The oil & gas industry is currently using electro-hydraulic subsea control systems as the standard way to manage the production of hydrocarbons from subsea offshore oil & gas fields. Whilst these E/H controls are set to continue as the system of choice for the next 5 years or so, a desire to improve reliability and operational routines will increase the opportunity to use all-electric subsea production control systems. The first offshore trial of an all-electric subsea production control system and wellhead tree systems has recently been completed at the BP Magnus Platform in the North Sea. This paper describes the background leading to the development of the all-electric system, and describes how the production operators are set to benefit from such systems.
The oil & gas industry has for many years produced from offshore reserves in many areas of the world. Initially these were merely an extension of land based oil fields, using simple pontoons at near shore locations. The need to produce from reserves in greater water depths and longer distances from shore developed the fixed platform jacketed structures that are familiar today (figure 1). In order to produce from even greater water depths and harsher metocean conditions, the offshore industry has become technologically sophisticated. This applies both to the floating structures that support topside facilities in 2,000 meters plus water depths, and the tie-back technology to produce from long distance remote step-out wells. These can be located at many tens of kilometres from the host facility.
Figure 1: BP operated North Sea Magnus Platform. (Available in full papaer)
Today there are many different ways to configure offshore production facilities. These range from the isolation systems (Xmas trees) mounted directly on the host facility (dry tree systems) to configurations where the Xmas trees are installed subsea. Subsea oil & gas developments are located remote from the host facility, connected via umbilical and flowline systems. Some complex offshore developments use a combination of Subsea and Dry Xmas trees, together with multiple manifold collection centre and connecting flowlines and umbilicals. In the early days of subsea tiebacks, each of the hydraulic valves (needed to control the flow of hydrocarbons from the wellhead systems) was individually controlled by a direct hydraulic connection back to the host facility and a topside control panel. The panel consisted of hydraulic pumps, motors, valves and accumulators. This was a very successfully and reliable concept, due to its simplicity and relative low cost. However, the limitations of direct hydraulics resulted in slow subsea to host actuator response times, and this permitted modest tie-back distance to around 15 kilometres. In addition, the size and weight of the connecting umbilical hoses, in all but the simplest of systems, resulted in difficulties with transportation and installation. These limitations, together with the increasing requirements to collect reservoir pressure and temperature data, prompted the industry to develop more sophisticated technology, including subsea control systems.
As subsea technology advanced, piloted and sequenced valve hydraulic systems (ref 1) were used.