Abstract: The invention relates to a method of monitoring the interior of a pipeline (1) positioned in contact with a soil (S) below a water mass (E), comprising implementation of the following steps by data processing means (11): (a) for at least one position along said pipeline (1), obtaining acoustic data descriptive of at least one cross-section of said pipeline (1) at said position, acquired by a mobile acoustic acquisition device (20) in said water mass (E), (b) estimating by quantitative migration from said acoustic data an estimated relative impedance perturbation profile in at least said cross-section of said pipeline (1).

Abstract: The present invention is a method of detecting and counting a geological constituent (cge) of an acquired image of a rock sample (IER), by a location detection machine learning method (ALG).

Abstract: The present invention relates to a method of detecting a geological constituent (cge) of a rock sample, by use of a machine learning method (ALG) trained with a limited number of training images (IAP), through segmentation (SEG) and partitioning (DEC) of training images (IAP) into multiple patches.

Abstract: The invention is a method of monitoring an underground formation into which a gas is injected or from which a gas is produced, by a stratigraphic inversion of seismic data with anamorphosis of impedances. Pre-injection and post-injection seismic data are acquired. A pre-injection seismic impedance cube IP1 is determined by a stratigraphic inversion of the pre-injection seismic data. An anamorphosis function ? is defined by a function comprising a positive lower limit B1, an upper limit B4, an identity interval defined between limits B2 and B3, with B1<B2<B3<B4. A value for each limit B1, B2, B3 and B4 is associated with each cell of the cube. Post-injection seismic impedances IP2 are determined by a stratigraphic inversion of the post-injection seismic data wherein the anamorphosis function ? is applied to seismic impedances IP2. The gas is located within the zone by identifying the cells where IP2<IP1.

Abstract: The invention is a method of constructing an image representative of a heterogeneous medium by a procedure of joint inversion of seismic data represented on different time scales having an application for underground reservoir exploration. Sequential inversion of the seismic data is performed so as to determine a first model from the seismic data expressed in a first time scale, and a second model from the seismic data expressed in the second time scale. A scale factor t1(t0) allowing synthetic data described in a first time scale to be expressed in a second time scale is defined by a differential equation relating the traveltime variations of a seismic wave to the models resulting from the sequential inversion. Finally, joint inversion wherein a cost function using the scale factor is minimized is carried out so as to evaluate a difference between the synthetic data and the seismic data expressed in another time scale.

Abstract: A method of monitoring an underground formation into which a gas is injected or from which a gas is produced, by a stratigraphic inversion of seismic data with anamorphosis of impedances. Pre-injection and post-injection seismic data are acquired. A pre-injection seismic impedance cube IP1 is determined by a stratigraphic inversion of the pre-injection seismic data. An anamorphosis function ? is defined by a function comprising a positive lower limit B1, an upper limit B4, an identity interval defined between limits B2 and B3, with B1<B2<B3<B4. A value for each limit B1, B2, B3 and B4 is associated with each cell of the cube. Post-injection seismic impedances IP2 are determined by a stratigraphic inversion of the post-injection seismic data wherein the anamorphosis function ? is applied to seismic impedances IP2. The gas is located within the zone by identifying the cells where IP2<IP1.

Abstract: A method of constructing an image representative of a heterogeneous medium by a procedure of joint inversion of seismic data represented on different time scales having an application for underground reservoir exploration. Sequential inversion of the seismic data is performed so as to determine a first model from the seismic data expressed in a first time scale, and a second model from the seismic data expressed in the second time scale. A scale factor t1(t0) allowing synthetic data described in a first time scale to be expressed in a second time scale is defined by a differential equation relating the traveltime variations of a seismic wave to the models resulting from the sequential inversion. Finally, joint inversion wherein a cost function using the scale factor is minimized is carried out so as to evaluate a difference between the synthetic data and the seismic data expressed in another time scale.