Abstract: A method and apparatus determines three phase holdup fractions and flow rates for the individual phases of a fluid flowing in a well. A logging tool comprising a temperature compensated gradiomanometer having a differential pressure detector comprised of two pressure sensors and a nuclear densitometer having a beam source is lowered into a wellbore. The differential pressure between the pressure sensors is measured and an average fluid density is determined. The attenuation of a beam propagating from the beam source through the fluid and to the beam detector is measured, and holdup fractions of the fluid are calculated. Flow rates for the individual phases are determined by adding a flowmeter, and multiplying each holdup fraction by the total flow rate.

Abstract: The flow of bubbles in a borehole within an active well is determined by using data from a borehole televiewer. A known discontinuous material is introduced into the borehole at a known distance from the borehole televiewer, and the elapsed time is determined between introduction and detection of the discontinuous material by the borehole televiewer.

Abstract: A method is disclosed for using data from a borehole televiewer in an active well to determine fluid properties. That method involves determining the wall effects from the data, and factoring out the wall effects from the data to determine the fluid properties.

Abstract: A method for providing improved measurement of oil, water, and gas flow rates in producing wells using thru-tubing wireline inflatable and retrievable packers or plugs to systematically isolate producing zones within a wellbore. Surface flow rates are measured before and after zonal isolation, with the zonal production rate determined by the measured difference in flow rate before and after isolation. Surface measurement of individual production zones allows greater accuracy in measuring multiphase flows, while at the same time allowing evaluation of reservoir properties of the lower, isolated zones.

Abstract: A method of determining relative liquid and vapor phase steam profiles in a steam injection well utilizes an unstable radioactive isotope. A dual detector gamma ray logging tool is inserted into the well at a depth below the perforation zone. The unstable radioactive isotope is then injected into the steam flow, and it naturally hydrolyzes from a vapor phase into a liquid phase at a known rate, so that at a given time after injection, the relative proportions of the vapor phase and the liquid phase can be determined. The transmit times of the vapor and liquid phases to pass between the gamma ray detectors is measured and the above steps are then repeated at a second location. The amount of fluid entering a formation between the first and second locations can then be determined.