Long-term Coreflood Testing with Biopolymers—A Laboratory Investigation Showing How Return Permeability Improves From 0 to 100 Percent by Getting a Critical Parameter Right

Abstract

A series of long-term coreflood tests has shown the importance of considering the self-breaking rate of biopolymers when designing coreflood tests of low-solids and solids-free brine-based drilling and completion fluids that naturally contaminate the core plug with biopolymers during testing. The tests were conducted with a solids-free potassium formate brine–based reservoir drilling fluid, formulated with xanthan gum and starch, which when exposed to overbalanced pressure, invaded deep into the core plug. The coreflood test simulated filtrate invasion into a water-saturated formation while drilling an injection well. In this scenario the core plug was initially 100% saturated with formation water, and return permeability was measured by injecting formation water through the core in the same direction as the test fluid filtrate invasion. Testing was conducted at two temperatures, 121 and 149°C (250 and 300°F). At both test temperatures there was a very good correlation between the cleanup or permeability recovery rate of the core plug and the biopolymer self-breaking rates, which had been measured in an earlier study. Due to the low cleanup rate at the lowest temperature, this test was terminated as soon as the cleanup rate was fully established, and the testing was continued at the higher temperature until the permeability had reached close to 100% of its initial value. The initial 49-hours cleanup with formation water at 121°C (250°F) resulted in a return permeability to formation water of only 3.8%, explaining why laboratory coreflood tests with low-solids/solids-free brine-based drilling and completion fluids containing biopolymeric additives are generally unable to reproduce or predict the excellent well performance the same fluids deliver in the field after days, weeks, or months of steady clean-up. The results also give us useful insights into what to expect when such fluids are used to drill injection wells. Although the biopolymer self-breaking rate is much higher in the low-salinity injection water, it takes time for biopolymers to break down enough in the protective ionic environment of the formate brine for the filtrate to be diluted and displaced locally by the flow of injection water. The desire to reduce fluid screening and qualification costs unfortunately often means that reservoir drilling and completion fluid selection decisions are based on the results of short-term coreflood tests. This may be the correct procedure for fluids that cause permanent intractable damage from solids plugging. However, for solids-free or low-solids fluids containing self-breaking biopolymers, relying on such short-term tests can mean that the wrong fluid selection decisions are made.