In 2013, Michael Celia and colleagues initiated a new line of inquiry focused on leakage of methane along old wells, and on development of models to predict fluid movement and potential leakage associated with hydraulic fracturing and shale-gas production. This work follows naturally from their earlier and ongoing research focused on CO2 injection and the possible leakage scenarios associated with CCS (see “Models for CO2 injection, migration and leakage” below).
Field measurements of gas leakage from abandoned wells
A new field measurement program, led by senior graduate student Mary Kang, involves direct measurements of methane fluxes along old abandoned wells in northwestern Pennsylvania. Mary and others from Princeton made a total of four rounds of measurements in the last year, involving 19 abandoned wells. All 19 wells showed positive methane emissions to the atmosphere, independent of their plugging status (Figure 1). The mean methane flux for the 14 wells is 0.27 kg/day/well, and the chemical composition of the gas indicates a mixture of thermogenic and biogenic sources. These fluxes are much higher than soil fluxes measured adjacent to the wells and used as controls. If the mean flux for these 19 wells is used as an average for all abandoned wells in Pennsylvania, this would represent methane leakage that is between 5 and 7 percent of the total estimated anthropogenic methane emissions in the state of Pennsylvania. This number is also similar to the estimated leakage rate from operating fracking wells, although the temporal extent of leakage from abandoned wells is likely to be much longer than those associated with fracking and production operations. The team hopes to measure additional wells, from different oil and gas fields and with different attributes, to get a better measure of the overall leakage rates.
Fate of fluids in fracking and shale-gas production
As a parallel activity, the researchers have begun to develop models to study fluid movements associated with hydraulic fracturing (“fracking”) and shale-gas production. The focus is the fate of the fracking fluids, where about 75% of the injected aqueous-based fracking fluid does not return to the well in the flow-back period. Recent literature has hypothesized this as an indication of leakage upward toward potable aquifers. The Celia group is looking at two-phase flow effects and the role of spontaneous imbibition, to determine whether this absorption into the rock matrix can reasonably account for the fluid losses. This work is ongoing, although early results indicate that simple imbibition away from the main fracture planes cannot account for this loss of mass.
Enhanced methane recovery and CO2 storage in shales
In a related effort, Celia and colleagues have recently begun to consider whether CO2 might be injected into depleted shale-gas formations for the purpose of enhanced methane recovery with the co-benefit of CO2 storage driven by preferential sorption within the rock. The researchers are making initial calculations using simplified models at the large scale while also building new porescale models to represent the shale system at the small scale. The large-scale calculations are part of a collaboration with Eric Larson from CMI’s Low-Carbon Energy Group and Lynn Loo from Chemical Engineering, while the pore-scale modeling is being developed in collaboration with Vahid Joekar-Niasar who is at the Shell Research Laboratory in Rijswijk, The Netherlands.