Traditional production logging sensors make point measurements of the total flow of all phases combined. These sensors do not sufficiently characterize the complex downhole flow profiles found in highly deviated wells with multiphase flow. Pipe deviation can result in significant changes to the flow regime, and multiphase fluids can segregate because of gravitational effects. Conventional production logging measurements are limited in their usefulness under these conditions.
The new Digital Entry and Fluid Imaging Tool (DEFT) has four probes placed radially around the wellbore. Each probe makes a digital measurement of the number of bubbles in the dispersed phase, giving a direct measurement of water holdup and an indirect measurement of flow velocity. By combining one or more passes of the measurement, an image showing the radial distribution of holdup and velocity can be obtained.
An interpretation model was developed to combine the DEFT data with conventional production logging measurements to estimate the individual phase flow rates and holdups. The technique provided accurate identification of gas, oil and water flow for effective reservoir management in deviated wells.
Production logging (PL) is one of the most important aspects of managing the production of a field. It provides insight into the type and rates of fluid flow in reservoirs - information that is crucial to optimizing the life of a well. Traditionally, the analysis of production logging measurements has focused on spinner (flowmeter), density (gradiomanometer), capacitance (holdup), temperature, manometer (pressure), and other data. In vertical wells with relatively high flow rates, traditional production logging analysis produces reliable results.
Wellbore deviation adds another dimension to the already complex multiphase flow phenomena observed in vertical wells. Flow patterns observed in multiphase flow in an inclined pipe have been found to affect PL tool responses significantly. In gas/liquid or oil/water flow, the lighter phase move rapidly along the high side of the wellbore, establishing a circulating current that causes downflow along the lower side. Because of this non-uniform flow profile, production logging tools that measure localized quantities do not represent volumetric flow rates, average densities or holdups. Under these conditions, spinner tools often indicate reverse flow only, especially when the spinner is not centralized. Density and capacitance tools, on the other hand, tend to be immersed primarily in the denser phase of the multiphase flow, preventing an accurate measurement of the average flow properties.
Figure 1 shows the effect of well deviation on spinner response. Note that this effect changes as the tool is moved from the center of the pipe to the bottom. Depending on the spinner position in the wellbore, the response can vary from very fast on the high side of the pipe to erratic spinner motion as the tool moves between up and downflow regions. Spinner tools are limited because they measure only the localized velocity at one position in the wellbore. In complex flow, it is impossible to determine total fluid flow rate from a single localized velocity measurement.
The gradiomanometer tool measures the difference in pressure over a short length which is then related to fluid density. The limited length over which the pressure drop is measured reduces the precision of the tool. Further, the reduced precision is most critical in oil/water detection when the density difference between the two phases is small. The gradiomanometer measurement is also affected by other factors;
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