Designing Well Fluids for the Ormen Lange Gas Project, Right on the Edge

Abstract

The challenges in developing the Ormen Lange field were the harsh weather conditions, deep-water depth, subsea topography and sub-zero seabed temperatures. Due to environmental constraints and the selected sand face completion type, a water-based fluid system was required. This paper discusses the design of the fluids to give full hydrate inhibition, maximize breaker effectiveness, provide low overbalance, and reduce corrosion risk. An extensive research and development program was initiated that spanned over two years. The study included bridging and chemical component selection, brine evaluation, hydrate suppression measurement, elastomers compatibility, extensive breaker treatment studies, formation damage measurements using actual reservoir core and long term corrosion testing. An in-situ generating acid/enzyme breaker treatment deployed in the gravel pack carrier fluid was developed to optimise filtercake cleanup whilst providing a non-corrosive environment for the selected gravel pack screens and lower completion metallurgy. The basis of design and knowledge gained in the laboratory testing phase was transferred to the field and the first three wells of the initial development phase have been drilled and completed trouble-free. The resulting production rates have met expected targets proving low formation damage and an efficient cleanup was achieved. Introduction When the Ormen Lange field comes into full production, it will make Norway the second largest exporter of natural gas in the world and will supply 20% of the UK's gas requirement. Maximum daily exports from the Ormen Lange field will amount to 80 MSm3/day of gas and 50,000 bbls of condensate. The gas will be piped to the UK through the Langeled Pipeline which is the world's longest underwater gas pipeline at 1200 km long. The field was discovered in 1997 and is the second largest gas field on the Norwegian continental shelf. It is situated 140 km west of Kristiansund in the Norwegian Sea in deepwater, with depths up to 1100 meters and seabed temperatures as low as minus 1°C. The field has proven gas reserves of 400 billion m3 (14 Tcf), with an expected field life of 25–30 years. The first phase of the field development consists of two subsea templates with eight subsea big bore wells requiring a total investment close to 10 billion USD. During the later phases of the project, a third and possible fourth template will be installed bringing the total number of wells up to 24. Each of the big bore wells is designed for production rates up to 10 MSm3/day (350 MMScf/day). Therefore optimum drilling and completion fluid selection was considered to be a key focus area to maximise the open area to flow and associated well productivity, in order to comply with the planned lifetime and production targets.