Abstract

Delineating the sweet spots, areas where well performance will be most economic, is a critical issue for both the exploration and the development of gas-shale reservoirs. Two simple methods to aid identification and mapping of sweet spots using density and neutron logs are presented in this chapter. The first method is apparent shale porosity*thickness (PHIas*H) maps, derived from the raw density porosity log, can be used to qualitatively assess and map reservoir quality and quantity. What is unique in our approach is that no rock calibration is done to correct for total organic carbon (TOC), a common industry practice. The second method is the neutron gas effect. In many gas shales, the neutron and density logs exhibit approach sometimes to the point of a crossover response, similar to the well-documented effect in gas reservoirs in sandstone or carbonate. All currently commercial gas shales in North America exhibit the gas effect, suggesting that it can be used as a direct detection technique for commercial gas shale.

The PHIas*H maps presented in this chapter were constructed in 2008 and based on density/neutron logs from vertical wells existing at that time for three emerging plays: Haynesville, Eagle Ford and Marcellus shales. For each of these plays, the initial potential (IP) of horizontal wells drilled over the last three years that have now defined the productive sweet spots of each of the trends are plotted on the PHIas*H maps. The location of highest IP horizontal wells show good correlation with the mapped PHIas*H thicks, the predicted sweet spots, and clearly demonstrate the utility of this mapping technique.

It should not be too surprising that PHIas*H maps can be used to predict sweet spots since they are based on the density log, which is the log that underpins most porosity and original-gas-in-place petrophysical calculations and maps. But the efficacy of using PHIas*H utilizing the uncalibrated density log porosities is surprising and calls into question whether current quantitative petrophysical methods produce a truly more quantitative answer. Many workers have questioned the accuracy of some of the most basic core-derived measurements in gas shales, in particular, porosity and water saturation. Calibrating logs to suspect core-derived parameters and creating gas-in place maps presents a significant challenge. Perhaps of even greater concern is the issue of scale. Ion-milled scanning electron microscopic images of gas-shale reservoirs show a heterogeneous pore network on a 10- to 100-nm scale, yet down-hole logs sample at a frequency of, 0.5 ft (15.4 cm), a six- to seven-order-of-magnitude difference. Expecting quantitative assessments from current logging tools and rock calibration may be optimistic and suggests that current techniques for in-place gas resource evaluations may need a fundamental reassessment.