Exxonmobil Upstream Research Company

Exxon Production Research Company

Jerome R Krebs

Sunwoong Lee

John E Anderson

Ramesh Neelamani

Partha Sarathi Routh

David L Hinkley

Thomas A Dickens

Young Ho Cha

Anatoly I Baumstein

Spyridon K Lazaratos

Lorie K Bear

Christine E Krohn

Charlie Jing

Carey M Marcinkovich

Peter Traynin

Pavel Dimitrov

Warren S Ross

Sen-Tsuen Chen

Anoop A Mullur

Volkan Akcelik

Jonathan Liu

Nathan Downey

Gopalkrishna Palacharla

Charles Jing

Spyridon Lazaratos

Spyridon Lazarato

A method, including: storing, in a computer storage device, geophysical seismic data that has been separated into a multiple-free component and a multiple contaminated component; performing, with a processor, a first full wavefield inversion process on the multiple-free component of the seismic data, wherein a first subsurface physical property model is generated; determining, with a processor, an extended target reflectivity, wherein the extended target reflectivity includes a reflectivity for each of a plurality of shots; separately performing, with a processor, a second full wavefield inversion process with the multiple contaminated component of the seismic data for each of the plurality of shots using the reflectivity corresponding to each of the plurality of shots, wherein a second subsurface physical property model is generated; and generating, with a processor, multiple-free final subsurface physical property model by combining the first subsurface physical property model and the second subsurface physical property model.

Method for generating multiple free seismic images

Method for performing simultaneous encoded-source inversion of geophysical data to estimate parameters of a physical property model (), especially adapted for surveys without fixed-receiver acquisition geometry, such as marine seismic surveys with moving source and receivers. The encoding functions () used on the sources to generate one or more simultaneous encoded-source gathers of data (), as well as to simulate the same (), are orthogonal or pseudo-orthogonal with respect to cross-correlation. In addition, receivers are also encoded, with the receiver encoding being designed to make a given receiver less sensitive to sources to which it was not listening during the survey (). The encoding functions may be temporal bandpass filters differing one from another by central frequency, phase, or both. Efficiency of the method may be further improved by grouping several sources into a super-source, grouping the corresponding gathers into a super-gather, and then applying the above encoding strategy.

Orthogonal source and receiver encoding

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

Artifact reduction in iterative inversion of geophysical data

The invention includes a method for reducing noise in migration of seismic data, particularly advantageous for imaging by simultaneous encoded source reverse-time migration (SS-RTM). One example embodiment includes the steps of obtaining a plurality of initial subsurface images; decomposing each of the initial subsurface images into components; identifying a set of components comprising one of (i) components having at least one substantially similar characteristic across the plurality of initial subsurface images, and (ii) components having substantially dissimilar characteristics across the plurality of initial subsurface images; and generating an enhanced subsurface image using the identified set of components. For SS-RTM, each of the initial subsurface images is generated by migrating several sources simultaneously using a unique random set of encoding functions. Another embodiment of the invention uses SS-RTM for velocity model building.

Seismic data processing

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

A method for efficient inversion of measured geophysical data from a subsurface region to prospect for hydrocarbons. Gathers of measured data () are encoded () using a set of non-equivalent encoding functions (). Then all data records in each encoded gather that correspond to a single receiver are summed (), repeating for each receiver to generate a simultaneous encoded gather (). The method employs iterative, local optimization of a cost function to invert the encoded gathers of simultaneous source data. An adjoint method is used to calculate the gradients of the cost function needed for the local optimization process (). The inverted data yields a physical properties model () of the subsurface region that, after iterative updating, can indicate presence of accumulations of hydrocarbons.

Efficient method for inversion of geophysical data

Method for simultaneous full-wavefield inversion of gathers of source (or receiver) encoded geophysical data to determine a physical properties model () for a subsurface region, especially suitable for surveys where fixed receiver geometry conditions were not satisfied in the data acquisition. Simultaneous source separation () is performed to lessen any effect of the measured geophysical data's not satisfying the fixed-receiver assumption. A data processing step () coming after the simultaneous source separation acts to conform model-simulated data () to the measured geophysical data () for source and receiver combinations that are missing in the measured geophysical data.

Simultaneous source encoding and source separation as a practical solution for full wavefield inversion

Method for simultaneous full-wavefield inversion of gathers of source (or receiver) encoded () geophysical data () to determine a physical properties model () for a subsurface region, especially suitable for surveys where fixed-receiver geometry conditions were not satisfied in the data acquisition (). The inversion involves optimization of a cross-correlation objective function ().

Simultaneous source inversion for marine streamer data with cross-correlation objective function

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

Method for simultaneous full-wavefield inversion of gathers of source (or receiver) encoded geophysical data to determine a physical properties model for a subsurface region, especially suitable for surveys where fixed receiver geometry conditions were not satisfied in the data acquisition. First, a shallow time window of the data () where the fixed receiver condition is satisfied is inverted by simultaneous encoded () source inversion (). Then, the deeper time window of the data () is inverted by sparse sequential source inversion (), using the physical properties model from the shallow time window () as a starting model (). Alternatively, the shallow time window model is used to simulate missing far offset data () producing a data set satisfying the stationary receiver assumption, after which this data set is source encoded () and inverted by simultaneous source inversion ().

Hybrid method for full waveform inversion using simultaneous and sequential source method

An improved method for reducing the accuracy requirements on the starting model when performing multi-scale inversion of seismic data () by local objective function optimization (). The different scales of inversion are brought about by incorporating a low-pass filter into the objective function (), and then decreasing the amount of high-frequency data that is filtered out from one scale to the next. Moreover, the filter is designed to be time varying, wherein the filter's low-pass cutoff frequency decreases with increasing traveltime of the seismic data being filtered (). The filter may be designed using Pratt's criterion for eliminating local minima, and performing averages (or other statistical measure) of the period and the traveltime error only with respect to source and receiver location but not traveltime ().

Full wavefield inversion using time varying filters

Method for updating a velocity model () for migrating seismic data using migration velocity scans with the objective of building a model that reproduces the same travel times that produced selected optimal images from a scan. For each optimal pick location () in the corresponding test velocity model (), a corresponding location is determined () in the velocity model to be updated, using a criterion that the travel time to the surface for a zero offset ray () should be the same. Imaging travel times are then computed from the determined location to various surface locations in the update model (), and those times are compared to travel times in the test velocity model from the optimal pick location to the same array of surface locations. The updating process consists of adjusting the model to minimize the travel time differences ().

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Houston, TX, United States of America

Jerome R Krebs