Occasionally during a pre-frac injection test the observed friction pressures are much higher than expected.These tests have frequently led to significant delays and expense in tight gas wells re-perforating the interval to be fractured in order to remove this ‘excess near-wellbore friction’ pressure.This paper presents a method to identify and mitigate the effects of two-phase flow during an injection test.Examples are presented which encountered very high apparent near-wellbore friction pressures that were actually due to two-phase flow.Subsequent testing with 100% liquid injection revealed normal near-wellbore friction pressures.A technique of repeating the test after a variable shut-in time has routinely served to eliminate the need for a costly and time-consuming re-perforating job. Introduction The Burgos basin is found in northeastern Mexico and is an extension of the south Texas Oligocene-Vicksburg trend.Production is from a series of sandstone reservoirs ranging in depth from 3000 ft (900 m) to more than 11000 ft (3300 m) and is primarily gas with condensate yields varying from 10 bbls/MMscf to more than 60 bbls/MMscf.The majority of these reservoirs are ‘tight gas’ and require fracture stimulation to obtain economical production rates.Permeability ranges from less than 0.02 mD to as high as 3 mD with an average of perhaps 0.2 mD. Gas wells in the Burgos basin are typically "tubingless" completions with a 2–7/8" or 3–1/2" casing string in shallow and intermediate depth wells and 4–1/2" tapered strings in the deeper wells.The small diameter completion precludes the use of a "deadstring" configuration for obtaining bottom hole fracturing pressures directly.A diagram of a typical well completion is shown in figure 1. Due to contractual requirements a low volume (35–40 bbls), single-rate injection test with 2% KCl water (called an ‘admit’ test) is run after perforating each zone.By analyzing the falloff data from these tests the minimum horizontal stress, sHmin in the pay zone is generally well known.In addition, these tests give important clues about the formation permeability and the reservoir pressure, although exact values for these are rarely obtainable.Figures 2 and 3 show an example of an admit test and an estimation of sHmin from a plot of the pressure vs. the Nolte ‘G’ function.After this analysis is complete the well will typically be evaluated with a flow test, prior to designing a fracture treatment.
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