Marco Perez

Seismic petrophysics and isotropic-anisotropic AVO methods for unconventional gas exploration

Exploration and drilling for natural gas in North America has moved radically away from conventional reservoirs to focus on unconventional reservoirs such as tight gas sands and shales. These reservoirs have low porosity and near-zero permeability with gas stored in natural fractures and within the matrix porosity. Economic gas production requires hydraulic fracture stimulation to open connections to existing natural fractures or matrix porosity, and successful stimulation depends on the formations geomechanical brittleness being capable of supporting extensive induced fractures. However, despite adequate stimulation, significant variations exist between wells in expected ultimate recovery (EUR) due to the heterogeneity of these resource plays. Consequently, predicting natural fractures or fracture-prone “sweet spots” is essential to optimize development of such plays.

Developing Templates For Integrating Quantitative Geophysics And Hydraulic Fracture Completions Data: Part I - Principles And Theory

Summary Unconventional resource plays require that geophysicists redefine the value seismic brings for economic development of these assets. A large part of developing resource plays comes from optimizing engineering practices. Understanding that seismic data contains information regarding resource potential, rock properties, in-situ stress, reservoir pressure and fracture intensity/orientation allows for educated and optimized large scale development plans. The heuristic interpretation templates provided herein outline a method to interpret seismic data for estimated ultimate recovery (EUR) and the important physical properties for hydraulic fracturing all of which provide insight for optimizing completion efforts.

Unconventional resource evaluation and applied geophysics utilising LMR

Over the last decade the oil and gas industry has delivered conceptual and technical changes that have entirely changed the fundamentals of natural gas supply in North America. Underpinning the step change in natural gas reserves and market ready supplies has been the change in the perception of fine-grained, organic rich rocks (i.e. shales - although of course not all shales are organic rich). No longer are such rocks viewed only as source and seal candidates, but also as source rock reservoirs or shale gas plays. Although the geological continuity of shale gas plays have led to the production-line style operations seen across North America in mature unconventional plays, it is not “factory-style” efficiency improvements in isolation that allow the economic exploitation of shale gas. The large number of fit-for-purpose technologies, introduced by operators and service companies, has been critical in increasing production while keeping costs flat and/or reducing costs and time to production. 3D seismic data play a key role in unconventional developments as a unique look-ahead dataset. The role of seismic, however, has evolved to be far more than simply a tool for mapping major structures. For example, through AVO inversion we are able to make predictions regarding elastic properties of the formations of interest. The integration of AVO inversion data with engineering and rock physics data is providing new avenues of data exploitation. Seismic data are also being used to predict closure stress and stress anisotropy, which can be calibrated with data and analysis from hydraulic fracturing. Additionally, the integration of surface seismic data with microseismic provides a means of fine-tuning the estimation of stimulated rock volume.

Finite-difference methods for estimating traveltimes and raypaths in anisotropic media

Summary Finite-difference solutions to the eikonal equation have been determined by a variety of methods. Solutions to isotropic methods have been extended to include anisotropic media. The following scheme computes traveltimes based on a finite-difference approximation to the eikonal equation for transversely isotropic (TI) and isotropic media (a special case of TI media). The method expands along wavefronts by following minimum traveltimes to honor causality. The proposed method is valid for weak to moderate levels of anisotropy as defined by Thomsen’s parameters. A method to determine raypaths using the reciprocity principle for the purpose of tomography is also presented.