Techniques for evaluating hydrocarbon reserves using tool response models are provided. An example method includes measuring a first fluid distribution of a first formation proximate to a first wellbore and measuring a second fluid distribution of a second formation proximate to a second wellbore. The method further includes generating a first tool response model for the first formation based at least in part on the first fluid distribution and generating a second tool response model for the second formation based at least in part on the second fluid distribution. The method further includes comparing results of the first tool response model to results of the second tool response model to determine a fluid distribution difference between the first formation and the second formation and implementing a drilling command to alter drilling of one of the first and second wellbores based at least in part on the fluid distribution difference.

Methods and mediums for estimating stimulated reservoir volumes are disclosed. Some method embodiments may include obtaining microseismic event data acquired during a hydraulic fracturing treatment of the formation, the data including event location and at least one additional attribute for each microseismic event within the formation; filtering the microseismic events based on the at least one additional attribute; determining a density of filtered microseismic events; weighting the filtered microseismic events based on the density; and determining a stimulated reservoir volume estimate based on filtered and weighted microseismic events.

A set of reservoir production results are obtained by simulation of hydrocarbons flow in a heterogeneous reservoir based on the values of heterogeneity blocks transport matrices. The transport matrices of the heterogeneity blocks are calculated from a reservoir block hierarchy. The simulation is initiated by a set of foundation blocks transport matrices calculated by evaluating a fluid transport law in the blocks being in the lowest rank of the hierarchy.

The invention notably relates to a computer-implemented method for processing a 4D seismic signal relative to a subsoil, the subsoil including a zone subject to extraction and/or injection, the method comprising: providing the 4D seismic signal; identifying a part of the 4D seismic signal corresponding to a zone of the subsoil distinct from the zone subject to extraction and/or injection; determining a noise model of the 4D seismic signal based on the identified part of the 4D seismic signal; and processing the 4D seismic signal based on the noise model. This improves the field of 4D seismic data processing.

Exemplary implementations may: obtain, from the electronic storage, geological data corresponding to the geographic volume of interest; generate a framework for sediment deposition using a first set of multiple physical, chemical, biological, and geological processes; generate a framework for diagenesis using a second set of multiple physical, chemical, biological, and geological processes; generate a representation of sediment deposition by applying the geological data corresponding to the geographic volume of interest to the framework for sediment deposition; generate a representation of diagenesis based on the framework for diagenesis and the representation of sediment deposition; and display the representation of sediment deposition and the representation of diagenesis on a graphical user interface.

A method is described for time-lapse seismic imaging that may include detecting moir patterns in seismic images generated from time-lapse seismic data and identifying geologic features based on the moir patterns. The method may be executed by a computer system.

A method of characterizing a subterranean formation using a plurality of seismic acquisitions includes obtaining a first seismic acquisition of the subterranean formation, wherein the first seismic acquisition is a baseline survey. Injecting a gas fluid into the subterranean formation, wherein the gas fluid at least partially fills a portion of a fracture network of the subterranean formation. Obtaining a second seismic acquisition of the subterranean formation. Calculating a time-lapse difference in the plurality of seismic acquisitions.

Disclosed is a method for characterizing the evolution of a reservoir by determining a seismic wavelet which links observed seismic data to a sequence of reflectivities. The method comprises obtaining seismic data (200) representing seismic changes which have occurred between a first time and a second time, said seismic data comprising a plurality of seismic traces; and performing an optimization operation simultaneously (230) on the seismic traces so as to optimize for said seismic wavelet. The optimization operation may be performed without using known reflectivity data as an input.

The present disclosure provides a technique for marine seismic imaging that processes data acquired from two or more different seismic surveys in a combined manner to advantageous effect. The different seismic surveys may use seabed sensors at same positions on the seabed, but they may have different shot locations and may be performed at different times. In one use case, the technique may be used to image a subsurface location that is difficult to image using either survey alone. In another use case, the technique may be used to image a subsurface location under an obstruction. The technique may also be utilized to efficiently monitor a reservoir over time.

A method of characterizing a subterranean formation using a plurality of seismic acquisitions includes obtaining a first seismic acquisition of the subterranean formation, wherein the first seismic acquisition is a baseline survey. Injecting a gas fluid into the subterranean formation, wherein the gas fluid at least partially fills a portion of a fracture network of the subterranean formation. Obtaining a second seismic acquisition of the subterranean formation. Calculating a time-lapse difference in the plurality of seismic acquisitions.