How can you gain a deeper understanding of fractures? How can you find sweet spots? You’ll find answers at the short course, Seismic & Microseismic in Fine-Grained Petroleum Systems on September 21 in Houston at the Fall Education Conference. Don’t delay - Log Analysis of Shaly Sandstones is taught by George Asquith, a leading expert in the field, and will be offered in Houston on September 21, at the AAPG Fall Education Conference.
One of the better established tools for understanding fracture networks pre-microseismic is 3D Azimuthal Analysis. 3D Seismic datasets acquired with full azimuth coverage offer the potential to predict the local stress field or fracture potential using changes in velocity or amplitude as a function of azimuth. The expectation is that velocity and amplitude should vary with azimuth across a fractured reservoir – faster velocity and weaker or stronger reflectivity in locally stress or fractured sections. For nearly a decade the industry has been developing tools to extract this information from seismic data and comparisons with borehole measurements have become increasingly favorable. Azimuth products from 3D seismic offer the chance to better orient horizontal wellbores to optimize fracture stimulation. A byproduct of the azimuthal processing is a more reliable input dataset to elastic inversion. Seismic attributes estimating changes in Young’s Modulus, Poisson Ratio and Density offer additional tools for Sweet Spot characterization and mapping. Fracture and rock property confirmation from microseismic fracture network analysis is still in its early stages but some examples have been published.
Topic 2: Using Surface Microseismic to Image the Permeability Structure of Shale Gas and Shale Fluids Reservoirs (morning)
Summary of Application: Industry has come to expect that microseismic technology has only one product to offer: a 3D map of individual hypocenters that show the growth of hydraulic fractures for each stage of a frac job. Both down-hole and surface arrays have been used, each with their own strengths and limitations. After some initial enthusiasm for the technology, systemic problems have been noted in the literature that question the viability of this technology in deep and unconventional settings. A new method – Tomographic Fracture ImagingTM has been developed that uses the time dimension inherent in the data to map out movement of pressure responses at the frac stage, along the near-wellbore rock volume and even in the far-field reservoir rock volume. Examples from shale gas and liquids reservoirs will be presented.
Topic 3: Integration of Seismic, Microseismic and Engineering Data Provides Insight into Well Prospectivity and Productivity: Examples from the Eagle Ford (afternoon)
Summary of Approach: Regional and local analysis of the Eagle Ford using production data and Global Geophysical’s vast multi-client seismic data library indicates substantial lateral and vertical heterogeneity throughout this play. This observation suggests the following questions:
- Can geoscience and engineering attributes be identified that are indicators of well performance?
- Can these be used to create a predictive model for well prospectivity and productivity?
The workflow demonstrated here is a multi-disciplinary integration of the geophysical, geological, petrophysical and engineering data that combines numerous datasets together, identifies the specific data types that are essential to hydrocarbon production, and produces a model that not only identifies the most prospective areas for drilling, but also provides quantitative estimates of the cut-off values of the most important factors. The integration of seismic attributes and petrophysical analyses in a 3D geological model allows for the description of rock quality, stress conditions and fluid distribution in both lateral and vertical dimensions. Furthermore, the integration of seismic and microseismic analyses provides insight into the dynamic response of the resource to stimulation and production. Properly applied, this workflow can significantly reduce drilling risk and aid in the optimization of a drilling and completion program. The work presented here also demonstrates the value that seismic and microseismic data can bring to resource characterization and development planning of unconventional resources.
DATES: September 21, 2012
LOCATION: Norris Conference Center, City Centre Location, Houston, TX
TUITION: Member: $475.00 • NonMember $475.00
(if purchased individually)
Registration for the entire week is $1,795 for members, $1,895 nonmembers. Goes up to $1895/$1995, and/or individual course prices increase by $50/course day after 8/20/2012. Course notes, refreshments and lunch buffet included.
No refunds for cancellations after 8/20/2012.
CONTENT: .7 CEU What is a CEU?
Upon completion of this course, participants will be able to:
- Understand the values and limits of surface vs down-hole microseismics;
- Learn what microseismics show us about hydro-fracs and their interaction with in situ fracture systems;
- Understand the differences in querying near-well SRV data vs field-wide permeability systems
Last 5 posts by Susan Nash
- AAPG Pre-Conference Short Courses (URTeC) - July 25th, 2014
- Granite Wash and Pennsylvanian Sand Forum - July 7th, 2014
- Latitudinal Controls on Stratigraphic Models and Sedimentary Concepts: An AAPG/SEPM Hedberg Research Conference - July 7th, 2014
- Folding, Thrusting and Syntectonic Sedimentation: Perspectives from Classic Localities of the Central Pyrenees - June 24th, 2014
- Complex Carbonate Reservoirs: Sedimentation and Tectonic Processes - The Impact of Facies and Fractures on Reservoir Performance - June 23rd, 2014