Development of remote offshore fields has unique technical challenges because quite often, such fields have only a few subsea wells tied to adjacent fields. This scenario is especially the case in small and/or marginal offshore fields where the profitability is very dependent on capital and operational expenditures. Therefore, quite often a group of marginal offshore fields located nearby are developed together with several gathering points and pipeline systems joining different subsea wells. Flow metering is usually performed at gathering points on the seabed using multiphase flowmeters rather than at individual wellheads. While this method can be very efficient from an economical point of view, it may, on the other hand, compromise the data acquisition process, resulting in an insufficient understanding of individual well performance. The situation may get even more complicated when wells from different fields are tied together. Because well interventions for individual well performance evaluations are generally expensive and not always possible, it is necessary to have a reliable and cost-effective permanent downhole monitoring system that provides continuous real-time data necessary for updating and improving the field development strategy.
This paper presents a case study of a subsea oil producing well in the North Sea where one such system—a venturi downhole flowmeter—was installed to obtain continuous pressure and temperature measurements for downhole fluid density and flow rate calculations. This type of flowmeter is useful only in liquid environments because the underlying Bernoulli principle is applicable only for single-phase flow and tenable in low-slip liquid/liquid flow regimes, such as in the concurrent flow of oil and water at high velocities. Surface flow rate validation is always a good complement but not compulsory. The goal of this cost-effective monitoring method was to facilitate production (oil and water) allocation so as to simultaneously improve well performance and reservoir modeling.
The continuous pressure and temperature data obtained from this downhole flowmeter were translated into valuable information during well flowing and shut-in periods. The application of specific workflows transformed the downhole data into fluid flow rates, which allowed to accurately evaluate performance of the well. Successful calculation validations were performed using a multiphase meter data due to the inability to test the well. The results allowed the operator to properly allocate flow, assess reservoir performance, and identify improvement opportunities in the field-development plan.
This case study demonstrates that with the installation of reliable, cost-effective downhole flowmeters and the appropriate interpretation of downhole real-time data, well performance evaluation and reservoir management strategy can be improved simultaneously in subsea environments where the risks are high and expenditures are tight.