Abstract
Description of the Paper: The U-A reservoir unit is an eolian deposition where the primary facies are dune deposits. These sands are composed of quartz grains with feldspars. These grains are large in diameters and coated with illite clays, which made the formation sand friable. These sands require sand control and one of the techniques applied is to frac-pack the wells. The usual practice is to clean up the well as soon as possible to minimize formation damage. This process can take up to seven days, which results in frac fluid being le ft in the formation. This paper examines the effect of shut-in times following hydraulic fracturing treatments on the return permeability of the reservoir core.
Lab studies included conducting coreflood experiments using reservoir cores and typical treatment fluids. The study was performed at bottomhole conditions (300°F) using cores with air permeabilities ranging from 25 mD to 28D. Polymer and breaker concentrations in the fracturing fluid were identical to those used in the field. Core plugs were tested by both methods: injecting and circulating the fracturing gel, and soaking it under pressure for up to seven days. Tests were performed in the absence and presence of a breaker, unencapsulated sodium bromate.
Application: Guar gum and its derivatives are commonly used to prepare hydraulic fracturing fluids. During fracturing treatments, the polymer invades the formation and leaves a gel residue in the fracture and formation, which impairs well deliverability. Several factors like polymer loading, formation temperature, shut-in time and clean-up process contribute to the treatment outcome. A common belief (misconception) has been that long shut-in periods after fracturing a gas well will further reduce the permeability, and the impairment of delivery becomes severe. To avoid the resulting damage of the well, the treatment fluids are recovered while the rig on location, which costs rig time. This concept has led us to study the impact of shut-in time on the retained permeability of reservoir cores.
Results, Observations, Conclusions: Experimental results reveal that 25% reduction in the permeability of reservoir cores occurs at a polymer loading of 45 lb/1,000 gals. A lower polymer loading of 35 lb/1000 gals caused less damage to the permeability. Most of the damage occurred during the first few hours of interaction of the gel with the core plug. Longer shut-in times did not cause additional damage. This study resulted in a significant cost savings by avoiding the need to flowback the well with the rig on location.
Technical Contributions: Guar gum polymer used in hydraulic fracturing treatment can cause damage up to 25%. The damage occurred once the fracturing gel invades the formation. Longer shut-in times don’t cause additional damage up to seven days. The degree of damage depends on the breaker concentration.
