Introduction To February Focus: Reservoir Geophysics

Geophysics has a wide range of uses within the oil and gas industry. In the broadest sense, geophysical data is a representation of the earth’s interior. Geophysicists design experiments to ascertain properties such as structure, geomorphology and even mapping hydrocarbon reservoirs. Reservoir geophysics can mean a number of different things ranging from using seismic data to detect and predict reservoir presence to quantifying lithologic variations to monitoring stimulation of tight reservoirs. Each of these uses are important for exploration and/or development of conventional and unconventional reservoirs. Continuing developing and perfecting seismic techniques and increasing accuracy of predictions is at the core of good geophysical practice. To that end, this issue of the RECORDER presents four Focus articles illustrating the various techniques used to explore and monitor hydrocarbon reservoirs.

The first article, by Blackwood and Thorpe, reviews seismic exploration efforts in the Flemish Pass Basin and demonstrates that in the utility of reflection amplitude and their inversions towards estimating reservoir presence and fluid fill. Using three different wells, each containing a porous sand reservoir, Gassmann’s equation is used to model amplitude variability as a function of fluid. The exercise is important as it outlines expectations for interpretation of reflection data; what can be reliably mapped and what is more ambiguous. Their impedance analysis shows the reservoir elastic parameter variability and the impact of hydrocarbon. The authors investigate elastic impedance as a proxy for quantitative inversions and show that in offshore environments they are quite useful.

The second article, by Holt and Westwood, suggests a quantitative rock physics method for estimating mineralogy in low porosity unconventional reservoirs. Elastic properties in rocks can vary as a function of mineralogy, porosity, stress, fabric, fluid and TOC. Assuming small variations in porosity and fluid, any elastic variation can attributed to changes in mineralogy. Three dominant mineral groups, silicates, clays and carbonate are then estimated from well log data from two different unconventional plays with accuracy. In this way interpretation templates are constructed that can be applied to inversion data. The success of such a workflow is dependent on the quality of the elastic parameter estimate.

Akram and da Silva Paes outline best practices for project management of microrseismic acquisition. The monitoring hydraulic stimulation of reservoirs provides valuable information which can only be obtained through careful planning. Understanding the deliverables and setting expectations is key in a successful microseismic program. Involving the entire geotechnical team and designing the appropriate acquisition geometry by integrating local geologic information optimizes the experiment and assures the project scope has been fulfilled.

The final article by Chopra discusses the merits of inverting prestack seismic data that has been depth migrated. Since inversion consists of estimating elastic properties from reflection amplitudes, it is of critical importance that the reflection amplitude be accurately migrated to correct subsurface location. PSDM is best suited to achieve this as it accounts for vertical and lateral velocity variations, present in even unstructured geology. One of the drawbacks inverting depth migrated data is the resulting spatial and temporal stretch, a result of the time to depth conversion. The two methods suggested consist of allowing a single wavelet to be stretched by a velocity function or by a pseudo-depth transformation. All of this is possible now, since the computational efforts required for prestack depth migration (PSDM) are now manageable as algorithms are more efficient and computer power has increased.