Exxonmobil Upstream Research Company

Phillips Petroleum Company

The Goodyear & Tire Rubber Company

Chevron Phillips Chemical Company LP

John E Anderson

Jerome R Krebs

Ramesh Neelamani

Christine E Krohn

Charlie Jing

Thomas A Dickens

David L Hinkley

Anatoly I Baumstein

Carey M Marcinkovich

Valeriy V Brytik

Robert H Kallenberger

Max Deffenbaugh

Sunwoong Lee

Tetyana Vdovina

Peter Traynin

Jerry Krebs

Gary L Funk

George Michael Stoila

Michael W Norris

Marshall D Bishop

Partha Sarathi Routh

Michael James Hogan

Ward J Burkholder

Young Ho Cha

Rongrong Lu

William Curry

Norman C Allegar

Sirui Tan

Gboyega Ayeni

Hong Zhao

Frank E Evans

Lijian Tan

Jia Yan

Mohamed T Hadidi

Simon Dewing

Ernest G Hildenbrand

Jason Shaw

Haiyang Wang

Charles Jing

Willie P Reneau

A method and apparatus for identifying features of a subsurface region, including: obtaining an initial physical property model and survey data for the subsurface region; identifying a current model to be the initial physical property model; and executing one or more iterations of: generating synthetic data and forward wavefields with the current model and the survey data by forward modeling with forward wave equations representing isotropic wave-mode-independent attenuation; generating adjoint wavefields with the synthetic data and the survey data by adjoint modeling with adjoint wave equations representing isotropic wave-mode-independent attenuation; computing an objective function gradient with the forward wavefields and the adjoint wavefields by solving gradient equations with the corresponding wave equations representing isotropic wave-mode-independent attenuation; computing a search direction of the objective function; searching for a possible improved model along the search direction; and updating the current model to be the possible improved model.

Inversion, migration, and imaging related to isotropic wave-mode- independent attenuation

A method, including: obtaining initial estimates of a plurality of subsurface parameters; obtaining a recorded wavefield decomposed into a plurality of discrete components; performing, with a computer, a cascaded inversion where the initial estimates of the subsurface parameters are individually updated, wherein each of the subsurface parameters are updated using a different discrete component of the recorded wavefield of the plurality of discrete components; and generating, with the computer, updated subsurface models from the cascaded inversion for each of the subsurface parameters.

Estimating multiple subsurface parameters by cascaded inversion of wavefield components

A method of molding a green tire having a first and second bead area is described herein, wherein the method includes the steps of: inserting a tire clamping device inside a tire bladder and then inserting the tire clamping device and the bladder into the green tire, aligning the outer surfaces of the tire clamping device into engagement with a respective bead area of the tire so that each tire bead area is clamped between a respective upper and a lower mold ring and the tire clamping device during cure. A tire clamping device includes an inner portion, and a plurality of segments connected to the inner portion, wherein the tire clamping device has a closed position wherein the plurality of segments together forms a first and second ring for engagement with the bead areas of the tire so clamp the bead areas between the clamping device and the mold rings during cure.

Tire clamping device

A method for designing 4-D seismic acquisition source and receiver repeatability specifications, the method including: locating, with a computer subsurface anomalies above a target reservoir zone from analysis of high-resolution reflectivity images for the target reservoir zone; determining, with a computer, how the anomalies above the target reservoir zone modify target illumination for variations in the 4-D seismic acquisition source and receiver positions; and determining, with a computer, repeatability specifications for a monitor seismic survey, wherein tolerances for the source or receiver positions varies across an acquisition area based on how the anomalies modify the target illumination.

Method to estimate 4D seismic acquisition repeatability specifications from high-resolution near-water-bottom seismic images

A method for exploring for hydrocarbons, including: simulating a seismic waveform, using a computer, wherein computations are performed on a computational grid representing a subsurface region, said computational grid using perfectly matched layer (PML) boundary conditions that use an energy dissipation operator to minimize non-physical wave reflections at grid boundaries; wherein, in the simulation, the PML boundary conditions are defined to reduce computational instabilities at a boundary by steps including, representing direction of energy propagation by a Poynting vector, and dissipating energy, with the dissipation operator, in a direction of energy propagation instead of in a phase velocity direction; and using the simulated waveform in performing full waveform inversion or reverse time migration of seismic data, and using a physical property model from the inversion or a subsurface image from the migration to explore for hydrocarbons.

Poynting vector minimal reflection boundary conditions

Method for generating an effective, efficient, and stable absorbing boundary condition in finite-difference calculations, such as model-simulation of predicted seismic data. The top surface and optionally the bottom surface of the computational domain or grid are treated with one or more layers of PML (), preferably 1D PML, assuming an orthorhombic medium in the PML implementation (). The side surfaces are handled with one or more ABC layers (). Further advantages may be realized by tapering earth model symmetry axis on the top and bottom of the model toward the vertical (). The invention provides a beneficial compromise between reducing artifacts in the image or physical property model and computational efficiency and stability.

Efficient and stable absorbing boundary condition in finite-difference calculations

A method for generating seismic attribute gathers, the method including: computing, with a computer, seismic images with a field dataset; generating, with a computer, synthetic data corresponding to the seismic images; computing, with a computer, an attribute volume by applying an expectation method to the synthetic data; mapping, with a computer, the attribute volume to the seismic images; and generating, with a computer, seismic attribute gathers by stacking the seismic images mapped to the attribute volume.

Efficient seismic attribute gather generation with data synthesis and expectation method

A method, including: obtaining, with a processor, a seismic image of a subsurface region from a computer memory; predicting, with a processor, a dip of the seismic image of the subsurface region; and removing, with a processor, noise or artifacts from the seismic image of the subsurface region by applying a dip guided Laplacian filter, wherein the removing generates another seismic image of the subsurface region that has noise or artifacts removed relative to the seismic image of the subsurface region.

Method of removing noise in seismic reverse-time migration

Method for correcting seismic simulations, RTM, and FWI for temporal dispersion due to temporal finite difference methods in which time derivatives are approximated to a specified order of approximation. Computer-simulated seismic data () are transformed from time domain to frequency domain (), and then resampled using a mapping relationship that maps, in the frequency domain, to a frequency at which the time derivative exhibits no temporal dispersion (), or to a frequency at which the time derivative exhibits a specified different order of temporal dispersion. Alternatively, measured seismic data from a field survey () may have temporal dispersion of a given order introduced, by a similar technique, to match the order of approximation used to generate simulated data which are to be compared to the measured data.

Method for temporal dispersion correction for seismic simulation, RTM and FWI

A method for obtaining zero-offset and near zero offset seismic data from a marine survey, with separation of direct arrival information and reflectivity information, the method including: modeling a direct arrival estimate at a passive near-field hydrophone array by using a notional source separation on active near-field hydrophone data; generating reflection data for the passive near-field hydrophone array by subtraction of the modeled direct wave from data recorded by the passive near-field hydrophone array; generating near zero-offset reflectivity traces by stacking the reflection data for the passive near-field hydrophone array on a string-by-string basis or on a combination of strings basis.

Method to estimate and remove direct arrivals from arrayed marine sources

Method for reducing the time needed to perform geophysical inversion by using simultaneous encoded sources in the simulation steps of the inversion process. The geophysical survey data are prepared by encoding () a group of source gathers (), using for each gather a different encoding signature selected from a set () of non-equivalent encoding signatures. Then, the encoded gathers are summed () by summing all traces corresponding to the same receiver from each gather, resulting in a simultaneous encoded gather. (Alternatively, the geophysical data are acquired from simultaneously encoded sources.) The simulation steps needed for inversion are then calculated using a particular assumed velocity (or other physical property) model () and simultaneously activated encoded sources using the same encoding scheme used on the measured data. The result is an updated physical properties model () that may be further updated () by additional iterations.

Iterative inversion of data from simultaneous geophysical sources

An additive for a wellbore treatment fluid comprising a sulfonated asphalt compound comprising particles having a D90 particle size of less than about 215 &#x3bc;m. A wellbore treatment fluid comprising (i) an oleaginous component and (ii) a sulfonated asphalt wherein the sulfonated asphalt comprises particles having a D90 of less than about 215 &#x3bc;m.

Additives for oil-based drilling fluids

Method and system for more efficient checkpointing strategy in cross correlating () a forward () and backward () propagated wave such as in migrating () or inverting seismic data. The checkpointing strategy includes storing in memory forward simulation data at a checkpointed time step, wherein the stored data are sufficient to do a cross correlation at that time step but not to restart the forward simulation. At other checkpoints, a greater amount of data sufficient to restart the simulation may be stored in memory (). Methods are disclosed for finding an optimal combination, i.e. one that minimizes computation time (), of the two types of checkpoints for a given amount of computer memory (), and for locating a checkpoint at an optimal time step (). The optimal checkpointing strategy () also may optimize () on use of fast () vs. slow () storage.

Method and system for checkpointing during simulations

Method for converting seismic data to obtain a subsurface model of, for example, bulk modulus or density. The gradient of an objective function is computed () using the seismic data () and a background subsurface medium model (). The source and receiver illuminations are computed in the background model (). The seismic resolution volume is computed using the velocities of the background model (). The gradient is converted into the difference subsurface model parameters () using the source and receiver illumination, seismic resolution volume, and the background subsurface model. These same factors may be used to compensate seismic data migrated by reverse time migration, which can then be related to a subsurface bulk modulus model. For iterative inversion, the difference subsurface model parameters () are used as preconditioned gradients ().

Methods for subsurface parameter estimation in full wavefield inversion and reverse-time migration

The invention discloses a way to recover separated seismograms with reduced interference noise by processing vibroseis data recorded (or computer simulated) with multiple vibrators shaking simultaneously or nearly simultaneously (). A preliminary estimate of the separated seismograms is used to obtain improved seismograms (). The preliminary estimate is convolved with the vibrator signature and then used to update the seismogram. Primary criteria for performing the update include fitting the field data and satisfying typical criteria of noise-free seismograms (). Alternative ways to update are disclosed, including signal extraction, modeled noise extraction, constrained optimization based separation, and penalized least-squares based separation. The method is particularly suited for removing noise caused by separating the combined record into separate records for each vibrator, and is advantageous where the number of sweeps is fewer than the number of vibrators ().

Growing community of inventors

Houston, TX, United States of America

John E Anderson