Scalable workflow illustrates formation pressure variability across a basin.

For geologists and engineers, accurate reservoir characterization is often the difference between economic success and failure. One of the main tools to reduce reservoir uncertainty is drill stem tests (DSTs) which provide key information about formation pressure and fluid characteristics of the reservoir. Using TGS Well Data processing and mastering, DST data can now be efficiently evaluated at scale. We show a regional and formation level workflow in the Delaware Basin (Pecos, Reeves, Culberson, Loving, Ward, and Winkler Counties in Texas, and Eddy and Lea Counties in New Mexico) to determine a pressure gradient for hydrocarbon production forecasting models and illuminate depleted or underdepleted zones for water disposal and re-completion, respectively.

TGS DST data shows that in the Delaware Basin, formations are generally underpressured from the surface to -7,500 ft, overpressured between -7,500 to -10,000 ft, and normally pressured below -10,000 ft. When plotted spatially, pressure gradients from DSTs show how pressure regimes vary across a basin within individual formations, which becomes critical when determining absolute pressure values. In the Devonian, for example, using the pressure gradient in the basin center of 0.49 psig/ft instead of the northwest shelf at 0.39 psig/ft would cause a formation pressure error of 1,000 psig and could result in an overestimation of production volumes. Pressure gradients can also illuminate depleted or underdepleted zones by comparing pressures from the DSTs to present-day. Depleted oil and gas zones, along with existing underpressured zones, are prime candidates for water disposal. Underdepleted zones, on the other hand, could be overlooked opportunities, potentially becoming economical with new wells or re-completions. DSTs hold the answer to those questions.

Read the full Well Intel article here.