Robert Meek

The role of seismic attributes in understanding the hydraulically fracturable limits and reservoir performance in shale reservoirs: An example from the Eagle Ford Shale, south Texas

As the importance of self-sourcing reservoirs continues to increase, it is more important than ever to evaluate rock properties that contribute to productive wells. It has become increasingly evident that in order to maximize potential returns, an integrated approach to shale play characterization is necessary to identify productive areas. Numerous criteria exist to characterize ultra-low permeability shale reservoirs and their associated resource potential; these include measures of organic richness, thermal maturity, lithologic heterogeneity, and formation brittleness. The latter, a descriptor of the geomechanical rock properties, can play a significant role in overall well performance and is commonly a key productivity driver. Thus, an understanding of the mechanical properties of the target section is fundamental for high-grading prospective areas, well placement design, and hydraulic stimulation effectiveness. Observation of geomechanical attributes extracted from seismic data in the Eagle Ford Shale captures changing mechanical properties indicative of strike-oriented lithologic facies changes. Using acoustic logs, core, and three-dimensional seismic data, we assess the mechanical contrast between Eagle Ford facies units and their effect on well performance. We use three-dimensional seismic data to map the structure and facies distribution in an area where identification of reservoir facies is a major challenge to development drilling. In this study, we demonstrate how Young’s modulus and density, inverted from three-dimensional seismic data, prove as effective discriminators for the purpose of identifying and mapping facies changes and establishing the hydraulically fracturable limits in areas where effective stimulation and proppant embedment in the formation during pressure drawdown is a concern. The result is an interpretation that identifies and uses the mechanical changes from three-dimensional seismic data attributes associated with the brittle carbonate-rich Eagle Ford facies to predict both the reservoirs hydraulically fracturable limits as well as the variability in well performance associated with proppant embedment. The changes in mechanical properties of the Eagle Ford facies are important in high-grading productive intervals in these ultra-low permeability rocks. We believe we can apply this method to other shale reservoirs where rock mechanics may play an important role.

3-D Finite Difference Modeling of Microseismic Source Mechanisms in the Wolfcamp Shale of the Permian Basin

Summary Microseismic data acquired during hydraulic stimulations are a key tool in determining well spacing, stimulation parameters, frac barriers, and natural and hydraulic fracturing relationships. In addition to hypocenter locations of the fracturing mechanism, attributes associated with the microseismic event including magnitude and P-S amplitude ratios provide valuable insight into the stimulation. These attributes can be used as weights in the calculation of microseismic derived stimulated rock volumes to determine effective draining areas. High velocity layers associated with carbonate debris flows are known to distort the seismic wave field and may have an effect on associated microseismic derived attributes. In this study we use a 3D elastic finite difference algorithm to model double couple and open tensile source mechanisms at different levels in the Wolfcamp shale of West Texas to determine the sensitivity of microseismic attributes and location to the geology and array configuration. Magnitude, P-S ratio, and event location from a horizontal and vertical array are examined. 3D snapshot movies of the different mechanisms show the complexity of the developing wave field and the location of nodal planes which could interfere with the position or observation of microseismic events. The modeling showed that attributes derived from a vertical array are more robust than attributes from a horizontal array. Attributes from events that occurred near high velocity layers such as carbonate debris flows may be less accurate than events that occurred in more consistent lower velocity layers. Event location and microseismic event attributes recorded from a vertical array are more accurate than events recorded from a horizontal array.

Leveraging Seismic Attributes to Understand the ‘Frac-Able’ Limits and Reservoir Performance in the Eagle Ford Shale, South Texas, USA

There are numerous criteria commonly used to characterize low-permeability shale reservoirs and associated resource potential; these include some measure of organic richness, thermal maturity, lithologic heterogeneity and brittleness. The latter, a descriptor of the geo-mechanical rock properties, plays a significant role in overall well performance and may be a key productivity driver; an understanding of this mechanical stratigraphy is also fundamental for well placement design and hydraulic stimulation effectiveness.

Estimation and Interpretation of Hydraulic Fracture Parameters from Microseismic Data in Shale Plays or Are Pairs of Horizontal Stimulated Wells Generating a More Complex Stimulation

Summary Pioneer Natural Resources in the Texas unconventional shale plays continues to utilize various microseismic technologies to better understand stress and pressure relationships that occur during hydraulic stimulation. Company-wide we have been primarily utilizing seismic monitoring equipment placed in the well bore, and to a lesser extent surface systems, to capture stimulation fracture geometries. These data are used to obtain a better understanding of the stress heterogeneity within the reservoir and completion as well as to optimize the well spacing. Over the past year we have monitored over 30 wellbores in Texas. In one study area, utilizing microseismic data as a proxy for pressure we have observed differences in fracture height, overlap of stages, magnitudes of events, number of events, as well as azimuthal changes within the microseismic data for various zones within our lower Permian age reservoirs. Pioneer has recently collected over twelve microseismic jobs (386 stages) using predominately one downhole acquisition system that allows for inter-comparisons of data in Reagan and Upton Co. Texas. We have minimized changes with the acquisition of the data, and the stimulation pumping parameters, so that we can track how changes to completion design are manifested in the rock. In some cases, our landing zones between wells have been modified so that we can assess the specific stress heterogeneity related to the geomechanical properties of different layers within the main pay zones. This broad foundation of data allows the individual to recognize differences within the stimulation as they relate to the geology or completion. Our datasets demonstrate the geometry of the pressure field as imaged with the microseismic data is variable and appears to be controlled by a number of factors including the local geology, completion practices, previous stimulations and adjacent production. Pioneer has mapped in detail the density of the microseismic event field, and noted variations in the height, length and widths of the hydraulic stimulation as well as the development of the pressure field away from the perforations. We have used the data to better understand well spacing and placement as well as define potential vertical fracture barriers for the Wolfcamp Formation. The knowledge gained from microseismic investigations, combined with reservoir models, have economic importance to the company as it plans future development of a shale oil play. Spacing decisions directly impact well count and capital deployed by the firm to maximize development of reserves.