Monitoring hydraulic fracturing through the use of time-lapse, multicomponent seismic data and microseismic data, Wattenberg field, Colorado

2017 ◽  
Author(s):  
Thomas Davis
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Time Lapse ◽  
Wattenberg Field ◽  
Use Of Time ◽  
Microseismic Data ◽  
Multicomponent Seismic

Multidisciplinary Analysis of Hydraulic Stimulation and Production Effects within the Niobrara and Codell Reservoirs, Wattenberg Field, Colorado: Part 2 — Analysis of Hydraulic Fracturing and Production

2021 ◽  
pp. 1-53
Author(s):  
Matthew Bray ◽  
Jakob Utley ◽  
Yanrui Ning ◽  
Angela Dang ◽  
Jacquelyn Daves ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Time Lapse ◽  
Production Performance ◽  
P Wave ◽  
Production Data ◽  
Total Production ◽  
Wattenberg Field ◽  
Reservoir Models ◽  
3D Geomechanical Model

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.

Multidisciplinary Analysis of Hydraulic Stimulation and Production Effects within the Niobrara and Codell Reservoirs, Wattenberg Field, Colorado: Part 1 - Baseline Reservoir Conditions

2021 ◽  
pp. 1-41
Author(s):  
Matthew Bray ◽  
Jacquelyn Daves ◽  
Daniel Brugioni ◽  
Asm Kamruzzaman ◽  
Tom Bratton ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Time Lapse ◽  
Organic Content ◽  
P Wave ◽  
Seismic Survey ◽  
Fracture Density ◽  
Niobrara Formation ◽  
Reservoir Properties ◽  
Wattenberg Field

In the Wattenberg Field, the Reservoir Characterization Project at the Colorado School of Mines and Occidental Petroleum Corporation (Oxy) (formerly the Anadarko 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 Wishbone 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 (TOC). Petrophysical analysis of logs and core samples indicates that chalk intervals have high amounts of TOC (>2%) 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.

Predicting the azimuth of natural fractures and in-situ horizontal stress: A case study from Sichuan Basin, China

Geophysics ◽  
2021 ◽  
pp. 1-97
Author(s):  
kai lin ◽  
Bo Zhang ◽  
Jianjun Zhang ◽  
Huijing Fang ◽  
Kefeng Xi ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Sichuan Basin ◽  
Horizontal Stress ◽  
Seismic Attributes ◽  
Seismic Events ◽  
Natural Fractures ◽  
Microseismic Data ◽  
Maximum Horizontal Stress

The azimuth of fractures and in-situ horizontal stress are important factors in planning horizontal wells and hydraulic fracturing for unconventional resources plays. The azimuth of natural fractures can be directly obtained by analyzing image logs. The azimuth of the maximum horizontal stress σH can be predicted by analyzing the induced fractures on image logs. The clustering of micro-seismic events can also be used to predict the azimuth of in-situ maximum horizontal stress. However, the azimuth of natural fractures and the in-situ maximum horizontal stress obtained from both image logs and micro-seismic events are limited to the wellbore locations. Wide azimuth seismic data provides an alternative way to predict the azimuth of natural fractures and maximum in-situ horizontal stress if the seismic attributes are properly calibrated with interpretations from well logs and microseismic data. To predict the azimuth of natural fractures and in-situ maximum horizontal stress, we focus our analysis on correlating the seismic attributes computed from pre-stack and post-stack seismic data with the interpreted azimuth obtained from image logs and microseismic data. The application indicates that the strike of the most positive principal curvature k1 can be used as an indicator for the azimuth of natural fractures within our study area. The azimuthal anisotropy of the dominant frequency component if offset vector title (OVT) seismic data can be used to predict the azimuth of maximum in-situ horizontal stress within our study area that is located the southern region of the Sichuan Basin, China. The predicted azimuths provide important information for the following well planning and hydraulic fracturing.

Integration of surface seismic, microseismic, and production logs for shale gas characterization: Methodology and field application

2013 ◽  
Vol 1 (2) ◽  
pp. SB37-SB49 ◽  
Author(s):  
John Henry Alzate ◽  
Deepak Devegowda
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Data ◽  
Oil And Gas ◽  
Reservoir Characterization ◽  
Regional Scale ◽  
Field Application ◽  
Predictive Tool ◽  
Horizontal Drilling ◽  
Microseismic Data ◽  
Scale Characterization

Technologies such as horizontal drilling and multistage hydraulic fracturing are central to ensuring the viability of shale oil and gas resource development by maximizing contact with the most productive reservoir volumes. However, characterization efforts based on the use of well logs and cores, although very informative, may be associated with substantial uncertainty in interwell volumes. Consequently, this work is centered around the development of a predictive tool based on surface seismic data analysis to rapidly demarcate the most prolific reservoir volumes, to identify zones more amenable to hydraulic fracturing, and to provide a methodology to locate productive infill wells for further development. Specifically, we demonstrate that surface seismic attributes such as [Formula: see text]/[Formula: see text] crossplots can successfully be employed to quantitatively grade reservoir rocks in unconventional plays. We also investigate the role of seismically inverted Poisson’s ratio as a fracability discriminator and Young’s modulus as an indicator of total organic carbon richness and porosity. The proposed predictive tool for sweet spot identification relies on classifying reservoir volumes on the basis of their amenability to fracturing and reservoir quality. The classification scheme is applied to a field case study from the Lower Barnett Shale and we validate these results using production logs recorded in four horizontal wells and microseismic data acquired while fracturing these wells. The integration of seismic data, production logs, and microseismic data underscores the value of shale reservoir characterization with a diverse suite of measurements to determine optimal well locations and to locate hydraulic fracture treatments. A key advantage of the methodology developed here is the ease of regional-scale characterization that can easily be generalized to other shale plays.

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