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Joint PP and SS seismic inversion enhances the ability to characterize reservoir properties of the Bakken petroleum system. Joint PP and SS inversion improved the accuracy of inversion results over P-wave simultaneous inversion by 10 percent. An advantage of multicomponent seismic data recording over P-wave acquisition alone is the ability to improve our inversion processes to provide improved reservoir characterization.
Presentation Date: Tuesday, October 16, 2018
Start Time: 9:20:00 AM
Location: Poster Station 7
Presentation Type: Poster
This paper presents construction and validation of a reservoir model for the Niobrara and Codell Formations in Wattenberg Field of the Denver-Julesburg Basin. Characterization of Niobrara-Codell system is challenging because of the geologic complexity resulting from the presence of numerous faults. Because of extensive reservoir stimulation via multi-stage hydraulic fracturing, a dual-porosity model was adopted to represent the various reservoir complexities using data from geology, geophysics, petrophysics, well completion and production. After successful history matching two-and-half years of reservoir performance, the localized presence of high intensity macrofractures and resulting evolution of gas saturation was correlated with the time-lapse seismic and microseismic interpretations. The agreement between the evolved free gas saturation in the fracture system and the seismic anomalies and microseismic events pointed to the viability of the dual-porosity modeling as a tool for forecasting and future reservoir development, such as re-stimulation, infill drilling, and enhanced oil recovery strategies.
This paper presents construction and validation of a reservoir model for the Niobrara and Codell Formations in Wattenberg Field of the Denver-Julesburg Basin. Characterization of Niobrara-Codell system is challenging because of the geologic complexity resulting from the presence of numerous faults. Because of extensive reservoir stimulation via multistage hydraulic fracturing, a dual-porosity model was adopted to represent the various reservoir complexities using data from geology, geophysics, petrophysics, well completion and production. After successful history matching two-and-half years of reservoir performance, the localized presence of high intensity macrofractures and resulting evolution of gas saturation was correlated with the time-lapse seismic and microseismic interpretations. The agreement between the evolved free gas saturation in the fracture system and the seismic anomalies and microseismic events pointed to the viability of the dual-porosity modeling as a tool for forecasting and future reservoir development, such as re-stimulation, infill drilling, and enhanced oil recovery strategies.
Curia, David (Wintershall) | Korotkov, Ilya (Unified Geosystems LLC) | Galikeev, Tagir (Unified Geosystems LLC) | Davis, Tom (Colorado School of Mines) | Wheeler, Rick (Geospace Technologies Corporation)
A small static cable-less acquisition spread of 600 three-component (3C) receivers was laid during a larger P-wave seismic acquisition effort in Argentina (Figure 1).
Non-symmetrical acquisition system raised some challenges during processing, but they were successfully overcome using the larger and denser P-wave survey.
Acquisition parameters and conditions
A large dense wide-azimuth PP survey was shot using Vibroseis as a source. PS acquisition was added with a cable-less system utilizing 3C receivers. Subject of this paper is the latter, PS survey. Distance between receivers was set at 120 meters, while source distance was half of that, at 60 m. Distance between source lines was 300 m and receiver line distance was double of the source lines, at 600 m. Theoretically, converted wave surveys should have denser receiver line spacing (at least half of the source line spacing) and the receiver distance should be smaller than that of the source distance (half or a quarter) due to CCP shift towards receivers. However, the acquisition area is very forgiving and is characterized by high vector fidelity, relatively simple near surface (statics regime is not very complicated) and subhorizontal geometry of seismic reflectors.
Planting of three component geophones was done with a special planting tool and horizontal component H1 was oriented to 0 degrees (magnetic North). Soil conditions were excellent and guaranteed tight coupling of geophones (see Figure 2).
Figures 3 and 4 illustrate true fold maps, with all zero and bad traces removed, for PP and PS data. Fold map for PS survey was computed using asymptotic binning with gamma=2. Several binning and stacking tests were performed for gamma=[1.5; 5]. Gamma=2 was selected due to the homogeneous nature of the fold map, preserving structural features evident on PP dataset and using Vp/Vs ratio from wells.
Unconventional reservoirs are multivariate problems requiring integration of data across multiple disciplines. Microseismic data recording hydraulic fracture treatments in the Niobrara Formation in the Denver Basin are no exception. Microseismic data are the real time recording of the subsurface reaction to stimulation and the stimulation is affected by the lithology and structure penetrated by the wellbore. Microseismic data are often not studied at the wellbore scale, yet this is where the stimulation initiates. Integrating both cluster analysis and horizontal borehole imagery can aid in the interpretation of microseismic data.
Due to the complex stratigraphy and structure in the Denver Basin, horizontal wells rarely target a single lithology. The varying lithology targeted by the wellbore could lead to stimulation heterogeneity and recorded via microseismic data. Vertical well cluster analysis was applied to one horizontal well to quantify the number of stage locations per lithology and how microseismic magnitude is affected by the lithology at each stage location. The number of natural fractures in each lithology was also quantified. In addition, horizontal borehole imagery identified natural and drilling induced fractures which aided in the interpretation of microseismic data heterogeneity. These interpretations can help understand how lithology and structure control stimulation heterogeneity and thus recorded by microseismic data.
Microseismic magnitude was found to be 43% higher in stage locations within higher Young's Modulus (chalk) rock compared to stage locations within lower Young's Modulus (marl) rock. In addition, chalk was found to be more naturally fractured than marl, although the marl still contains natural fractures. Finally, image log analysis showed linear microseismic trends are due to lack of natural fractures and are affected by and parallel maximum horizontal stress (σH) whereas clustered microseismic trends are due to abundant, conjugate natural fractures.
The research presented is a part of a joint research effort between the Reservoir Characterization Project and Anadarko Petroleum Corporation. The Wattenberg Project, Phase XV, began July 1, 2013 with the main objective of the Wattenberg Project is to guide well spacing and completions to improve ultimate hydrocarbon recovery. Unconventional reservoir development is dependent upon integration of data and multiple disciplines to solve multivariate problems. This research focuses on integrating both vertically derived, horizontally applied cluster analysis and horizontal borehole imagery to identify how geological heterogeneity influences completions and thus microseismic data recording the stimulation along the wellbore.
Time-lapse, multicomponent seismic data were acquired in conjunction with microseismic monitoring during hydraulic fracture stimulation of two horizontal wells at Pouce Coupe Field, Alberta. Seismic monitoring showed that fracture complexity was introduced by the interaction of the hydraulic fracture stimulation with the natural fracture network in the reservoir. Seismic monitoring is essential for optimizing completions and for evaluation of refracturing potential.
Fracture complexity occurs when the hydraulic fracturing process causes the interaction of the hydraulic with natural fractures. Complexity can be created when stresses and natural fractures are favourable for generating multiple fracture sets. Generally, if we can tell where the natural fractures are prior to the well drilling and completions, we can take advantage of the natural fractures to increase the effective permeability and create greater conductivity to the well bore.
Microseismic data cannot portray all the details to allow a complete understanding of stimulation behaviour. By integrating microseismic data with surface multicomponent seismic monitoring, we can develop a broader understanding of how hydraulic fracture treatments create fracture complexity.
Figure 1 shows linear trends of microseismicity associated with the stimulation of two horizontal wells at Pouce Coupe Field. One could assume that the longer the linear trend, the greater the surface area; therefore the better well should be the northern well (07-07). In fact, this well is the poorer producer (Figure 2). Through combined microseismic and surface time-lapse multicomponent seismic monitoring, it was determined that well 02-07 has greater fracture complexity in the near well bore area, giving rise to better production.
There are natural fractures in the formation as evidenced from inversion analysis of the shear wave data (Figure 3). Differences in the velocity of split converted shear waves within this reservoir interval occur in the Montney C unit. The velocity differentials are directly proportional to fracture density. Increased fracture complexity gives rise to better production for the 02-07 well.
Pore pressure and CO2 saturation changes are important to detect and quantify for maximizing oil recovery in Delhi Field. Delhi Field is a enhanced oil recovery (EOR) project with active monitoring by 4D multicomponent seismic technologies.
Dynamic rock physics modeling integrates the rich dataset of core, well logs, thin sections and facies providing a link between reservoir and elastic properties. We use Vp/Vs ratio and acoustic impedance to predict pore pressure and CO2 saturation changes in the reservoir. PP and PS seismic data are used to jointly invert for Vp/Vs ratio and acoustic impedance. Combination of the inversion results from the monitor surveys of June 2010 and August 2011 provides impedance and Vp/Vs percentage differences. The time-lapse inverted response fits the predicted dynamic models (calibrated at the wells).
Dynamic reservoir characterization adds value in this stratigraphic complex reservoir composed by the Paluxy and Tuscaloosa Formations. The results indicate that reservoir heterogeneities and pore pressure gradients control the CO2 flow. Paluxy injectors 148-2 and 140-1 shows CO2 is moving downdip following a distributary channel and induced by differential pressure from an updip injector or a barrier caused by a heterogeneity in the reservoir. This fact makes reservoir monitoring important for hydrocarbon recovery and reservoir management at Delhi Field.
Krahenbuhl, Richard A. (Center for Gravity, Electrical & Magnetic Studies (CGEM), Colorado School of Mines) | Li, Yaoguo (Center for Gravity, Electrical & Magnetic Studies (CGEM), Colorado School of Mines) | Davis, Tom (Reservoir Characterization Project (RCP), Colorado School of Mines)