtained from third geophones positioned at the first depth below the earth's surface. A propagation of the first seismic energy along a first path is estimated based on the first, second and third data. One or more characteristics of the target are determined based on the estimate.

Abstract: In a general implementation, systems, apparatus, and methods for AVO of imaging condition in ERTM include the described system provides for an efficient and accurate vector wavefield decomposition with a corresponding modified dot-product imaging condition of ERTM by employing a modified AVO algorithm. In some implementations, the phases of source wavelet and multicomponent records are modified using a 1/?2 filter and the amplitudes of the extrapolated wavefields are scaled using ?2 and ?2, where ?, ? and ? are the angular frequency, local P- and S-wave velocities, respectively. The results yield correct phases, amplitudes, and physical units for separated P- and S-mode wavefields. Divergence and curl operators may then be applied to the phase-corrected and amplitude-scaled elastic wavefields to extract vector P- and S-wavefields. With the separated vector wavefields, a modified dot-product imaging condition can be employed to produce PP and PS reflectivity images.

Abstract: In an example implementation, first seismic energy is generated using first seismic sources positioned on an earth's surface. First data including measurements of the first seismic energy is obtained from first geophones positioned at a first depth below the earth's surface. Second data including measurements of the first seismic energy is obtained from second geophones positioned on the earth's surface. Second seismic energy is generated using second seismic sources positioned on an earth's surface and proximal to the second geophones. Third data including measurements of the second seismic energy is obtained from third geophones positioned at the first depth below the earth's surface. A propagation of the first seismic energy along a first path is estimated based on the first, second and third data. One or more characteristics of the target are determined based on the estimate.

Abstract: Innovative aspects of the subject matter described in this specification may be embodied in methods that include obtaining a seismic data image. A first plane-wave destruction filter dip estimation is applied to the seismic data image to generate an initial dip model. A second plane-wave destruction filter dip estimation is applied to the seismic data image using the initial dip model to generate a pattern-guided dip estimation. The pattern-guided dip estimation is stored in a data store.

Abstract: In a general implementation, systems, apparatus, and methods for AVO of imaging condition in ERTM include the described system provides for an efficient and accurate vector wavefield decomposition with a corresponding modified dot-product imaging condition of ERTM by employing a modified AVO algorithm. In some implementations, the phases of source wavelet and multicomponent records are modified using a 1/?2 filter and the amplitudes of the extrapolated wavefields are scaled using ?2 and ?2, where ?, ? and ? are the angular frequency, local P- and S-wave velocities, respectively. The results yield correct phases, amplitudes, and physical units for separated P- and S-mode wavefields. Divergence and curl operators may then be applied to the phase-corrected and amplitude-scaled elastic wavefields to extract vector P- and S-wavefields. With the separated vector wavefields, a modified dot-product imaging condition can be employed to produce PP and PS reflectivity images.

Abstract: The present invention provides a method and system for distributed residual tomographic velocity analysis using dense residual depth difference maps. Prestack seismic imaging is performed using an initial velocity field and interpreted horizons. A residual depth difference is estimated referenced to fixed offset and all horizons. Residual depth difference maps are computed for each offset and each horizon. The residual depth difference maps are back projected to determine slowness perturbation. The initial velocity model may be converted to slowness and the estimated slowness is composited therewith to produce a new slowness volume. The new slowness volume is converted to a new velocity volume for performing prestack seismic imaging. This process is repeated until the slowness perturbation is negligible or reaches a predetermined threshold.