Permanent distributed temperature sensing (DTS) using fiber-optic technology provides measurements over the complete length of the fiber in the wellbore. The temperature profiles can be monitored at surface in real time, minimizing the need for production logs, preventing deferred production losses, decreasing well interventions, and reducing operating costs. This technology has been applied by Apache North Sea Ltd in the Forties field to monitor and optimize the performance of two wells producing by gas lift in the Delta platform and, at the same time, examine their completion integrity. To accomplish these objectives, a hybrid fiber-optic electrical cable was installed in two Forties wells, allowing the continuous measurement of temperature and acquisition of pressure data from a downhole gauge located below the deepest gas-injection point. The combined benefit of reducing both the number of well interventions, and thus eliminating the associated QHSE risks, and the operating costs made this well monitoring strategy the appropriate one in this mature field. The analysis and interpretation of downhole pressure and DTS data provided rapid feedback to the platform production team regarding the status of the well, allowing a better and more informed decision-making process. In this paper, we outline the deployment of the hybrid DTS system and describe the analysis performed in each of the two wells. Data handling, analysis, and interpretation are described as well as the methodology and workflow for well monitoring and optimization using permanently installed DTS.

Since the mid-1970s technology has enabled extraction of the UK’s oil and gas reserves in a cost-effective manner using subsea wells rather than individual platforms. In 2008, 43% of the UK’s oil and gas production was by subsea wells (The United Kingdom Offshore Oil and Gas Industry Association, 2010). Centrica Energy performed an extended well test on a subsea high-pressure, high-temperature (HPHT) appraisal well in the North Sea and monitored the test using a permanently installed optical distributed temperature sensor (DTS) system. The high temperatures and pressures, together with a subsea installation, created specific challenges for monitoring the completion integrity and flow from the multizone reservoir during the well test. In this paper the authors outline the deployment of the DTS system and present an interpretation of the acquired data. The completion was installed in one trip, with tubing-conveyed perforating (TCP) guns run at the bottom of the string. The firing of the guns, the completion integrity, and the fluid flow were monitored using a DTS optical fiber connected through the wellhead via an optical wet-connector and extending past the packer to the bottom of the guns. The same cable was used to operate a downhole electrical pressure gauge above the packer. Interpretation of the continuous temperature data enabled Centrica Energy to: identify leaks at gas lift mandrels while pressure testing the production tubing during commissioning, allowing time saving decisions to be made on how to proceed with the installation. check that all the perforating guns fired correctly to confirm that the whole reservoir was open to flow. monitor the flow from different reservoir intervals over the 2-week well test to compare the flow profile from the reservoir to model predictions. minimize QHSE risks associated with a well intervention.

The Chestnut field is located in Block 22/2a in the central North Sea. The field, with water depths to 120 m, is approximately 180 km east of Aberdeen, Scotland. Chestnut was first commercially produced in September 2008 by Centrica Energy (formerly Venture Petroleum) using two subsea wells (a horizontal oil producer and a water injection well) tied into a floating production, storage, and offloading (FPSO) vessel. Water injection was required almost immediately because the oil was saturated. A second oil producing well was spudded in September 2008, targeting the South Chestnut field. This well, 22/2a-16Y, was tied into the same flowline and riser as the existing oil producer. A venturi-type downhole flowmeter was installed in well 22/2a-16Y to obtain continuous pressure, temperature, and flow rate measurements. The production from the other well could then be calculated by subtracting the venturi flowmeter measurements from the total rate measurements made at the FPSO. Venturi-type downhole flowmeters are, strictly speaking, only applicable in liquid environments because the Bernoulli principle is valid only for single-phase flow and is tenable only in low-slip liquid-liquid flow regimes, such as in the concurrent flow of oil and water at high velocities. Because the Chestnut oil is saturated, it was known that free gas would be seen at the intake of the venturi because the flowing pressure would, by definition, be below the bubblepoint. To address the challenges caused by two-phase flow through the flowmeter, a workflow was developed that would first assess the quantity and affect of the free gas in the venturi device. The workflow was then developed to increase the accuracy of the flowmeter in the two-phase oil-gas flowing conditions. The enhanced flow calculations were then validated by using FPSO test separator data when only the flowmeter-equipped well was producing. The enhanced model improved the accuracy of the liquid-rate predictions across various rates from initial discrepancies of 40% to 190%, to less than 5%, allowing Centrica Energy to achieve its well- and reservoir-monitoring objectives. The use of venturi-type flowmeters has traditionally been limited to applications in which only liquid is flowing through the meter. This present case study shows that customized workflows can improve the accuracy of the venturi flowmeter measurements in multiphase environments, making these downhole flowmeters a cost effective alternative to true multiphase meters for certain applications.

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.