Exxonmobil Upstream Research Company

Exxon Production Research Company

Thomas A Dickens

Dennis E Willen

Charlie Jing

John E Anderson

Jerome R Krebs

Ramesh Neelamani

David L Hinkley

Anatoly I Baumstein

Christine E Krohn

Partha Sarathi Routh

Yaxun Tang

William Curry

Tetyana Vdovina

Peter Traynin

William A Burnett

Graham A Winbow

William A Schneider

Pavel Dimitrov

Xinyou Lu

Warren S Ross

Rebecca L Saltzer

Anoop A Mullur

Carey M Marcinkovich

Valeriy V Brytik

Martin J Terrell

Sirui Tan

Gboyega Ayeni

Andrew P Shatilo

Jim J Carazzone

Eva-Maria Rumpfhuber

Charles Jing

Gopalkrishna Palacharla

A method, including: determining, with a computer, point spread functions for a plurality of parameter locations by performing at least a portion of a first iteration of an iterative full wavefield inversion process; determining at least one property for each of the point spread functions; and evaluating a candidate survey design based on the at least one property for each of the point spread functions.

Method to design geophysical surveys using full wavefield inversion point- spread function analysis

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

A method for iteratively inverting seismic data to jointly infer a model for at least P-wave velocity and attenuation parameters of the subsurface, the method including: jointly inverting the P-wave velocity and attenuation parameters with an iterative visco-acoustic full wavefield inversion process, wherein the iterative visco-acoustic full wavefield inversion process includes computing a gradient of an objective function, the objective function measuring a misfit between all or part of the seismic data and corresponding model-simulated seismic data; for each of the P-wave velocity and attenuation parameters, computing a search direction in model space from the gradient; determining line search step sizes &#x3b1; and &#x3b2; for the search directions for the P-wave velocity and attenuation parameters, respectively, wherein a ratio of the step sizes is a function of the P-wave velocity parameter; and using the step sizes &#x3b1; and &#x3b2; and the search directions for each of the P-wave velocity and attenuation parameters, computing a new search direction in model space, then performing a line search along the new search direction to arrive at a new step size, and using the new step size and the new search direction to generate an updated model for a current iteration of the iterative visco-acoustic full wavefield inversion process.

Joint full wavefield inversion of P-wave velocity and attenuation using an efficient first order optimization

Method for rapidly computing updates to frequency-domain seismic wave fields by utilizing a matrix perturbation approach. The method speeds up model (e.g., velocity) parameter estimation by iterative inversion of measured seismic data. The method applies to the line search where the optimal size of the model update is estimated by testing different size updates to see which one generates the minimum objective function. By treating the model update as a perturbation, perturbation theory is used to relate the model perturbation to a corresponding wavefield perturbation. Thus, the Helmholtz equation is solved only once per iteration cycle.

Method for fast line search in frequency domain FWI

In the present inventive method, individual traces of seismic data are migrated () without any assembling of different midpoints or any summing of different offsets, so that post-migration processing or analysis, e.g. trace alignment, may be applied to the individual migrated traces () to compensate for any deficiencies among them, before stack and assembly. Thus, the present invention fully separates the steps of migration (), assembly (), and stacking (), which are combined together in traditional migration. Thus, imaging deficiencies can be measured and addressed in the image space before they are obscured by summation. Afterward, summation can proceed to construct the improved final image ().

Creating seismic images using expanded image gathers

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

Embodiments described herein use stochastic inversion () in lower dimensions to form an initial model () that is to be used in higher-dimensional gradient-based inversion (). For example, an initial model may be formed from 1.5-D stochastic inversions, which is then processed () to form a 3-D model. Stochastic inversions reduce or avoid local minima and may provide an initial result that is near the global minimum.

Constructing resistivity models from stochastic inversion

Method for efficient computation of wave equation migration angle gathers by using multiple imaging conditions. Common reflection angle or common azimuth gathers or gathers including both common reflection angles and common azimuth angles are produced as the data are migrated. In the course of either wave equation migration or reverse time migration, the pressures and particle motion velocities that need to be computed are sufficient to also compute the Poynting vector pointing in the direction of source-side () or receiver-side () wavefield propagation. From that, the reflection and azimuth angles can be computed (). The seismic images can then be stored in the appropriate angle bins, from which common reflection angle or azimuth data volumes can be assembled ().

Efficient computation of wave equation migration angle gathers

Method for using seismic data from earthquakes to address the low frequency lacuna problem in traditional hydrocarbon exploration methods. Seismometers with frequency response down to about 1 Hz are placed over a target subsurface region in an array with spacing suitable for hydrocarbon exploration (). Data are collected over a long (weeks or months) time period (). Segments of the data () are identified with known events from earthquake catalogs (). Those data segments are analyzed using techniques such as traveltime delay measurements () or receiver function calculations () and then are combined with one or more other types of geophysical data acquired from the target region, using joint inversion (-) in some embodiments of the method, to infer physical features of the subsurface indicative of hydrocarbon potential or lack thereof ().

Hydrocarbon detection with passive seismic data

A method for suppressing measurement system signature, or artifacts, that arise when controlled source electromagnetic survey data are inverted to obtain a resistivity image of a subsurface region. The method involves identifying regions () where the image has low or rapidly varying sensitivity to data acquired by a given receiver, typically regions close to and under the given receiver. Then, in the iterative inversion process where a resistivity model is updated to minimize an objective function, the model update is modified () to reduce the impact of such low sensitivity regions on the update.

Inversion of CSEM data with measurement system signature suppression

Method for identifying, determining and correcting source-related phase errors in data from a controlled source electromagnetic survey by using data from ordinary survey receivers, i.e. without benefit of source monitoring data. Abrupt anomalies indicating source malfunctions are identified () in the time domain by plotting time intervals between neighboring zero crossings or by zero-lag cross correlation between consecutive bins of receiver data, and the amount of the time error () can be determined by performing cross correlation between two bins on either side of an anomaly. In the frequency domain, transmitter anomalies can be identified by looking for discontinuities in plots of phase vs. offset, and the corrective phase shift can be determined by matching the phase on one side of the anomaly to that on the other side. A global time/phase shift () can be determined by using phase frequency-scaling behavior at near offsets.

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Houston, TX, United States of America

Thomas A Dickens