Schlumberger Technology Corporation

Other

Westerngeco L.l.p.

Colin Michael Sayers

Lennert David Den Boer

Donald W Lee

Patrick J Hooyman

Ali Mese

Richard Anthony Birchwood

Bikash Kumar Sinha

Takeshi Endo

Konstantin Osypov

John Paul Horkowitz

Ran Bachrach

Jorge Aurelio Santa Cruz Pastor

Geoff Weller

Aron Kramer

Alexis S Husser

Robert Andrew Holicek

Dan Shan

Sudhendu Kashikar

A method of predicting pore pressure based on seismic data can include obtaining seismic inversion data based in part on seismic data collected from a formation. The method also includes calculating a pore-pressure transform, wherein the pore-pressure transform comprises parameters derived using measured pore pressure data, upscaled sonic logs, and density logs, wherein the pore-pressure transform comprises an objective function to reduce unphysical variations in predicted pore pressure corresponding to depth. Additionally, the method can include adjusting the pore-pressure transform for sampling bias caused by pore pressure measurements being restricted to a plurality of lithologies by accounting for a difference between upscaled seismic velocities and average sonic velocities within each of the lithologies. Furthermore, the method can include generating pore pressure prediction values based on the pore-pressure transform for the lithologies and the seismic inversion data, and modifying a seismic model based on the generated pore pressure prediction values.

Seismic pore-pressure prediction using prestack seismic inversion

A method can include receiving values of an inversion based at least in part on seismic amplitude variation with azimuth (AVAz) data for a region of a geologic environment; based at least in part on the received values, computing values that depend on components of a second-rank tensor a; selecting a fracture height for fractures in the geologic environment; selecting an azimuth for a first fracture set of the fractures; based at least in part on the values for the second-rank tensor a, the fracture height and the selected azimuth, determining an azimuth for a second fracture set of the fractures; and generating a discrete fracture network (DFN) for at least a portion of the region of the geologic environment where the discrete fracture network (DFN) includes fractures of the first fracture set and fractures of the second fracture set.

Seismic constrained discrete fracture network

A method can include deriving a cloud of microseismic events corresponding to a fracturing operation in an environment by spatially locating the microseismic events in the environment via a seismic velocity model; extracting a set of fracture planes from the microseismic cloud; assigning characteristics to the fracture planes; determining a second-rank fracture compliance tensor and a fourth-rank fracture compliance tensor based on the characteristics of the fracture planes; determining a change in elastic stiffness of the environment using the second-rank fracture compliance tensor and the fourth-rank compliance tensor; and updating the seismic velocity model based at least in part on the change in the elastic stiffness of the environment or determining permeability in the environment based at least in part on fracture plane locations, orientations and apertures. Various other apparatuses, systems, methods, etc., are also disclosed.

Determining change in permeability caused by a hydraulic fracture in reservoirs

A logging tool capable of making different types of measurements is provided, and a plurality of measurements on a formation are obtained. Certain mineral properties of the formation are assumed and a mixed properties theorem for the formation is invoked. Upper and lower velocity limits for sonic waves traveling through the formation are determined using the above information. Biot's constant is also computed using the above information. LWD data on the formation is obtained and an effective stress is determined. A total stress is determined and, from that and the other information, a pore pressure is determined.

Pore pressure from spectroscopy and sonic data

A technique includes identifying a fracture polygon intersecting a voxel of a three-dimensional grid of voxels representing a region of interest of a hydrocarbon-bearing reservoir based on data indicative of a discrete fracture network. The technique includes partitioning the polygon with a regular mesh of points and determining a number of the mesh points inside the voxel and inside the polygon. The technique includes estimating an area of the fracture inside the voxel based at least in part on the determined number of mesh points inside the voxel and inside the polygon. The technique includes determining at least one property of a portion of the hydrocarbon-bearing reservoir, which coincides with the voxel based at least in part on the estimated area of the fracture.

Determining elastic and fluid flow properties of a fractured reservoir

Methods and apparatus that use microseismic event data, stress data, seismic data, and rock properties to predict the hydrocarbon production success of a well location are disclosed. An example method generates a hydrocarbon production function based on information associated with at least a first well location, obtains information associated with a second well location, and calculates the hydrocarbon production function using the information associated with the second well location to predict the hydrocarbon production of the second well location.

Using microseismic data to characterize hydraulic fractures

A method for performing an oilfield operation at a wellsite having a drilling rig configured to advance a drilling tool into a subsurface formation. The method includes generating a borehole temperature model for an area of interest using water depth information and a vertical stress model, generating a formation temperature model using the borehole temperature model, generating a mud-weight pressure model using the formation temperature model and pressure coefficients, generating a formation pore pressure model using the mud-weight pressure model, and adjusting the oilfield operation based on the formation pore pressure model.

Method and system for pore pressure prediction

A method and apparatus for estimating velocity in a subsurface region. Seismic data for a subsurface region may be received. One or more attributes for the seismic data may be calculated. A posterior distribution may be generated. The posterior distribution may represent one or more probabilities of one or more velocities for the attributes. A velocity with uncertainty may be determined for the subsurface region based on the posterior distribution. A pore pressure with uncertainty may be determined based on the velocity with uncertainty.

Estimating velocities with uncertainty

In general, in one aspect, the invention relates to a method for determining properties of a subterranean formation. The method includes obtaining a micro-mechanical model for modeling the subterranean formation as a plurality of particles having low aspect ratio pores therebetween, wherein anisotropy of the subterranean formation is represented by normal compliance and shear compliance that describe deformation of the low aspect ratio pores under an applied stress, determining a ratio of normal compliance over shear compliance of the subterranean formation to obtain an estimated ratio of normal compliance over shear compliance, measuring a first formation parameter of the subterranean formation to obtain a measured first formation parameter based on a sonic measurement technique, determining a second formation parameter based on the micro-mechanical model using the estimated ratio of normal compliance over shear compliance and the measured first formation parameter, storing the second formation parameter of the subterranean formation, wherein the first formation parameter and the second formation parameter comprises at least one selected from a group consisting of an anisotropy parameter and a stiffness coefficient of the subterranean formation.

Estimating seismic anisotropy of shales

The invention relates to a method for determining maximum horizontal stress in an earth formation. The method includes obtaining fast shear wave velocities (V) and slow shear wave velocities (V) for various depths in the earth formation, calculating shear wave anisotropy (A) using Vand V, obtaining vertical stress (S) and minimum horizontal stress (S) for the formation, representing maximum horizontal stress (S) using a parameterized function having at least one parameter and usingand Sas input, determining a value of the at least one parameter by minimizing a cost function that represents a measure of difference between Aand Afor the various depths and Ais predicted shear wave anisotropy determined using S, S, and S, calculating Susing the parameterized function and the value of the at least one parameter, and storing Sin relation to the earth formation.

Determining maximum horizontal stress in an earth formation

A method of characterizing a fractured reservoir in a field includes measuring seismic reflection coefficient of the fractured reservoir as a function of angle of incidence and azimuth, predicting seismic reflection coefficient of the fractured reservoir as a function of angle of incidence and azimuth using an elastic stiffness tensor and an elastic compliance tensor of the fractured reservoir, determining components of an excess compliance tensor due to the presence of fractures in the fractured reservoir by matching the predicted seismic reflection coefficient to the measured seismic reflection coefficient, and characterizing one or more properties of the fractured reservoir using the excess compliance tensor.

Method of characterizing a fractured reservoir using seismic reflection amplitudes

Predicting sand production in a wellbore. A first set of characteristics is determined for a formation in the wellbore, wherein determining uses a plastic model of the formation, and wherein the first set of characteristics comprises a yield surface, a failure surface, a stress total strain, an elastic strain, and a plastic-strain relationship. A relationship among a second set of characteristics of the wellbore is determined using an effective stress model, wherein the second set comprises a drawdown pressure, a production rate, pore pressure, a temperature and a viscosity of a fluid in the wellbore, a fluid flow pressure in the wellbore, a drag force of fluid flow in the wellbore, and a type of fluid flow in the wellbore. A critical total strain is determined for the formation using the first set of characteristics and the relationship. The critical total strain is calibrated using a thick wall test.

Determination of point of sand production initiation in wellbores using residual deformation characteristics and real time monitoring of sand production

In general, the invention relates to a method for pore pressure prediction. The method includes obtaining a compressional wave (P-wave) velocity and a shear wave (S-wave) velocity for a pre-drill location, calculating an effective stress at the pre-drilling location using a stress-velocity relationship equation, the compressional wave (P-wave) velocity and the shear wave (S-wave) velocity, obtaining a total stress at the pre-drill location, calculating a predicted pore pressure, at the pre-drill location, using the effective stress, the total stress and a stress-pressure relationship equation, and adjusting a drilling operation associated with the pre-drill location, based on the predicted pore pressure.

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Katy, TX, United States of America

Colin Michael Sayers