This paper describes a cost-effective, pragmatic way to continuously monitor and control well performance for most oil well types. Well fluid flow rate estimates are displayed in graphical form as trends on user desk top PCs. Deviations from the norm are flagged as process alarms. In some cases measured fluid flow changes are used to automatically control the well by adjusting choke settings for performance improvement. The main benefits of this approach are safer operations and reduced operating costs - operators visit only wells with problems thus reducing exposure to hazard and eliminating spurious travel and logistics. Other benefits include increased production due to early warning of well problems, better understanding of well behavior, improved allocation accuracy and improved well testing. The purpose of this paper is to describe Shell experience with low cost continuous well performance devices and some of the benefits that can be gained from this approach. Introduction The traditional approach to well surveillance - Operators go to the wells. For effective surveillance, we need to know when a well is off production, producing abnormally low or high, or behaving in an unstable manner. We need to know how a well responds to changes in operating parameters, e.g. gas-lift injection rate, pumping speed, choke setting, etc. Measurement of well productivity in the Oil Industry has traditionally been done by well testing - the oil, water and gas phases are separated by gravity in a tank and then measured individually. A test separator is usually shared amongst a number of wells. Hence well testing is inherently discontinuous (e.g. once per month). Also, because of back-pressure effects the test conditions may be different from actual well production conditions and also well test results may be adversely affected by leaking manifold valves. We need to know when to test a well, and when a test is not needed so we can concentrate testing on wells where information is most needed. Well surveillance is traditionally a manual process. Operators routinely visit the well production sites, put wells on test, take samples and physically inspect the wells to determine if there is a problem. Most of the time the operators find that the wells are healthy. Consequently, most of the time well head visits prove to be unnecessary. Lots of unnecessary lab samples and data result from the visits. Samples and data have to be processed, again resulting in much spurious activity. Sometimes the volume of data and errors can obscure the results, or give rise to false and misleading results e.g. well tests frequently have to be repeated and in some cases well problems are missed due to the shear volume of data. The ideal would be a well head device that could continuously, cost effectively and sufficiently accurately measure well productivity. This information would be transmitted back to the operator, who would then use the data to judge which locations have problems justifying manual intervention. Hence, limited manpower resource could be concentrated on problem areas to correct well problems sooner and more effectively. Even better would be to apply sufficient intelligence to automatically control the well such that unsafe, or unproductive conditions are automatically recognized and corrective action taken by immediately activating control valves. Such monitoring and control devices now exist and the purpose of this paper is to describe these devices and outline Shell's experience to-date with these techniques. Continuously measure well productivity and "bring the wells to the Operators" - FieldWare FlowMonitor Well liquid flow rates can be estimated by measuring the pressure drop (delta-P) across a fixed restriction in the well flow line with a delta pressure transmitter. A pressure drop of .1 - 1 bar is required across the line restriction. The instrumentation signal may be telemetered back to a remote control room, or via the Internet to a PC in the operator's office.