Summary Time-lapse, multicomponent seismic data were acquired in conjunction with microseismic monitoring during hydraulic fracture stimulation of eleven horizontal wells at Wattenberg Field, Colorado. By integrating microseismic data with surface multicomponent seismic monitoring, we can develop a broader understanding of how hydraulic fracture treatments can be monitored in the subsurface. INOVA's cableless system, the Hawk, was used to acquire the surveys. Vibrators (P and S-wave) was used as the source for the multicomponent data acquisition. Introduction Anadarko Petroleum Corporation (APC) and the Colorado School of Mines Reservoir Characterization Project (RCP) teamed up to conduct an integrated dynamic reservoir characterization study of a portion of Wattenberg Field, Colorado (Figure 1).
Characterizing anomalies detected on seismic-generated attributes is crucial in interpreting any formation of interest. Consequently, a representative rock physics model is needed to determine the effect of petrophysical properties on the seismic response. The developed workflow presented in this paper utilizes differential effective medium theory, Hudson's model for cracked media, and Gassmann's fluid substitution equation for anisotropic rock to represent horizontal transverse isotropic (HTI) in a reservoir rock. The rock physics model provides the ability to predict vertical incidence velocity variation for the compressional and two principal shear wave components (fast and slow) due to changes related to mineralogy, porosity, water saturation, fracture density, and pressure at the target unit. The forward modeling process involves varying a single parameter over its anticipated range, then determining the density and compressional and shear velocities. Although the presented petrophysical workflow is applied to Ordovician Red River Formation within Cedar Creek Anticline in the Williston Basin, it can be extended to other formations with the need to modify certain assumptions.
Presentation Date: Tuesday, September 26, 2017
Start Time: 10:35 AM
Location: Exhibit Hall C/D
Presentation Type: POSTER
Details of estimating these approximate PPDs can be found in Padhi and Mallick (2014) and Li and Mallick (2015). The dashed curves, shown in Figure 3 denote the search windows used for estimation each model parameter. Notice from Figure 3 that the peaks of these estimated PPDs were connected to obtain an estimate for each model parameter. Also notice although we used a wide window for estimating each model parameter, the estimated PPD functions are very wellconstrained. The sliding window inversion allowed good constraints on the model parameter estimates from shallow to deep, which, in turn, is clearly reflected in these PPD estimates. Figure 2: An example of the 3-component VSP data used in this inversion study.
Optimizing the production of unconventional tight gas and oil resources is dependent on the ability of an operator to understand geologic heterogeneity within the reservoir prior to drilling and completing wells. At Pouce Coupe Field, Alberta, azimuthally sectored converted wave (PS) seismic is used to characterize the fracture network of the Montney Formation through amplitude inversion. Significant fracture heterogeneity is observed in the small study area that shows a good correlation to stage-by-stage production. Integration of the results with micro-seismic, compositional analysis, and development history of the field enables a more complete understanding of the reservoir and the properties that drive production. It is demonstrated that storage capacity and brittleness combined with a network of permeability enhancing fractures provide the best conditions for economic success, and all these properties can be de-risked through the joint application of PP and PS seismic.
Understanding the lateral heterogeneity of tight shales plays prior to hydraulic fracturing is important for hydrocarbon production and recovery. Using the multicomponent seismic data set from Pouce Coupe Field, Alberta, we set out to try to predict the rock fabric of the Montney Shale. Our objective in this study is to understand the lateral and vertical heterogeneity using multi-attribute analysis of wells integrated with multicomponent seismic data focusing on rock fabric. The result is a consistent methodology beginning with a cluster analysis of the logs that are affected by composition, combined with the results from post-stack and pre stack inversion of the baseline of 4D seismic data to determine elastic rock properties, to predict areas of better rock quality. The integration of this analysis with production data of two horizontal wells in the area shows that the composition itself has a major influence on the rock quality of the Montney C and D units. The combined interpretation of this work with an understanding of the natural fracture system and the stress state of the reservoir can then provide a rock quality index (RQI) that can aid in future exploration and operational development of shale reservoirs worldwide.
The Reservoir Characterization Project at Colorado School of Mines has been working in conjunction with Talisman Energy Inc. since 2009 to analyze two hydraulic stimulations in the Montney Shale play in Canada. Specifically, the project originates from the monitoring of two five stage horizontals from the Pouce Coupe area in North-Western Alberta. The completions were monitored using a variety of microseismic methods (surface, shallow water well and downhole). This paper will focus on analysis of the downhole arrays that were used to monitor the hydraulic stimulations.
Amplitude ratios of seismic waves (P, Sh and Sv) can be used to estimate focal mechanism solutions in areas where a full moment tensor inversion is not effective. In this case, due to the limited azimuths available from the two recording arrays, amplitude ratios are seen as a more robust tool to ascertain these mechanism solutions. A technique is implemented to model the radiation patterns from simple end member mechanisms (pure double-couple or tensile sources) to match the microseismic amplitudes recorded by the downhole arrays. Similar to previous studies in this area, this work finds that the superior solution is a vertical strike-slip mechanism striking at an angle close to that of maximum horizontal stress (N40°E) within the reservoir.
Previous amplitude ratio work has highlighted that microseismic events appear to be shear dominated in their amplitudes and has theorized that the events we record are an interaction between the hydraulic fracture and existing planes of weakness (natural fractures, bedding planes etc.). The focal mechanism solutions drawn from this work are compared with other natural fracture determination methods (time-lapse shear wave splitting and FMI logs) to see if there is any correlation. Results show that these solutions tie well with the natural fracture directions determined by the shear wave splitting study. The shear wave splitting map is consistent with the strike directions of the focal mechanism solutions in areas where microseismic events were detected. The FMI logs show near vertical fractures striking at angles close to that resolved by the amplitude analysis, but with variations from the dominant trend. This is interpreted to be an indication of the complication of fracture sets present in a naturally fractured reservoir. This study extends previous work in this area and also provides another example of the use of amplitude ratios in analyzing microseismic data without the need for high receiver coverage and costs.
A multicomponent time-lapse survey was acquired by Talisman Energy in early 2008, along with microseismic of various methods, with the intent of delineating stimulated rock volume in an unconventional Montney reservoir. In an effort to determine the expected reservoir time-lapse response to an increase in fluid pressure due to the fracture stimulation, static moduli and velocity measurements in core data were analyzed. Due to the impermeable nature of the reservoir, only a very subtle time-lapse change is predicted from the core data, and only if full pressurization of the reservoir is achieved. Fluid flow modeling, however, shows full pressurization of the reservoir expected only in the immediate vicinity of the induced fracture, and therefore little or no time-lapse response is expected in the P-wave domain, and none is observed, Finally, modeling of the local reservoir stress regime before and after the induction of a fracture indicates a significant change is expected, one that is seen through analysis of shear-wave splitting. The time-lapse response in birefringence shows a correlation to downhole microseismic monitoring of the fracture extents.