WO2017142719A1 - Étalonnage de données sismiques à l'aide de mesures effectuées pendant des opérations de forage - Google Patents

Étalonnage de données sismiques à l'aide de mesures effectuées pendant des opérations de forage Download PDF

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Publication number
WO2017142719A1
WO2017142719A1 PCT/US2017/016610 US2017016610W WO2017142719A1 WO 2017142719 A1 WO2017142719 A1 WO 2017142719A1 US 2017016610 W US2017016610 W US 2017016610W WO 2017142719 A1 WO2017142719 A1 WO 2017142719A1
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WIPO (PCT)
Prior art keywords
seismic data
measured
lwd
measurements
drilling
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PCT/US2017/016610
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English (en)
Inventor
Michael Hermann NICKEL
Lars Kristian SØNNELAND
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Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
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Publication of WO2017142719A1 publication Critical patent/WO2017142719A1/fr

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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V11/00—Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V13/00—Manufacturing, calibrating, cleaning, or repairing instruments or devices covered by groups G01V1/00 – G01V11/00
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. for interpretation or for event detection
    • G01V1/30—Analysis
    • G01V1/301—Analysis for determining seismic cross-sections or geostructures
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G01V1/48—Processing data
    • G01V1/50—Analysing data
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2200/00—Details of seismic or acoustic prospecting or detecting in general
    • G01V2200/10—Miscellaneous details
    • G01V2200/16—Measure-while-drilling or logging-while-drilling
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/60—Analysis
    • G01V2210/61—Analysis by combining or comparing a seismic data set with other data
    • G01V2210/614—Synthetically generated data

Definitions

  • the present disclosure relates to calibration of seismic data using measurements made during a drilling operation to drill a borehole through an earth formation, such as for example logging-while-drilling (LWD) measurements.
  • LWD logging-while-drilling
  • Seismic surveying is generally performed by imparting energy to the earth at one or more source locations, for example, by way of controlled explosion, mechanical input etc. Return energy is then measured at surface receiver locations at varying distances and azimuths from the source location. The travel time of energy from source to receiver, via reflections and refractions from interfaces of subsurface strata, indicates the depth and orientation of such strata.
  • a local subsurface model is built for a region around the new planned well using the seismic data and sometimes additional logs from nearby wells.
  • the seismic data may be used to detect and map the relevant interfaces that will be used as references when geosteering the trajectory of the new well while drilling.
  • interfaces typically including the top and base reservoir as well as possible fluid contacts within the reservoir may be detected from the seismic data and used in steering the drilling of a borehole through a subterranean section of the earth.
  • the seismic data inherently measures the travel time it takes for a seismic pulse to propagate from the surface to e.g. the top reservoir and back to the surface, the depth of a seismic reflector must be inferred by converting the travel time to depth using a velocity model.
  • seismic data provides a broad view of the subsurface, which is useful for planning wellbore/borehole trajectories and steering the drilling system.
  • LWD measurements may be made and processed to detect interfaces/features in the subsurface corresponding to those detected from a seismic survey. For example, during geosteering, electromagnetic, resistivity and/or inductance measurements may be acquired and a two dimensional (2D) (or potentially three dimensional (3D)) image covering the neighbourhood of the wellbore within a radius of typically 30 meters can be generated by inversion. Furthermore, the detected interfaces can be placed quite accurately in their depth position since precise knowledge of the tool position in 3D during the drilling procedure is generally available and the inversion may have high accuracy.
  • 2D two dimensional
  • 3D three dimensional
  • the present disclosure provides methods and systems for calibrating seismic data using LWD measurements.
  • the present disclosure enables improvements in calibration of seismic data using LWD measurements in order to better predict the geology ahead of/around the drill bit and thus geosteer the wellbore along a preferred/optimized trajectory.
  • some embodiments of the present disclosure provide a method for calibrating seismic data using LWD measurements.
  • the method includes obtaining seismic data and obtaining LWD measurements during a drilling procedure.
  • the LWD measurements are used to produce synthetic seismic data.
  • This synthetic seismic data is then compared to the measured seismic data to generate a displacement field; and the measured seismic data is calibrated using the displacement field.
  • the method of the first aspect may have any one or, to the extent that they are compatible, any combination of the following optional features.
  • the method may be performed in real-time during the drilling procedure to provide for real-time steering of the drilling system.
  • the measured seismic data surveys the subterranean area around a section of a wellbore drilled and/or being drilled in the drilling procedure.
  • the measured seismic data may also measure properties of the subterranean section of the earth ahead of a drilled section of wellbore, and the method may further com prise extrapolating the displacement field ahead of the drilled section of wellbore. Calibration of the measured seismic data using such an extrapolated displacement field may lead to revision of a currently planned well trajectory.
  • the displacement field may be generated by non-rigid matching of the synthetic seismic data and the measured seismic data.
  • the comparing of the measured seismic data and the synthetic seismic data may be performed directly on measured and synthetic continuous seismic signal data, e.g. by determining root-mean-square differences between the two sets of data.
  • Another option, however, for the comparing of the measured seismic data and the synthetic seismic data is for the measured and synthetic seismic data to be in the form of processed seismic signal data, e.g. discrete (non-continuous) reflectivity data identifying positions and corresponding amplitudes of seismic reflectors.
  • the calibrating of the measured seismic data can include updating, on the basis of the displacement field, a velocity model which converts seismic pulse travel time to depth. This is particularly advantageous if the seismic data is in the time domain, i.e. it has not already been transferred to depth.
  • the LWD measurements may comprise deep and directional electromagnetic LWD measurements, deep resistivity measurements, and/or deep inductance measurements.
  • the obtaining of LWD measurements, the use of the LWD measurements to produce synthetic seismic data, the comparing the synthetic seismic data with the measured seismic data, and the calibrating the measured seismic data may be repeated multiple times, e.g. as the drill bit progresses along a trajectory.
  • the method may further comprise estimating, from the measured seismic data, a seismic wavelet, which may be used to produce the synthetic seismic data from the LWD measurements.
  • the method may further comprise displaying the calibrated measured seismic data, e.g. along with the synthetic seismic data and/or a representation of a current position of a drillstring used to obtain the LWD measurements.
  • inventions of the present disclosure provide a procedure for controlling a steerable or landable drillstring located in a borehole.
  • the drillstring may include one or more LWD modules and the procedure comprises performing the method of the first aspect and controlling the operation of the drillstring on the basis of the calibrated measured seismic data.
  • a computer system can be provided for calibrating seismic data using logging-while-drilling (LWD) measurements, the system including: a computer- readable storage medium storing (i) measured seismic data; and (ii) LWD measurements made during a drilling procedure.
  • One or more processors may be configured to use the LWD measurements to produce synthetic seismic data; compare the synthetic seismic data with the measured seismic data to generate a displacement field; and calibrate the measured seismic data on the basis of the displacement field.
  • the system may further include a display device for displaying the calibrated measured seismic data.
  • the measured seismic data may be used to process the LWD measurements to generate the synthetic seismic data.
  • a further aspect of the present disclosure provides a drilling system including a steerable or landable drillstring located in a borehole, where the drillstring includes one or more LWD modules; and a computer system according to the previous aspect for constraining a seismic inversion using real-time measurements from the LWD modules.
  • Figure 1 illustrates a drilling system for operation at a wellsite to drill a borehole through an earth formation, in accordance with some embodiments of the present disclosure
  • Figure 2 shows schematically a wellbore being drilled between top and bottom reservoir interfaces, in accordance with some embodiments of the present disclosure.
  • the order of the operations may be re-arranged.
  • a process is terminated when its operations are completed, but could have additional steps not included in the figure.
  • a process may correspond to a method, a function, a procedure, a subroutine, a subprogram, etc.
  • a process corresponds to a function
  • its termination corresponds to a return of the function to the calling function or the main function.
  • the term "storage medium” may represent one or more devices for storing data, including read only memory (ROM), random access memory (RAM), magnetic RAM, core memory, magnetic disk storage mediums, optical storage mediums, flash memory devices and/or other machine readable mediums for storing information.
  • computer-readable medium includes, but is not limited to portable or fixed storage devices, optical storage devices, wireless channels and various other mediums capable of storing, containing or carrying instruction(s) and/or data.
  • embodiments may be implemented by hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof.
  • the program code or code segments to perform the necessary tasks may be stored in a machine readable medium such as storage medium.
  • a processor(s) may perform the necessary tasks.
  • a code segment may represent a procedure, a function, a subprogram, a program, a routine, a subroutine, a module, a software package, a class, or any combination of instructions, data structures, or program statements.
  • a code segment may be coupled to another code segment or a hardware circuit by passing and/or receiving information, data, arguments, parameters, or memory contents. Information, arguments, parameters, data, etc.
  • first and second features are formed in direct contact
  • additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
  • Figure 1 illustrates a drilling system for operation at a wellsite to drill a borehole through an earth formation, in accordance with some embodiments of the present disclosure.
  • the wellsite can be located onshore or offshore.
  • a borehole 1 1 is formed in subsurface formations by rotary drilling in a manner that is well known.
  • Systems can also use be used in directional drilling systems, pilot hole drilling systems, casing drilling systems and/or the like.
  • a drillstring 12 is suspended within the borehole 1 1 and has a bottomhole assembly 100, which includes a drill bit 105 at its lower end.
  • the surface system includes a platform and derrick assembly 10 positioned over the borehole 1 1 , the assembly 10 including a top drive 30, kelly 17, hook 18 and rotary swivel 19.
  • the drillstring 12 is rotated by the top drive 30, energized by means not shown, which engages the kelly 17 at the upper end of the drillstring.
  • the drillstring 12 is suspended from the hook 18, attached to a traveling block (also not shown), through the kelly 17 and the rotary swivel 19 which permits rotation of the drillstring relative to the hook.
  • a rotary table system could alternatively be used to rotate the drillstring 12 in the borehole and thus rotate the drill bit 105 against a face of the earth formation at the bottom of the borehole.
  • the surface system can further include drilling fluid or mud 26 stored in a pit 27 formed at the well site.
  • a pump 29 delivers the drilling fluid 26 to the interior of the drillstring 12 via a port in the swivel 19, causing the drilling fluid to flow downwardly through the drillstring 12 as indicated by the directional arrow 8.
  • the drilling fluid exits the drillstring 12 via ports in the drill bit 105, and then circulates upwardly through the annulus region between the outside of the drillstring and the wall of the borehole, as indicated by the directional arrows 9.
  • the drilling fluid lubricates the drill bit 105 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation.
  • a control unit 40 may be used to control the top drive 30 or other drive system.
  • the top drive 30 may rotate the drillstring 12 at a rotation speed to produce desired drilling parameters.
  • the speed of rotation of the drillstring may be determined so as to optimize a rate of penetration through the earth formation, set to reduce drill bit wear, adjusted according to properties of the earth formation, or the like.
  • the bottomhole assembly 100 may include a logging-while-drilling (LWD) module 120, a measuring-while-drilling (MWD) module 130, a rotary-steerable system and motor 125, and drill bit 105.
  • LWD logging-while-drilling
  • MWD measuring-while-drilling
  • rotary-steerable system and motor 125 drill bit 105.
  • the MWD module 130 may be housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drillstring and drill bit.
  • the MWD tool may further include an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed.
  • the MWD module may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, a rotation speed measuring device, and an inclination measuring device.
  • the LWD module 120 may also be housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g. as represented at 120A.
  • the LWD module may include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment.
  • the LWD module may include a fluid sampling device.
  • Typical LWD measurement systems may include, for example, natural gamma ray, spectral density, neutron density, inductive and galvanic resistivity, acoustic velocity, acoustic caliper, downhole pressure, and the like. Formations having recoverable hydrocarbons typically include certain well-known physical properties, for example, resistivity, porosity (density), and acoustic velocity values in a certain range.
  • FIG. 2 shows schematically a wellbore being drilled between top and bottom reservoir interfaces, in accordance with some embodiments of the present disclosure, where the positions of the interfaces indicated are extracted from measured seismic data and from deep reading LWD measurements.
  • the LWD- derived interfaces are generally more accurately positioned than the seismic-derived interfaces.
  • the seismic-derived interfaces have an advantage of a wider field of view extending beyond the head of the well into the territory of future planned trajectory.
  • the LWD measurements are obtained along the well trajectory, providing expected interfaces vertically above and below the well trajectory.
  • the methods and systems of the present disclosure combine measured seismic data with LWD measurements.
  • measured seismic data can be used to identify key interfaces in and/or in a close neighbourhood to the subsurface volume of interest (typically a reservoir) where a new well is going to be drilled.
  • LWD measurements are then acquired while drilling, and can be used to produce a 2D or 3D subsurface model in the vicinity of the wellbore.
  • the LWD measurements are used to produce (e.g. by inversion) synthetic seismic data, which are compared with the measured seismic data to generate a displacement field. Calibration of the measured seismic data on the basis of the displacement field then allows seismic interfaces to be updated.
  • the calibration can be performed in real time and thus can support the decision process of how to proceed with drilling the wellbore along an optimal trajectory.
  • the seismic data may be used to interpret the LWD measurements, which in turn is used to generate the synthetic seismic data.
  • the MWD data may also be used to interpret the LWD measurements.
  • Relating the LWD measurements and the measured seismic data may involve as a first stage the decomposition of the seismic data into a "fluid" part and a "lithology” part. This may be performed, for example, in the case that the reservoir consists of a dipping formation that is bounded by an unconformity, a fault, a salt flank or another structural trap.
  • the signal component of the dipping reservoir fades can be extracted by applying a dip steered digital filter. Subtracting this "lithology" signal from the original seismic image renders a "fluid" component, i.e. reflectors with no dip. In this way, gravity steered fluid contacts may be enhanced.
  • a synthetic seismic reflectivity is generated from the resistivity image R(x,y,z).
  • the generated reflectivity may be convolved with a wavelet, which is extracted from the seismic image, using a process such as blind deconvolution (see Karesen, K. F. and T. Taxt (1998), Multichannel Blind Deconvolution of Seismic Signals, Geophysics 63, 2093-2107) or other process known to the skilled person for wavelet extraction using seismic and well log data. Commonly, the seismic is sampled at a smaller rate (i.e.
  • the wavelet may be upsampled or interpolated using algorithms such as spline interpolation, sine interpolation, Lanczos interpolation eto.
  • ⁇ resistivity ⁇ ⁇ > w(z) Y ⁇ X, J, z) (3)
  • w(z) denotes the interpolated wavelet.
  • the convolution is performed in the depth domain. However, for more accurate results it can be performed in the time domain.
  • Another option in accordance with some embodiments of the present disclosure is to map the reflectivity model r(x,y,z) from the depth to time domain using a seismic velocity model and a scheme for mapping between the two domains (such as a stretching or map migration).
  • the convolution is then performed in the time domain and the result is mapped back to the depth domain using the same velocity model and mapping scheme as before.
  • the synthetic resistivity seismic and the measured seismic are matched to each other.
  • both data sets may be resampled to the same sampling rate.
  • the sampling along the lateral dimensions (x,y) may also need attention.
  • Resistivity data may be acquired along the well trajectory at an interval of typically 305 millimeters (1 foot) as drilling proceeds.
  • seismic data typically have a lateral sampling interval in the range from 6.25 meters to 25 meters.
  • the synthetic seismic sample(s) that falls within the area represented by one measured seismic sample may be used in the subsequent matching process.
  • Various selection processes are possible.
  • an average of all the synthetic seismic samples that fall within the lateral area (i.e. a bin) of a measured seismic sample may be selected.
  • the two regions are then matched by comparing the measured and synthetic data (e.g. reflectivity images) and estimating the displacement field necessary to co-align the two sets of data.
  • This comparison process can be performed by applying non-rigid matching as detailed e.g. in PCT Published Patent Application No. WO 99/67660 A1 , which is incorporated by reference herein for all purposes.
  • other processes such as time warping fluid registration, registration using evolutional algorithms or Monte Carlo approaches may be used instead.
  • the estimated displacement field necessary to co-align the two sets of data may be restricted to the vertical dimension only, or displacement components in two or three dimensions may be allowed for.
  • the estimated displacement field is then used to calibrate the measured seismic data, e.g. to correct for positional inaccuracies in measured reflector positions due to a suboptimal velocity model.
  • the calibration may involve updating an existing velocity model using the estimated displacement field, as described in more detail in Appendix 2.
  • the calibration can provide an updated position of the measured seismic data ahead of the drill bit. More particularly, at a certain position of the drill bit, LWD measurements are only available for the trajectory drilled up to that position, and the corresponding displacement field is also only generated up to this position. However, assuming that the inaccuracies in the seismic velocity model are smoothly varying, in accordance with some embodiments of the present disclosure, this allows the displacement field to be extrapolated ahead of the bit as well as to neighborhoods parallel to the existing well section. The extrapolated displacement field can then be used to calibrate the measured seismic data ahead of and/or parallel to the existing well section to better inform control of future well trajectory. Such a calibration may lead to a revision of the currently planned well trajectory.
  • the extrapolation may be performed by copying the displacement field at the current bit position d(xbit,yt>it,z) horizontally to the position(s) the drill bit will reach when propagating along the currently planned trajectory.
  • Another option in accordance with some embodiments of the present disclosure, is for the extrapolation to follow a dip field extracted from the measured seismic data or one of its components (i.e. "fluid” or "Nthology") rather than being copied purely horizontally.
  • Yet another option, in accordance with some embodiments of the present disclosure is to employ a kriging method to interpolate the displacement field to locations of the trajectory ahead of the drill bit. This approach may use calibration points from surrounding wells where the displacement is known or known to be zero.
  • the above procedure may be repeated, resulting in the generation of a new displacement field and re-calibration of the measured seismic and associated horizons.
  • the mapping function f(R) may be explicitly modelled using rock-physics equations.
  • Faust equation where: v p is seismic pressure velocity, R f is the resistivity of the reservoir formation, and Z the formation depth.
  • R f a - R br ⁇ -" - S l is taken as the basis to establish the function /(R) .
  • R f is the resistivity of the reservoir formation
  • R br is the resistivity of the brine that occupies a part of the pore volume given by the saturation S br
  • ⁇ is the porosity i.e. the ratio of the pore volume to the bulk volume of the formation
  • a « 0.5 - 1.5 is the tortuosity factor
  • «3 ⁇ 4 « 1.8 - 2.0 is the cementation exponent
  • « « 2 is the saturation exponent.
  • the brine resistivity is composed of the components: free water resistivity and the clay bound water resistivity.
  • the clay bound water resistivity is dominating at depths greater than 1000m. It can be approximated by:
  • K formatwn , K frame , K matnx and K fl are the bulk moduli of the formation, the rock frame, the rock matrix and the fluid contained in the rock, respectively, and ⁇ is the rock porosity.
  • the formation bulk modulus may be rewritten as:
  • the dependence of the acoustic impedance on the resistivity is only implicit via the brine saturation and the porosity.
  • the saturation will be known with an acceptable amount of uncertainty and hence one may solve Archie's law for porosity: and substitute it into the formula for the acoustic impedance.
  • the porosity of a formation is known with an acceptable degree of uncertainty one may solve for the brine saturation and substitute this quantity in the above equation for the acoustic impedance.
  • acoustic impedance and the resistivity are quite complex, and can necessitate the measurement or estimation of many equation parameters.
  • another option is to establish a look-up table between the acoustic impedance and the resistivity e.g. by learning it from other wells in the neighborhood of the current subsurface location.
  • neural networks may be used.
  • Procedures for updating an existing velocity model using the estimated displacement depend on the domain in which the displacement is estimated, and in particular whether the vertical axis is measured in true depth or in two-way travel time.
  • the relation between the two-way travel time t and the depth z at the top and base of this layer is given as: where: i indicates the top and i+1 the base of the layer. If the velocity model used to image the acquired seismic is flawed, the apparent location of layer i becomes: where ⁇ , is due to assumed flaws in the velocity model of shallower layers. Consequently:
  • the flawed velocity model may be updated according to:

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Abstract

L'invention concerne un procédé d'étalonnage de données sismiques à l'aide de mesures de diagraphie en cours de forage (LWD). Dans le procédé, des données sismiques mesurées issues d'une étude sismique et des mesures LWD effectuées pendant une procédure de forage sont obtenues. Les mesures LWD sont utilisées pour produire des données sismiques synthétiques, qui sont comparées aux données sismiques mesurées pour générer un champ de déplacement. Le champ de déplacement est utilisé pour étalonner les données sismiques mesurées.
PCT/US2017/016610 2016-02-16 2017-02-04 Étalonnage de données sismiques à l'aide de mesures effectuées pendant des opérations de forage WO2017142719A1 (fr)

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CN110673209A (zh) * 2019-10-13 2020-01-10 东北石油大学 一种井震标定方法
CN110761780A (zh) * 2019-11-06 2020-02-07 中法渤海地质服务有限公司 一种基于井震结合的三维地质导向方法
CN112578445A (zh) * 2019-09-27 2021-03-30 中国石油天然气集团有限公司 地震逐点引导钻进的方法和装置
WO2022199776A1 (fr) * 2021-03-24 2022-09-29 Ouabed Noureddine Procédé d'estimation de la tortuosité à partir d'une inversion dans un réservoir hétérogène et anisotrope
WO2024102221A1 (fr) * 2022-11-09 2024-05-16 Schlumberger Technology Corporation Dispositifs, systèmes et procédés de prédiction de surface et de propriété géologiques

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Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN112578445A (zh) * 2019-09-27 2021-03-30 中国石油天然气集团有限公司 地震逐点引导钻进的方法和装置
CN110673209A (zh) * 2019-10-13 2020-01-10 东北石油大学 一种井震标定方法
CN110673209B (zh) * 2019-10-13 2021-06-04 东北石油大学 一种井震标定方法
CN110761780A (zh) * 2019-11-06 2020-02-07 中法渤海地质服务有限公司 一种基于井震结合的三维地质导向方法
WO2022199776A1 (fr) * 2021-03-24 2022-09-29 Ouabed Noureddine Procédé d'estimation de la tortuosité à partir d'une inversion dans un réservoir hétérogène et anisotrope
WO2024102221A1 (fr) * 2022-11-09 2024-05-16 Schlumberger Technology Corporation Dispositifs, systèmes et procédés de prédiction de surface et de propriété géologiques

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