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The initial flow test of the Hulin well was done to obtain brine and gas samples and to get a first measure of the reservoir properties. The 20,602 to 20,690-foot interval was perforated and tested in two short-term draw-down and buildup tests. This zone had an initial pressure of 17,308 psia and temperature of 339 F. The total dissolved solids of 207,000 mg/L (mostly sodium chloride) is higher than for previously tested Gulf Coast geopressured-geothermal wells. The gas content in the brine of 31 to 32 SCF/STB indicates that the brine is at or near saturation with natural gas. The permeability, as deduced from the draw-down and buildup tests, is 13 md for the lower 80-foot-thick sand member. The duration of the tests was too short to determine the lateral extent of the reservoir; but declining measured values for static bottomhole pressure prior to each flow test suggests a relatively small reservoir. When the uppermost interval in the zone of interest (20,220 to 20,260 feet) was perforated such that flow from this zone would commingle with flow from the lower zone, little to no free gas was observed. It had been speculated before the test that there might be freemore » gas in this upper zone. These speculations were generally deduced from logs after assuming the formation contained brine that had a salinity between 70,000 and 100,000 mg/L. The actual salinity was more than twice that number. it is now apparent that the amount of free gas, if any, is too small to make a significant contribution to production in a short-term test. This does not preclude the possibility of mobilization of gas by higher drawdown or coning down from an offsetting gas cap in one or more of the sand members. However, there was no evidence that this was occurring in this test. No measurements of the reservoir parameters, such as permeability, were made for the shallowest interval tested. But substantially lower drawdown for the commingled zones suggests either higher permeability or lower skin for the shallower perforated interval. Hydrate formation in the upper part of the wellbore was a problem. To circumvent this problem, about 10 barrels of diesel were pumped into the top of the well after each flow to displace the brine down to a level in the well where the temperature was too high for hydrates to form. Calculations of saturation index indicated that calcium carbonate scale would also form in the well if the pressure was drawn down too far. Thus all the flow tests were performed at low flow rates to preclude formation of scale in the wellbore. Scale inhibitor was injected into the surface flow lines to control possible scale formation in the surface equipment. Corrosion inhibitor was also injected, and coupon monitoring indicated a corrosion rate of less than 5 mils per year.« less |
