Methods and apparatus for acoustic velocity well logging. Methods may include estimating a property of an earth formation, including estimating a depth-dependent lateral tectonic strain profile for the earth formation by generating a linear-to-linear transformation constrained to map a first value of a shear wave velocity parameter of the formation to an estimated minimum value of lateral tectonic strain in at least one direction corresponding to at least one principal horizontal stress of the formation, and map a second value of the shear wave velocity parameter of the formation to an estimated maximum value of lateral tectonic strain in the at least one direction, wherein the strain values may be estimated using closure pressure. The first value of the shear wave velocity parameter may be a minimum value of shear wave slowness and the second value of the shear wave velocity parameter is a maximum value of shear wave slowness.

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.sub.ij; 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.sub.ij, 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.

This disclosure describes a novel method for predicting or estimating rock mechanical properties from cuttings at a particular depth based on determining the facies, plotting the facies on a ternary diagram with clay, silica and carbonate endpoints, and estimating rock mechanical properties based on comparison to a database of core samples from vertical wells that is also organized by depth and facies. We have shown that datapoints at similar locations on the ternary diagram will have fairly similar rock properties. These rock properties can be used to improve the reliability of a variety of reservoir modeling platforms, which can then be used in designing and implementing completion, stimulation and production plans.

Predicting hydraulic fracture treatment uses well log data and core data from one well in a given subsurface region to create a petrophysical properties model for the subsurface region. The petrophysical properties model yields fluid volumes and mineral volumes in any given well passing through the subsurface region using only well log data as inputs. The fluid and mineral volumes are used with dipole sonic data from a second well to create an elastic rock properties model for the given subsurface that yields elastic properties in any well passing through the subsurface region using only well log data and mineral and fluid volumes. For wells in the subsurface having only well log data, the petrophysical properties model and the elastic rock properties model are used with the well log data to predict an amount of recoverable hydrocarbons within wells that will respond to hydraulic fracture treatments.

Embodiments of determining a vertically transverse isotropy (VTI) anisotropy along a horizontal section of a wellbore drilled into a formation are provided. One embodiment comprises determining elastic constants C11, C44, and C66 of the horizontal section and determining a vertical compressional slowness of the horizontal section corresponding to an elastic constant C33 of the horizontal section using a model with a condition. The model is built using second sonic log data and second density log data of the vertical wellbore. The condition is that the shear slowness (DTS) of the vertical wellbore is equal to the vertically polarized shear slowness (DTSV) of the horizontal section. The embodiment further comprises determining a VTI anisotropy along the horizontal section using the elastic constants C11, C44, C66, and C33 of the horizontal section.

A method of predicting model parameters (R.sub.1, R.sub.2, R.sub.3, . . . ) of a geological formation under investigation, wherein said geological formation is distinguished by reservoir parameters including observable data parameters and the model parameters (R.sub.1, R.sub.2, R.sub.3, . . . ) to be predicted, comprises the steps of calculating at least one model constraint (M.sub.1, M.sub.2, M.sub.3, . . . ) of the model parameters (R.sub.1, R.sub.2, R.sub.3, . . . ) by applying at least one rock physics model (f.sub.1, f.sub.2, f.sub.3, . . . ) on the model parameters (R.sub.1, R.sub.2, R.sub.3, . . . ), said at least one model constraint (M.sub.1, M.sub.2, M.sub.3, . . . ) including modelled data of at least one of the data parameters, and applying an inverse model solver process on observed input data (d.sub.1, d.sub.2, d.sub.3, . . . ) of at least one of the data parameters, including calculating predicted model parameters, which comprise values of the model parameters (R.sub.1, R.sub.2, R.sub.3, . . . ) which give a mutual matching of the input data and the modelled data, wherein the modelled data are provided with probability distribution functions, the inverse model solver process is conducted based on the probability distribution functions, wherein multiple predicted values of the model parameters are obtained comprising values of the model parameters (R.sub.1, R.sub.2, R.sub.3, . . . ) which give the mutual matching of the input data and the modelled data, and model probabilities of the predicted model parameters are calculated in dependency on the probability distribution functions.

A method of performing oilfield operations at a wellsite is disclosed. The wellsite is positioned about a subterranean formation having multiple wellbores therethrough and a fracture network therein. The fracture network includes natural fractures. The method involves generating fracture parameters including a hydraulic fracture network of a fracture grid for each of the multiple wellbores based on wellsite data including microseismic events and a mechanical earth model, generating reservoir parameters including an updated mechanical earth model of a reservoir grid based on the wellsite data and the fracture parameters, generating integrated wellsite parameters including an integrated earth model by integrating the fracture parameters from the multiple wellbores with the reservoir parameters, and performing production operations at the multiple wellbores based on the integrated wellsite parameters.

A method of an interconnect structure includes the following steps. A first etching stop layer, a first dielectric layer, a second etching stop layer, an insert layer and a second dielectric layer are deposited over the second etching stop layer are deposited over a substrate. The second dielectric layer, the insert layer, the second etching stop layer, the first dielectric layer and the first etching stop layer are patterned thereby forming a trench opening and a via hole. A conductive feature is filled in the trench opening and the via hole thereby forming a conductive line in the second dielectric layer and the insert layer and a via in the first etching stop layer and the first dielectric layer. A material of the insert layer is different from the second dielectric layer and the second etching stop layer.

Methods and an alarming system for long-term carbon dioxide sequestration in a geologic reservoir are described. The geologic reservoir may be a water filled sandstone reservoir or a carbonate reservoir. A reservoir model is constructed to show the effects of varying injection pressures, the number of injection wells, the arrangement of injection wells, the boundary conditions and sizes of the reservoir on caprock uplift, fracture formation and fracture reactivation. The alarming system generates an alarm when caprock uplift that surpasses a threshold is detected. The injection pressures and the number of injection wells operating may be varied in response to the alarm.

A method includes receiving a first transition probability matrix (TPM) of a subsurface region, wherein the TPM defines, for a given lithology at a current depth sample (or micro-layer), a probability of particular lithologies at a next depth sample (or micro-layer), receiving seismic data for the subsurface region, utilizing the first TPM and the seismic data to generate first pseudo wells, calculating a second TPM from the first pseudo wells, determining whether the second TPM is consistent with the first TPM, and utilizing the first pseudo wells to characterize a reservoir in the subsurface region when the second TPM is determined to be consistent with the first TPM.