The Highlander Field: Eight Years On
Authors: Smith J.R. 
Published: October 2008

In 1985 the Highlander field was brought onstream from a remote-controlled subsea production facility at a water-depth of 420 feet in the North Sea. Oil and solution gas were produced through 8 miles of pipelines to the processing facilities on an existing platform. Eight years later it is possible to look back and benefit from the experience gained with gaslift, water-injection, data acquisition, scale, chemical treatments, production optimisation, wellwork, water-production, and production allocation. Previous papers described the development of the subsea facilityl, the initial installation and bringing the field on production3,4. This paper describes the experiences with a maturing field.

INTRODUCTION

The Highlander field is located in Block 14/20b in the U.K. sector of the North Sea, 8 miles (13 km) northwest of the Tartan platform and 114 miles (183 km) northeast of Aberdeen in 420 feet (128 m) of water fig. 1)(Available in full paper). At the time of development in 1985 the field was considered marginal with an estimated 35 million bbl (5.6×106m3)of recoverable oil. A remote subsea production system (fig. 2)(Available in full paper) was chosen to take advantage of existing production, processing and pipeline capacity of the production platform "Tartan A".

The Highlander field consists of reservoirs of Jurassic and Cretaceous age, both having low-energy crude with a low GOR. Conventional gaslift was included in the well-completion design to supplement the natural reservoir energy. The subsea facilities were designed to handle slug-flow in the production pipelines while minimizing backpressure on the wells. Water-injection facilities were included as initial testing had shown the potential for improved recovery.

Crude analysis indicated good-quality light oil with wax and CO2. Pour-point and hydrate-formation temperature have been shown to be higher than seawater temperatures. In the original facilities design these properties necessitated provision for continuous injection of pour-point-depressant (PPD), methanol and corrosion inhibitors backed up by a pigging system (which has not been used to date).

The design philosophy in the subsea facilities focused on system redundancy, accessibility by divers and ease of component-replacement. The 12- slot template (Fig. 3)(Available in full paper) incorporates connections for 6 satellite wells. The specified design capacity was 30,000 B/D (4800 m3/d) of production, 36,000 B/D (5700 m3/d) of water injection, and 21 MMscf/D (59,000 m3/d) of gaslift. Production is achieved via a 12-inch bulk-production (capacity 25,000 B/D and 22 MMscf7D) and 8-inch test-production line (capacity 15,000 B/D and 7.5 MMscf/D). Each line is tied in to its own multi-chamber slugcatcher (Fig. 4)(Available in full paper) at the base of the Tartan platform. The liquids from these slugcatchers are then pumped (fig. 5)(Available in full paper) from the base of the platform, via heat exchangers (Fig. 6)(Available in full paper), to single-stage bulk and test separation facilities (design capacities 31,000 B/D and 10,000 B/D, respectively, at 2% watercut). The submersible pumps are suspended some 200 feet (61 m) below the seabed on 7-in (175 mm) tubings in 185/8-in (470-mm) risers. Gas, separated at the slugcatchers, is routed via the 185/8-inby 7-in riser annuli to the surface where it is recombined with liquids prior to entering the separators.