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Summary. This paper describes the development of a three-phase metering system for installation on seabed templates at or near subsea wellheads. It tracks the development of the system from its conception through continuing tests on a production platform in the North Sea. The paper also reviews modification of the original design as a result of 1989 offshore tests. Introduction Current challenges facing offshore operations include developing technologies that economically maximize production from existing offshore platforms and allow reservoirs in ever-increasing ocean depths to be produced. Considerable attention is being given to the use of single- and/or multiwell subsea satellites and the development of equipment and production systems that can be placed at these satellites. In 1981, for example, a series of subsea developments began to boost production from the Tartan Alpha platform in the North Sea. Initially, simple hydraulically controlled, nearplatform, single-well satellites were developed. Then, in 1985, the sophisticated Highlander subsea oil production template was installed 8 miles from Tartan. The Petronella field development followed in 1986 with an offset of 6.8 miles. Such work on long offset subsea developments highlighted the high cost of providing metering facilities for flow testing remote subsea wells. Periodic well flow testing is necessary to monitor well and reservoir performance over time to optimize decisions on well production rates and new well requirements through improved reservoir models, to determine the timing of well workovers, and to identify when wells become uneconomical to produce. A dedicated "test separator" conventionally is used to meter individual wells. Fluids from a well are separated into the three component phases (oil, gas, and water) in a large vessel, and the flow rate of each phase is measured on the respective outlet lines from the vessel. The same method currently is used for subsea satellite developments by providing a dedicated "test pipeline" from the subsea field to carry a selected well's production to a test separator for metering on the host platform. The capital cost of these systems rises rapidly with distance. Greater distances between the wellhead and flow test system increase the cost of the test pipeline and require larger and hence more expensive slug catchers and risers. Clearly, a subsea-based well-test system could result in large capital cost savings by eliminating the need for conventional test systems (Fig. 1). This paper tracks the development of one subsea well test system from conception to field testing on the Tartan A platform in the North Sea. This work defines the design requirements of the system, reviews system development and fabrication, describes modifications made as a result of initial field tests, and reports the results of topside tests completed through Dec. 1990.

The development of a three phase metering system for installation on seabed templates at or near subsea wellheads is described. The Subsea Metering System (SMS) design measurement accuracies are +/-5%.The performance of the SMS as determined from topside tests on Texaco's Tartan Alpha Platform in the North Sea is presented in comparison with standard test separator References and figures at end of paper. 447 equipment. The schedule for completing the topside tests and fitting the SMS to the Highlander Template is reviewed.

The Morpeth field is developed using three satellite subsea production wells and one water injection well clustered together in a line with 50 ft well spacing. The cluster of wells produces to a SeaStar mini-TLP located approximately 1500 feet to the North. The satellite wells produce through individual flowlines linked near the trees by pigging loops, reflecting a concern with wax deposition and hydrate prevention and remediation. The subsea wells are controlled through two umbilicals from the SeaStar.

This paper describes the architecture of the Lucius Subsea Production System and the drivers behind it. Novel technologies are detailed including suction pile mounted Pipeline End Manifolds (PLEMs) and chemical injection backpressure regulator valves. Innovative installation techniques and highlights are described, including the use of laser metrology and a "strong back" system for rigid jumpers. Difficulties and lessons learned are also shared.