Swami, Vivek (CGG) | Tavares, Julio (CGG) | Pandey, Vishnu (CGG) | Nekrasova, Tatyana (CGG) | Cook, Dan (Bravo Natural Resources) | Moncayo, Jose (Bravo Natural Resources) | Yale, David (Yale Geomechanics Consulting)
In this study, a state-of-the-art seismic driven 3D geological model was built and calibrated to a petrophysical and geomechanical analysis, 1D-MEM (Mechanical Earth Model), on chosen wells within the Arkoma Basin of Oklahoma. The well information utilized in this study included basic wireline logs and core analysis, including XRD (X-Ray diffraction) data. The traditional petrophysical analysis was augmented with advanced rock physics and statistical techniques to generate the necessary logs. Hydrostatic, overburden and pore pressures were calculated with a petrophysical evaluation model. The 1D-MEMs were based on the Eaton/Olson/Blanton approach with the HTI (Horizontal Transverse Anisotropy) assumption. The 1D-MEMs were calibrated to laboratory data (triaxial tests) and field observations (mud logs, wellbore failure, frac pressures). Therefore, a very good confidence was achieved on Biot's coefficient, tectonic components, anisotropy and dynamic to static conversion factors for Young's Modulus and Poisson's Ratio. Seismic inversions were performed in different time windows and merged to generate high resolution P- and S-Impedance attributes from surface down to the target interval after careful AVO compliant gather preconditioning. A density volume estimate was calibrated to well data, accounting for different geological formations, to decouple P- and S-Wave components as a 3D volume, as well as dynamic Young's modulus (E) and Poisson's ratio (PR). Dynamic E and PR were converted to static parameters using results from 1D-MEMs; and 3D models of Biot's coefficient (α) and tectonic components were built to compute 3D fracture pressure volumes calibrated to well data. The final products were seismic-driven 3D pore pressure and fracture pressure calibrated to 1D-MEMs. The correlation between measured/estimated well logs and corresponding seismic-derived pseudo logs was more than 80%, which indicates good quality of seismic inversion results and hence 3D-MEM. Also, stress barriers, anisotropy, and brittleness indices were calculated on well scale which would help to identify best zones to place hydraulic fractures. The 3D geological model will aid in identifying sweet-spots and optimizing hydraulic fractures.
Copyright 2018, Unconventional Resources Technology Conference (URTeC) This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Standard seismic/ acoustic log Pp prediction techniques developed for young sediments in offshore basins are not very effective in unconventional reservoirs. The age and lithification of shale reservoirs, the variability in lithology, and different overpressure generation mechanisms and basin histories all lead to poor quality predictions using standard Eaton or Bowers methods. But Pp prediction remains important in unconventional reservoirs due to the correlation between overpressured areas and productivity, and the correlations between thermal maturity and pore pressure. We have developed a method that extends the theoretical basis of the Eaton and Bowers methods to the geologic and basin history conditions of unconventional reservoirs. The method has been developed using standard log suite along with dipole acoustic logs.
Chen, Ganglin (ExxonMobil Upstream Research Co.) | Yale, David (ExxonMobil Upstream Research Co.) | Huang, Xiaojun (ExxonMobil Upstream Research Co.) | Xu, Shiyu (ExxonMobil Upstream Research Co.) | Finn, Chris (ExxonMobil Upstream Research Co., now at ExxonMobil Development Co.) | Boitnott, Greg (New England Research)
Ultrasonic velocity measurements were made on dry and oil saturated samples/cores of unconsolidated sands to investigate the stress-induced velocity anisotropy under realistic reservoir stress conditions. Instrumentation was arranged to simultaneously measure five velocities (axial P, axial S, radial P, radial S polarized radially, and radial S polarized axially) and the axial and radial deformation of the samples in a single run.
Within the experimental uncertainties, the measurements show:
(1) Stress-induced velocity anisotropy in unconsolidated sands could be a major contributor to the azimuthal shear wave anisotropy observed in sonic logs from some of the West Africa wells;
(2) Stress-induced velocity anisotropy is stress-path dependent;
(3) P-wave stress-induced anisotropy is stronger than S-wave stress-induced anisotropy;
(4) Vp/Vs ratio could increase or decrease with increasing stress;
(5) For dry samples, P-wave velocity is related to the stress component in the direction of wave propagation, whereas S-wave velocity is related to the average of the stress components in the directions of wave propagation and particle motion.
However, large uncertainties still exist in the exact amount of stress-induced velocity anisotropy. More measurement data are needed for better reservoir characterization where stress regimes are non-hydrostatic.
ABSTRACT: Many practical geomechanical problems require estimation of the in situ stress state at a given location beneath the earth's surface. These estimates are difficult to make because the stress distribution can depend heavily on topography, far-field tectonic forces, and local geologic history. Even when measurements of stress exist at one location, it can be difficult to extrapolate the measurements in order to estimate stresses at a second location.
Two examples of geomechanical problems requiring this type of stress estimation are: (1) the prediction of hydraulic fracture orientations, and (2) the specification of boundary conditions for geomechanical models of the effects of reservoir depletion or injection on processes such as drilling, fracturing, petroleum production, fluid or waste injection, etc.
This paper deals with the creation of calibrated models of in situ earth stress. The models are calculated on a finite element mesh using readily available finite element analysis software (ABAQUS, Visage, etc.). The models are loaded with their own weight and with additional loads and displacements as appropriate to the regional and local geology. Gravity loading (burial) and episodes of erosion and/or tectonic strain are applied to the model sequentially in a series of modeling steps that attempt to mimic the geologic history. The geologic processes are represented by loads and/or displacements applied to the model in its present-day geometric configuration. The mechanical properties assigned to rocks in the model are varied between modeling steps to account for differences in mechanical behavior during each of the important geologic episodes. Allowing the mechanical properties to evolve in this manner permits simple constituitive models (often linear elasticity) to be used in the description of relatively complex geologic situations. The rock mechanical properties during the geologic history are taken as parameters to be determined by calibration to known (measured) in situ stresses.
The resulting calibrated model developed in this manner provides an estimate of in situ stress at locations throughout the model rather than just at the locations for which in situ stress measurements have been made.
The method is illustrated with an example application in the Piceance Basin of Western Colorado. As part of a research project aimed at developing in situ methods to produce oil from oil shale, the technique was used to estimate the direction (vertical/horizontal) of hydraulic fractures created in the shallow Green River oil shale. Subsequently, the same in situ stress model has been used in conjunction with finer-scale finite element models (not covered in this paper) to estimate fracture gradients and the associated drilling hazards in pressure depleted Tertiary gas reservoir sands.