Experimental measurements of condensate blocking and treatements in low and high permeability cores
MetadataShow full item record
Experiments were performed to investigate the effect of condensate and water blocking on gas productivity in both low and high permeability cores. Liquid dropout data for a four-component synthetic gas mixture was measured experimentally. The Peng-Robinson equation-of-state was used to calculate the liquid drop and matched the data closely after a small adjustment in the gas composition. Coreflood experiments were conducted to measure relative permeability using Berea sandstone and Texas Cream limestone cores and the four-component synthetic gas mixture to quantify the loss in relative permeability caused by condensate blocking. The condensate saturation was established dynamically by precise control of core inlet and outlet pressures. It is well known that retrograde condensate blockage can cause significant productivity loss in low permeability gas reservoirs. This research shows that such productivity losses can also occur in high permeability gas reservoirs. Gas relative permeability reductions of up to 97% were measured in 3 md and 350 md cores during steady state flow of gas and condensate (see Table 5.1). Higher initial water saturations resulted in higher reductions in gas relative permeability. Gas and condensate relative permeability values are almost equal at steady state flow of gas and condensate. Values as low as 0.04 were measured at the highest initial water saturation. Methanol treatments in the same cores increased both gas and condensate relative permeability in both low and high permeability rocks. These coreflood experiments also were used to quantify the methanol treatment volumes required to restore the gas relative permeability. Methanol displaces condensate and maintains improved gas relative permeability for a significant period of time after the treatment even with production below the dew point pressure. Methanol miscibility displaces water, which is also beneficial since water contributes to the total liquid blockage of the gas. These same coreflood experiments showed that dynamic condensate accumulation is influenced by flow rate. More pore volumes were required to reach a steady state at high flow rates than a low flow rates. Co-injection equilibrium gas and condensate phases into the core achieved a steady state with fewer pore volumes than the high flow rate dynamic accumulation corefloods. These data show that local equilibrium was not reached at the high flow rates. At the highest flow rates, the residence time in the core was only about 9 minutes, which evidently is not sufficient time for complete mass transfer to occur. However, it is important to note that the steady state values of gas and condensate relative permeability are the same for both methods. These values will be reached very quickly around gas wells with high flow rate due to the large number of pore volumes flowing near the well. In light of these new data, the common perception that condensate blocking around wells in high-permeability gas reservoirs is not significant should be re-examined. Reservoir engineers should be especially careful to evaluate the damage done in such high-permeability reservoirs if the well's pressure drawdown is high enough to result in pressures below the dew point over a long enough period of time to allow condensate accumulation near the well.