Exxonmobil Upstream Research Company

Exxonmobil Technology and Engineering Company

Brent D Wheelock

Mehmet Deniz Ertas

Harry William Deckman

Lang Feng

Qiuzi Li

Limin Song

Yibing Zhang

Xinyou Lu

Huseyin Denli

Peter A Gordon

David A Howell

Jan Schmedes

Ratnanabha Sain

Dezhi Chu

Kenneth W Desmond

Joseph W Witt

David D McAdow

Xin Zhan

John E Bishop

Harry J Deckman

Methods and systems for measuring cluster efficiency for stages of wellbores are provided herein. One method includes selecting a frequency band for generating broadband tube waves within the fluid column of the wellbore and generating the broadband tube waves within the fluid column of the wellbore using a pressure pulse generator that is hydraulically coupled to the wellbore. The method also includes recording data corresponding to the broadband tube waves and reflected broadband tube waves using pressure receivers that are hydraulically coupled to the wellbore. The pressure receivers are arranged into arrays with two or more pressure receivers in each array. The data recorded by the pressure receivers relate to characteristics of reflectors (including perforation cluster/fracture interfaces) within the wellbore. The method further includes processing the recorded data using interferometry and performing full waveform inversion(s) on the processed data to determine frequency-dependent, complex-valued reflection coefficients at each perforation cluster/fracture interface.

Systems and methods for measuring cluster efficiency using broadband tube waves

Embodiments of an invention disclosed herein relate to methods for performing formation evaluation of a formation or formation's surrounding to identify and characterize the abundance and morphology of non-ionic conductor grains, 'c-grains', within the formations that are evaluated by formation evaluation (FE) tools. The methods and related systems as disclosed herein are directed to correcting any existing FE logs that can be adversely affected by the presence of c-grains in the detection volume of FE tools, and/or obtaining new FE information that is unavailable by the application of existing FE methods.

Methods for performing formation evaluation and related systems

A method and apparatus for modeling a subsurface region, including: obtaining a training set of geologically plausible models for the subsurface region; training an autoencoder with the training set; extracting a decoder from the trained autoencoder, wherein the decoder comprises a geologic-model-generating function; using the decoder within a data-fitting objective function to replace output-space variables of the decoder with latent-space variables, wherein a dimensionality of the output-space variables is greater than a dimensionality of the latent-space variables; and performing an inversion by identifying one or more minima of the data-fitting objective function to generate a set of prospective latent-space models for the subsurface region; and using the decoder to convert each of the prospective latent-space models to a respective output-space model. A method and apparatus for making one or more hydrocarbon management decisions based on the estimated uncertainty.

Subsurface models with uncertainty quantification

A method and apparatus for identifying non-elastic indicators for a subsurface region, the method including obtaining seismic data for the subsurface region; generating a best-fit elastic model from the seismic data; and identifying non-elastic indicators from the seismic data and the best-fit elastic model. The method and apparatus may also include estimating reservoir flow properties from the non-elastic indicators based on a poroelastic interpretation of the seismic response. The method and apparatus may also include subdividing the seismic data into a plurality of subdivisions, wherein: generating the best-fit elastic model from the seismic data includes generating an individual best-fit elastic model for each subdivision; identifying non-elastic indicators from the seismic data and the best-fit elastic model includes identifying individual non-elastic indicators from each subdivision and its respective individual best-fit elastic model; and estimating the reservoir flow properties from the non-elastic indicators comprises analyzing the individual non-elastic indicators based on the subdivisions.

Estimation of reservoir flow properties from seismic data

A method including: obtaining geophysical data for a subsurface region; generating, with a computer, at least two subsurface property models of the subsurface region for at least two subsurface properties by performing an inversion that minimizes a misfit between the geophysical data and forward simulated data subject to one or more constraints, the inversion including generating updates to the at least two subsurface property models for at least two different scenarios that both fit the geophysical data with a same likelihood but have different values for model materiality, with the model materiality being posed as an equality constraint in the inversion, wherein the model materiality is a functional of model parameters that characterize hydrocarbon potential of the subsurface region; analyzing a geophysical data misfit curve or geophysical data misfit likelihood curve, over a predetermined range of values of the model materiality to identify the at least two subsurface property models that correspond to a high-side and low-side, respectively, for each of the at least two subsurface properties, with the high-side and low-side quantifying uncertainties in the subsurface properties; and prospecting for hydrocarbons in the subsurface region with the at least two models that correspond to the high-side and the low-side for each of the at least two subsurface properties.

Reservoir materiality bounds from seismic inversion

A method for inversion of 4D seismic data, including: determining time shift between baseline and monitor geophysical datasets; determining time strain from the time shift; iteratively repeating until a stopping criteria is satisfied, performing an iterative elastic AVO inversion with a 4D difference providing an update, from an initial model including the time strain, to generate an updated time strain and an updated physical property model, wherein the stopping criteria is a misfit between synthetic data generated from the updated physical property model and the 4D difference being within a predetermined noise level generating final values for the physical property model; and converting, with a rock physics model or a reservoir simulation model, the final values to saturation and/or pressure changes for a subsurface region.

4D time shift and amplitude joint inversion for obtaining quantitative saturation and pressure separation

Hydrocarbon wells and methods for identifying production from a region of a subterranean formation. The hydrocarbon wells include a wellbore extending within the region of the subterranean formation and a production tubular that defines a production conduit and extends at least partially within the wellbore. The hydrocarbon wells also include an electromagnetic transmitter, an electromagnetic receiver, and a controller. The electromagnetic transmitter is configured to provide an input electromagnetic signal to a region of the production conduit to electromagnetically excite a produced tracer material that forms a portion of a produced stream that flows within the production tubular. The electromagnetic receiver is configured to receive an electromagnetic output signal from the region of the production conduit. The controller is programmed to identify the region of the subterranean formation based, at least in part, on the output electromagnetic signal. The methods include methods of operating the hydrocarbon wells.

Hydrocarbon wells and methods for identifying production from a region of a subterranean formation

Methods of determining a spatial distribution of an injected tracer material within a subterranean formation are disclosed, including flowing the tracer material, which includes a tracer electrical capacitance that differs from a formation electrical capacitance of a region of the subterranean formation, into the region of the subterranean formation via a wellbore. Subsequent to the flowing, the methods also include providing an input electromagnetic signal to the region of the subterranean formation. Responsive to the providing, the methods further include receiving an output electromagnetic signal from the subterranean formation. The methods further include determining the spatial distribution of the tracer material within the subterranean formation based, at least in part, on the output electromagnetic signal.

Methods of determining a spatial distribution of an injected tracer material within a subterranean formation

A method including: generating an updated subsurface property model of a subsurface region, with a computer, from an initial estimate of the subsurface property model by performing an iterative inversion, which includes inverting geophysical data to infer the updated subsurface property model, wherein the generating the updated subsurface property model includes linearly remapping the initial estimate of the subsurface property model based on an inverse of a regularization operator, included with the initial estimate of the subsurface property model, into one in which the regularization operator is represented by an identity matrix, performing a unitary matrix decomposition in order to group the identity matrix with sparse matrices output from the unitary matrix decomposition, and performing a search over at least one trade-off parameter to reduce a misfit between simulated data generated from a most recent estimate of the subsurface property model and the geophysical data until a predetermined stopping criteria is satisfied; and generating, with a computer, an image of the subsurface region using the updated subsurface property model.

Accelerated Occam inversion using model remapping and Jacobian matrix decomposition

Method for semi-airborne electromagnetic prospecting for hydrocarbons or other fluids or minerals. In the method, electromagnetic receivers are deployed on the Earth's surface over a subsurface region (). An airborne electromagnetic transmitter is flown over the receivers () and the receivers record at least one component of electromagnetic field data excited by the transmitter (). The recorded electromagnetic data are analyzed for subsurface resistivity (), and the resistivity is interpreted for evidence of hydrocarbons or other fluids or minerals (). Compared to traditional fully airborne surveys, the advantages of the method include better signal-to-noise, and data for multiple source-receiver offsets.

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Houston, TX, United States of America

Brent D Wheelock