North Sea Downhole Corrosion: Identifying the Problem; Implementing the Solutions
Authors: Houghton Christopher John , Westermark Robert Victor 
Published: December 2007

Tubing failures caused by CO2 corrosion and erosion are examined. Corrosion inhibitors were used for batch treatments, formation squeezing and continuous injection downhole through the annulus. Plastic-coated tubing also was used. Evaluation was by surface corrosion monitoring, tubing caliper surveys and inspection of recovered tubing. Economics were reviewed.

Introduction

The Ekofisk field was discovered in the Norwegian sector of the North Sea in late 1969 by the Phillips Norway Group. This group is composed of Phillips Petroleum Co. Norway (37%), Norske Fina A/S (30%), Norske Agip A/S (13%), and the Petronord Group (20%). Seven geologically separate Fields have been developed with eleven producing platforms. Phase 1 of development was the completion of four subsea wells tied into a converted jackup with tanker loading using single-point mooring buoys. Phase 2 was the installation of three production platforms, subsea pipelines, and a million-bbl (159 000-m3) concrete storage tank. Phase 3 was in two parts. First, three production platforms, an oil line to Teesside, England, and a gas line to Emden, Germany, were installed. Finally, five more production platforms were brought on stream in 1979, resulting in platforms were brought on stream in 1979, resulting in the seven-field Greater Ekofisk development. There are 120 wells completed with most using 4 1/2-in. OD, 12.6-lbm/ft (114-mm OD, 18.8-kg/m) N-80 (after 1979, L-80 was used) tubing inside 7-in., 29-lbm/ft (178-mm. 43.2-kg/m) N-80 casing. Most wells are deviated, with a maximum deviation of 55 degrees. In a few of the higher-volume wells, a 5 1/2- × 5- × 4 1/2-in. (140- × 127- × 114-mm) tapered tubine string was selected. Except for the 5 1/2-in. (140-mm)completions, a 3.81-in. (96.8-mm) seating nipple was set at 550 ft (168 m) to locate wireline retrievable safety valves. The larger completions have 4.56-in. (115.8-mm) seating nipples. The production rates varied considerably both within and between fields. The low water-cut production was coupled with a CO2 content of 1.5 to 3 mol% in the gas phase (Table 1). phase (Table 1). Corrosion was found first in the surface flow lines and downhole safety valves in 1976. The first tubing failures occurred in 1978. A corrosion task force including personnel from. operations, corrosion, reservoir, process, personnel from. operations, corrosion, reservoir, process, and drilling engineering was established to recommend and to coordinate projects for combating the downhole corrosion. Three tubing failure case histories are reviewed in the First section of the paper, then control methods used and the results are described.

Case History 1

Table 1 summarizes the flowing conditions for Well 1. This 10.500-ft (3200-m) total depth (TD) oil well was in service for only 309 days with 68 days downtime before the tubing was perforated because of erosion/corrosion. The tubing pared at a depth of 1,400 ft (427 m) during the work over to replace it. Parting was caused by severe circumferential wall thinning. The well was deviated 7 degrees at this point. The flowing velocity ranged from 21 to 61 ft/sec (6.4 to 7.9 m/s) from the bottom to the top of the tubing. Fig. 1 shows a perforated tubing length from a depth of 5,700 ft (1740 m). The corrosion attack is concentrated in one quadrant of the tubing. The deviation at this depth was 35 degrees. The CO2 partial pressure was 90 psi (620 kPa), and the well tests had shown negligible free water at the separator. Subsequent testing indicated water production as a tight emulsion of approximately 1%. The estimated corrosion rate for the failure is more than 400 mil/yr (10.2 mm/a).

JPT

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