New Concept Used in Satellite Subsea Well Systems
Authors: Morton Arthur W. 
Published: December 2007

Satellite subsea wells usually are subjected to high operational and installation costs. Re-entry into a well for servicing can cost as much as drilling a well from a platform. The economics of laying and connecting a multitude of lines to a deepwater satellite well may preclude field development using such systems. New concepts, successfully used to connect multiple lines, may enhance the use of satellite subsea wells for early production and reservoir performance evaluation. production and reservoir performance evaluation. Introduction

Conoco Inc. decided to re-enter and complete three wells that were drilled originally to delineate the Murchison field (Fig. 1). The economic justification of these completions was early production and an accelerated production rate buildup. production rate buildup. A method was devised to construct and lay bundles of flow lines in deep water. The method involves building the lines onshore and towing them to location. Data from the installation suggest that there can be abnormally high towing stresses if the lines being towed are not kept below the surface. This paper suggests several new concepts in flow line technology that may enhance the use of subsea satellite wells for field development.

Conventional Subsea Well Systems

Various systems have been devised to produce a satellite subsea well. They generally start with a casing program similar to wells completed on a platform and use a modified land-type Christmas tree on the seafloor. A platform and use a modified land-type Christmas tree on the seafloor. A subsea controller is required to control the functions of the subsea Christmas tree valves. Such systems require the subsea installation of: Christmas tree, controller, flow lines, service lines, hydraulic control lines, electric control lines, and riser system at the platform.

New Concepts of Subsea Well Systems

Reliability studies of a conventional satellite system indicated that some components have a tendency to fail within 18 months. One such component is the subsea controller. Packing on valve stems appears to be another source of failure. Damage to control lines has been an additional reason for abnormally high operating costs. It is anticipated that high operational, equipment, and installation costs can be overcome by use of new concepts.The new concepts eliminate subsea Christmas trees, subsea controllers, and lay barges to lay flow lines.The Murchison installation accomplished the latter two objectives. Three wells were re-entered, completed, and tested in 1978. Two were brought onto production 2 years later, after the platform was completed and without additional workover. The heavy completion fluid was displaced from the dual tubing strings by use of a dedicated through-the-flow-line (TFL) pumping system. To ensure that the downhole safety valve and seafloor pumping system. To ensure that the downhole safety valve and seafloor Christmas tree valves would open after a 2-year shut-in, oil was "spotted" across these valves when the wells were completed. The dual 3 1/2-in. (89-mm) tubing and flow lines allowed the two oil wells to produce more than 23,500 BOPD (3736 m3/d oil). The third well (water injection) was put into service 3 years after completion, with no subsea equipment problems. Currently the water injection well is in operation and as predicted by reliability studies, the two oil producing wells have been shut in after 7 months of operation because of downhole safety-valve equipment problems.

Subsea flow Lines

The completion used dual tubing strings in concert with two horizontal tubing extensions and four hydraulic control lines. These lines were too complex and expensive to be installed by conventional methods.

JPT

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