In the Wattenberg Field, the Reservoir Characterization Project at the Colorado School of Mines and Occidental Petroleum Corporation collected time-lapse seismic data for characterization of changes in the reservoir caused by hydraulic fracturing and production in the Niobrara Formation and Codell Sandstone member of the Carlile Formation. We have acquired three multicomponent seismic surveys to understand the dynamic reservoir changes caused by hydraulic fracturing and production of 11 horizontal wells within a 1 mi2 section. The time-lapse seismic survey acquisition occurred (...) immediately after the wells were drilled, another survey after stimulation, and a third survey after two years of production. In addition, we integrate core, petrophysical properties, fault and fracture characteristics, as well as P-wave seismic data to illustrate reservoir properties prior to simulation and production. Core analysis indicates extensive amounts of bioturbation in zones of high total organic content. Petrophysical analysis of logs and core samples indicates that chalk intervals have high amounts of TOC and the lowest amount of clay in the reservoir interval. Core petrophysical characterization included X-ray diffraction analysis, mercury intrusion capillary pressure, N2 gas adsorption, and field emission scanning electron microscopy. Reservoir fractures follow four regional orientations, and chalk facies contain higher fracture density than marl facies. Integration of these data assist in enhanced well targeting and reservoir simulation. (shrink)

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Using synthetic and field data examples, we find that joint prestack amplitude variation with angle inversion of PP- and PS-wave data can significantly improve estimation of P-impedance, S-impedance, and density. For reservoir characterization, improvements in these parameters can better identify reservoir rock and fluid properties. For reservoir monitoring, time-lapse changes in P-impedance, S-impedance, and density can lead to inversion of saturation and pressure changes. We see that in the joint inversion, 4D S-impedance is better estimated and not coupled to 4D (...) P-impedance. These claims are first demonstrated on synthetic data, and then shown on an onshore unconventional play from Colorado and offshore 4-D-4C data set from the North Sea. Joint inversion of PP- and PS-wave data requires a higher level of care compared with PP-waves because the two wave modes need to be acquired, processed, and merged properly. This has diminished the use of converted waves in the past. However, modern acquisition and processing on land and offshore data make this technology quantitatively more accurate and realizable. As such, we also provide best practices for a successful project. We indicate that joint inversion can lead to a larger chance of success in placing exploration and development wells. (shrink)

Compensating for the effects of an acquisition footprint can be one of the most daunting problems when using seismic attributes for quantitative interpretation. This is especially true for unconventional plays because they are on land with accompanying irregular acquisition geometries. Additionally, in such plays, the physical property changes are often small, making the seismic amplitude fidelity critical. We have developed a methodology that integrates a 1D elastic prestack synthetic model with 3D acquisition geometry to accurately model the seismic footprint produced (...) by irregular or insufficient sampling of primary reflectivity. The stacked amplitude response of the modeled survey is then used to mitigate the poststack footprint on the field seismic. Modeling and removing this element of the acquisition footprint quantitatively improve the interpretive value of the mapped seismic amplitudes. In our study area, correlation between seismic amplitudes and well control increased from an [Formula: see text] of 0.053 before correction to an [Formula: see text] of 0.629 after. Our approach is especially effective in situations in which the spatial frequency of the footprint overlaps that of the geologic signal. Geological feature: Acquisition related seismic amplitude artifacts Seismic appearance: Smoothly varying amplitude changes Alternative interpretations: Bed thickness variation Features with similar appearance: Carbonate porosity Formation: Niobrara Formation, mixed chalks and marlstones Age: Upper Cretaceous Location: Wattenberg Field, Denver Basin, north central Colorado Seismic data: Joint acquisition between Anadarko Petroleum and Colorado School of Mines, Reservoir Characterization Project Analysis tools: Elastic prestack seismic modeling. (shrink)

Enhanced hydrocarbon recovery is essential for continued economic development of unconventional reservoirs. Our study focuses on dynamic characterization of the Niobrara and Codell Formations in Wattenberg Field through the development and analysis of a full integrated reservoir model. We demonstrate the effectiveness of hydraulic fracturing and production with two seismic monitor surveys, surface microseismic, completion data, and production data. The two monitor surveys were recorded after stimulation, and again after two years of production. Identification of reservoir deformation due to hydraulic (...) fracturing and production improves reservoir models by mapping non-stimulated and non-producing zones. Monitoring these time-variant changes improves the prediction capability of reservoir models, which in turn leads to improved well and stage placement. We quantify dynamic reservoir changes with time-lapse P-wave seismic data utilizing pre-stack inversion, and velocity-independent layer stripping for velocity and attenuation changes within the Niobrara and Codell reservoirs. A 3D geomechanical model and production data are history matched, and a simulation is run for two years of production. Results are integrated with time-lapse seismic data to illustrate the effects of hydraulic fracturing and production. Our analyses illustrate that chalk facies have significantly higher hydraulic fracture efficiency and production performance than marl facies. Additionally, structural and hydraulic complexity associated with faults generate spatial variability in a well’s total production. (shrink)