Extending the Innes Field Life by Cost-Effective Subsea Technology
Authors: Workman D.M. , Methven J.O. , Kearns J. 
Published: December 2007

This paper describes an approach taken to extend the economic life of the Innes field, one of the North Sea's smallest producing oil fields. Emphasis is placed on the importance of minimizing production operating costs for developed fields. In the Innes field case, this was achieved by applying "low-cost technology" to change the Innes field production mode from a dedicated floating production facility to a subsea satellite manifold producing to a remote floating production facility (FPF). The feasibility study, the Innes field flow test, and the eventual project work leading to the demobilization of the Innes field FPF and the routing of Innes field fluids to the nearby FPF Deepsea Pioneer are described in this paper, which emphasizes the cost benefits obtained by using low-cost proven technology wherever possible and limiting the use of high-cost equipment.

Introduction

The Innes field, discovered in 1983, is located in the central North Sea in U.K. Block 30/24. The field, with ultimate reserves of about 5.0 million bbl [7.95 × 10(5) m3] of oil, is very small by North Sea standards. The reservoir is part of the Permian Rotliegendes sandstone of the Auk formation and was discovered during drilling of Well 30/24-24 in Jan. 1983. Production began in Jan. 1985 through the FPF Transworld 58 (TW58), located over Well 24. Stabilized crude oil was exported through a 6-m [15.2-cm] flowline to a catenary anchor leg mooring (CALM) buoy and shuttle tanker located in the Argyll field. Production from the Innes, Argyll, and Duncan fields was commingled at the Argyll base manifold (Fig. 1) and routed by the CALM buoy to the tanker.

During Aug. 1985, a second Innes field development well. Well 30/ 24-32, was drilled 3,280 ft [1000 m] north of Well 30/24-24.ell 32 encountered oil-bearing Rotliegendes reservoir sand at a depth of 12,300 ft [3750 m]. Production was routed by a 4-in. [10.2-cm] subsea flowline to the TW58 in Nov. 1985. A third potential development well was drilled as a dry hole, thus confirming that the reservoir was indeed small. Initial combined production rates of about 10,000 BOPD [1590 m3/d oil] were achieved from the two development wells; however, production declined steadily to 5,000 BOPD [795 m3/d oil] by Dec, 1986 (Fig. 2). The Innes field reservoir production mechanism is depletion drive; hence, it was anticipated that production would continue to decline until the economic production limit of about 2,500 BOPD [397.5 m3/d oil] was reached in June 1987.

Innes Field Feasibility Study

The economic limit was rather high owing to the operating costs of the dedicated production facility, and declining production rates were anticipated. Thus, consideration was given to removing the TW58 and producing the Innes field directly to the Argyll/Duncan FPF. Several obstacles had to be overcome before this objective could be accomplished; hence, a study was initiated to propose a feasible scheme for the cost-effective tieback of Innes field production to the Argyll/Duncan FPF, the Deepsea Pioneer. The study highlighted a number of potential problems in directing Innes field fluids to the Deepsea Pioneer and proposed ways in which these could be overcome.

Flow Instability.

It was anticipated that the two-phase flow of Innes field well fluids, along an 8.1-mile [13-km] flowline connecting the field to the Deepsea Pioneer, may cause flow instability and process upsets on the Deepsea Pioneer. It was considered that a subsea slug catcher may be required upstream of the Deepsea Pioneer separators to solve this problem.