Subsea gas compression - A future option
Authors: Bjerkreim Bernt 
Published: October 2008

Ormen Lange is a long step-out gas field developed with gas processing facilities 120 km from the production wells. The development strategy is to deplete the reservoir. In order to maintain the production platau as long as possible and recover the anticipated gas and condensate resources, future compression is required for Ormen Lange.

This paper describes the base case future compression alternative, the floating production platform.

The paper also describes subsea gas compression as an alternative to the floating production platform and how the qualification strategy is outlined in order to ensure a qualified subsea gas compression system at the time of concept selection for future gas compression.

Introduction

Ormen Lange is a gas field located 100 km off the northwest coast of Norway on the Norwegian continental shelf, in water depth varying between 850 and 1,100 meters.

The reservoir covers an area 40 km long, eight to 10 km wide and 3,000 meters below the surface. Recoverable reserves are estimated to approximately 397 billion Sm3 dry gas and 28.5 million m3 condensate.

Ormen Lange is under development and production will start October 1, 2007.

. Fig. 1. Ormen Lange development(Available in full paper)

The main drive mechanism for the Ormen Lange reservoir is pressure depletion. The estimated recoverable reserves are based on the use of future compression facilities for pressure boosting upstream from the onshore plant, as the reservoir pressure declines.

The Ormen Lange subsea units and layout will be designed to accommodate the flexibility to evaluate and decide the type of offshore compression unit(s) at a later stage. The options considered are:Subsea compression.Topside compression on a platform. The final decision on an offshore compression concept can be postponed for a number of years after subsea production start-up of the Ormen Lange field. An evaluation of the maturity of the required technology and risk assessment for the two alternatives will be performed when required, as determined by production experience. This, in combination with pressure boosting onshore, upstream of the processing plant, will define the best timing of further compression facilities offshore. Installation of offshore compression in 2016, as indicated by this report, is therefore to be considered as an example only. Onshore compression is considered as proven technology and is therefore not described further in this report.

Topside compression, represented by a semi submersible, is chosen as the base case for offshore compression.

It should be noted that the subsea control of the gas production, MEG supply, etc., will still be from the on shore terminal CCR, even if an offshore compression platform is installed.

A qualification program for the subsea compression concept is proposed executed until a decision for implementation is taken. In this report, the cost for this qualification program is included as part of the base case cost estimate. The decision for possible implementation will be taken after sufficient production experience has been obtained.

Installation and commissioning, related to the semi submersible, riser towers, tie-in of production jumpers, etc., will have no minimum impact on the continued gas production from the subsea production units.