A method for determining a thermal maturity image of a subterranean region and a non-transitory computer readable medium, storing instructions for executing the method, are disclosed. The method includes, obtaining a seismic dataset for the subterranean region of interest, obtaining a thermal maturity value for a plurality of core samples taken from different positions within the subterranean region, and obtaining a plurality of well log types from the core sampling location. The method further includes determining a calibrated rock physics model based on the plurality of well log types, determining a pore fluid type based on the calibrated rock physics model, and determining a thermal maturity model based on the plurality of core samples, on the pore fluid type, and on the plurality of well logs. The method still further includes determining the thermal maturity image of the subterranean region based on the seismic dataset and thermal maturity model.

A method of generating a four dimensional seismic signal based on multiple sets of seismic data representing a subterranean formation. The method can include generating a tomographic velocity model based on a first set of raw seismic data and determining at least one Green's function based on the tomographic velocity model. The method can include generating a first image of a target region based on the first set of raw seismic data and the at least one Green's function. The method can include generating a second image of the target region based on a second set of raw seismic data and the at least one Green's function. The first and the second images can be compared, and a four-dimensional seismic signal can be determined based on the comparison.

A method is described for data analytics including receiving a dataset representative of a subsurface volume of interest; identifying at least two features in the dataset; performing optimization methods to fit the at least two features to a response variable; calculating partial dependency functions of the at least two features; calculating a simplicity of each of the partial dependency functions; calculating an importance of each of the at least two features; selecting at least one highly ranked feature based on a combination of the simplicity and the importance; and performing optimization methods to fit the at least one highly ranked feature to a response variable. The method may be executed by a computer system.

Receiver-consistent scalars of seismic receiver channels are used for time-lapse monitoring of a sub-surface earth formation. Signals are induced by seismic waves propagating through the earth formation adjacent to each respective seismic receiver channel. Each seismic receiver channel is acoustically coupled to the earth formation as present directly adjacent to the location of the seismic receiver channel in question. The base receiver-consistent scalars and the monitor receiver-consistent scalars of seismic receiver channels can be outputted to reveal changes in these receiver-consistent scalars. These changes can be used to delineate information about physical changes in the subsurface earth formation. The changes in the based receiver-consistent scalars and the monitor receiver-consistent scalars may be displayed visually.

The present disclosure describes a computer-implemented method that includes: receiving a seismic dataset of a surveyed subsurface of a reservoir, the seismic dataset comprising observed pressure and production data of the reservoir as well as a set of geological and geo-mechanical parameters representing physical features of the surveyed subsurface; generating multiple realizations of a discrete fracture network (DFN) based on a subset of the set of geological and geo-mechanical parameters; selecting, from the multiple realizations, one or more realizations based on a parameter with a value under a 10% quantile of a full range of likely values; performing a forward simulation for the reservoir based on the selected one or more realizations and the observed pressure and production data; determining that a misfit of the forward simulation is below a threshold based on evaluating an objective function; and producing a model of the reservoir based on the forward simulation.

A method for conducting a seismic survey for collecting seismic data off shore. It comprises a first seismic survey providing a first set of data for an area using individual seismic sub-source arrays (2). It further comprises a second seismic survey of the same area for providing a second set of data. The individual seismic sub-source arrays (2) are similar to the sub-source arrays used during the former survey and are arranged in more than two shot-unit sources (3). Each shot-unit source (3) comprises a pair of neighboring individual seismic sub-source arrays (2) arranged to be fired substantially at the same time.

Common transmission points can be used to monitor a seismic reservoir. First and second common transmission points (CTPs) are received. For each of the first CTP gather and the second CTP gather, the traces before the CTP can be aggregated, and the traces crossing the CTP can be aggregates. The aggregated before CTP traces from the first CTP gather can be compared with the aggregated before CTP traces from the second CTP gather to determine a first time difference. The aggregated cross CTP traces from the first CTP gather can be compared with the aggregated cross CTP traces from the second CTP gather to determine a second time difference. A third time difference can be determined based at least partially on the first time difference and the second time difference.

A multivariate analysis may be used to correlate seismic attributes for a subterranean formation with petrophysical properties of the subterranean formation and/or microseismic data associated with treating, creating, and/or extending a fracture network of the subterranean formation. For example, a method may involve modeling petrophysical properties of a subterranean formation, microseismic data associated with treating a complex fracture network in the subterranean formation, or a combination thereof with a mathematical model based on measured data, microseismic data, completion and treatment data, or a combination thereof to produce a petrophysical property map, a microseismic data map, or a combination thereof; and correlating a seismic attribute map with the petrophysical property map, the microseismic data map, or the combination thereof using the mathematical model to produce at least one quantified correlation, wherein the seismic attribute map is a seismic attributed modeled for the complex fracture network.

A method of determining fracture complexity may comprise receiving one or more signal inputs from a fracturing operation, calculating an observed fracture growth rate based at least partially on the one or more signal inputs, calculating a predicted fracture growth rate, determining a fracture complexity value, and applying a control technique to make adjustments a hydraulic stimulation operation based at least in part on the fracture complexity value. Also provided is a system for determining a fracture complexity for a hydraulic fracturing operation may comprise a hydraulic fracturing system, a sensor unit to receive one or more signal inputs, a calculating unit, a fracture complexity unit, and a controller unit to apply a control technique to adjust one or more hydraulic stimulation parameters on the hydraulic fracturing system.

A method for evaluating a wellbore treatment includes inducing an acoustic wave in the wellbore prior to treatment. Acoustic energy propagating as pressure waves in the wellbore is detected. A formation in fluid communication with the wellbore is treated. The inducing an acoustic wave and detecting acoustic energy are repeated. A characteristic of the treatment is determined based on differences between the detected acoustic energy prior to the treating and at the end of the treating. In some embodiments, the observed differences are then also compared to differences observed in prior treatment stages to assess benefit of changes to treatment design. In some embodiments, the treatment design parameters are continuously iterated, adjusted, and improved to maximize the contribution to production of all subsequent stages in same or any other well.