Conventional production logging with electric line is sometimes challenged by the presence of mechanical restrictions in the wellbore. The fragility of production logging tools also impedes the use of electric-line coiled tubing (CT) with the risk of damaging tools across sections with little clearance. This study showcases conclusive flow profiling using distributed temperature sensing (DTS) via fiber optics deployed with CT in a gas condensate well where wellbore access prevented the use of logging tools.

Flow profiling via DTS has been used globally in completions where fiber optic lines are permanently installed. Interpretation of those logs usually leverages months of acquired data to invert temperature information and obtain the evolution of flow distribution over time. The proposed methodology instead relies on hours of DTS acquisition through the temporary deployment of fiber optics with CT. A comprehensive sensitivity analysis on key unknown parameters is then performed using a fit-for-purpose thermal-flow simulator to match simulated and acquired temperature profiles, leading to a flow distribution of gas, condensate, and oil in the wellbore.

Before the intervention, an evaluation study was run using a flow-thermal simulator to evaluate the expected sensitivity of wellbore temperature to poorly characterized downhole parameters, such as permeability, pressure, or skin. This allows determining the downhole conditions under which DTS is able to detect flow contribution for a specific candidate. During the operation, the CT equipped with fiber optics was stationed across production zones for a total of 06 hours. The data was processed and fed back to the simulator along with reservoir, well data, and surface rates.

To further constrain data processing, pressure surveys were acquired during the CT run using a downhole gauge, both during flow and shut-in periods. Unknown reservoir properties were sensitized during data interpretation to obtain a match between acquired DTS profiles and simulated wellbore temperature evolution, which, in turn, yielded an associated flow distribution. The matching exercise being an open-ended mathematical problem, several scenarios were considered, and their results checked against further production characterization of the wellbore and the field. The proposed case study illustrates how this methodology enabled logging in a mechanically-restricted zone and helped determining that the top interval was not contributing to flow.

Flow profiling can be performed using a wide range of complementary logging tools, but the evolution of completions over the past few years is increasingly introducing mechanical restrictions that prevent the conveyance of such tools altogether. This study demonstrates that DTS can be a viable alternative for assessing zonal flow contributions. It also discusses the conditions under which this methodology is achievable.

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