Subsea pipeline developments advance operations, integrity

June 22, 2009
The proliferation of offshore pipelines has increased the premium on being able to effectively monitor their operations and intervene when necessary.

The proliferation of offshore pipelines has increased the premium on being able to effectively monitor their operations and intervene when necessary. At the same time, the competitiveness and potential volatility of oil and gas commodity markets make it important that any intervention have the minimum possible effect. Recent developments in subsea pipeline materials, monitoring, and maintenance technology are helping meet these requirements.

T.D. Williamson SA last month announced a successful hot-tap operation for tie-in of Ettrick field's natural gas export line, allowing gas to move from UK Central North Sea blocks 20/2a and 20/3a 120 km to the ExxonMobil-operated Scottish Area Gas Evacuation (SAGE) gas plant north of Aberdeen. The hot tap occurred under 311 ft of water while maintaining the pipeline's operating pressure of 117 barg.

Acergy was primary contractor on the project, providing engineering, procurement, installation, and precommissioning of the hot-tap assembly and the subsea structures. T.D. Williamson supplied all hot-tap equipment.

Preparation for the offshore hot tap included system integration tests at the BiFab yard, Methil, UK. The hot-tap machine—with the hot-tap valve attached—was lowered from the hot-tap installation frame (in white) into the subsea protection frame. Once situated in the protection frame, engineers supervised connection of the hot-tap machine and valve to the hot-tap nipple for pressure testing before performing the hot tap (Photo by T.D. Williamson; Fig. 1).

T.D. Williamson worked with Acergy on endurance testing as part of factory-based trials. System integration tests followed endurance testing (Fig. 1). Finally, T.D. Williamson supervised the dive team executing the hot tap from a dedicated dive-support vessel, ensuring the operation was conducted according to written procedures.

Nexen Petroleum UK Ltd. operates Ettrick field. Gas is exported from FPSO Aoka Mizu via a steep wave flexible riser connected to a 6-in. ID nonpressure seal flexible flowline. The flowline runs to a gas export pipeline end manifold that in turn is connected by a hot-tapped 6-in. ID jumper to the 350-km, 30 in. OD, ExxonMobil-operated SAGE export trunkline.

NKT Flexibles supplied the 6-in. ID. piping for export jumpers, riser, and flowline, all with a design pressure of 172.4 bar and a design temperature of 60° C.

Nexen's original development plans called for a fixed platform complex featuring a wellhead platform, process platform, utilities and quarters platform, and three jackets and piles. FPSO production calls for 20,000-30,000 b/d oil and 35 MMcfd gas.

Technology acquisition

Subsea 7 Ltd. was also active on the hot-tap front, announcing in May 2009 the acquisition of exclusive global license rights for subsea grouted tee (SSGT) hot-tap technology. According to Subsea 7, SSGT enables under-pressure intervention—including repairs, by-pass or replacement, blockage removal, and branch connections—on high- and low pressure subsea pipelines without major hyperbaric welding or production shutdowns.

Mechanical divers can deploy SSGT, originally developed by Advantica in the 1990s for use on high-pressure onshore pipelines, without human diver assistance. Subsea 7 and GL Industrial Services UK Ltd led a joint industry project sponsored by BP, Total, and ConocoPhillips on adapting SSGT for subsea use. DNV has since verified this application.

Development

BMT Scientific Marine Services Inc. announced development of a sensor assembly and installation tool permitting strain sensor installation by remotely operated vehicle on underwater pipelines (Fig. 2). The subsea strain sensor assembly (SSSA) attaches to a pipeline or riser at depths up to 10,000 ft, measuring tensile and bending strain and alerting operators to excessive strain or potential fatigue damage (Fig. 3).

The ROV-installed SSSA is an adaptation of BMT SSSAs (Fig. 4) installed as part of project development at BP's Greater Plutonio block 18 hybrid riser tower off the coast of Angola, Petrobras' P-52 free standing riser tower off Brazil, and Chevron's Tahiti spar pull tubes and steel catenary riser in the Gulf of Mexico.

This subsea strain sensor assembly (SSSA) alerts operators to excessive tensile and bending strain along a pipeline at water depths up to 10,000 ft (Fig. 3).

BP installed its Greater Plutonio block 18 hybrid riser tower in 1,310 m of water during September 2007. It embedded a comprehensive, permanent hybrid riser tower monitoring system (HRTMS) in the tower's architecture. The core of the HRTMS consists of two axial strain sensing assemblies at two elevations along the tower.

Adaptation of this standard SSSA allows these devices to be installed postconstruction by ROV rather than exclusively as an integrated part of the initial project (Fig. 4).

The HTRMS has tracked changes in tower strain and attitude since Sept. 10, 2007.1 The new sensor assembly and installation tool will allow retrofitting of similar devices to existing subsea pipelines.

Tool properties

The accompanying table summarizes the properties of BMT's standard subsea strain sensor. The sensing element consists of a customized submersible linear variable differential transformer. The sensor body is not exposed to seawater unless the pressure-balanced oil filled flexible housing fails. Subjecting the strain sensors to hydrostatic pressure with the sensors enclosed in a fixture with a known strain response to pressure established SSSA sensitivity.

A central processor with pressure-sensitivity test data for each sensor and the estimated depth change from atmospheric to installation corrects for pressure effects on the SSSA. The system only requires correction at depths greater than 200 m.1

BMT's ROV-deployable SSSA has a support frame for the sensor package clamped to the pipeline or riser before installation starts. This frame provides an anchor for the ROV, ensuring fitting and adjustment of the sensors without damage.

Aerogel progress

Aspen Aerogels completed delivery in March 2009 of its Spaceloft advanced thermal insulation to Technip for a 21-km subsea natural gas pipeline connecting Petrobras's Canapu field (1,700 m deep) to its Cidade de Vitoria floating production platform in 1,400 m water depths. Technip installed the insulation on the piping at its spoolbase in Mobile, Ala., before transport to Brazil.

The Canapu-CdV pipeline is the first in Brazil to use pipe-in-pipe design (production pipe surrounded by carrier pipe with insulation in between). Spaceloft's flexible blanket form simplified installation into the annulus between the two pipes.

Spaceloft is a hydrophobic, flexible nanoporous aerogel blanket insulation with nominal thicknesses of 5 mm and 10 mm, allowing use of a smaller and less costly outer pipe. Spaceloft's combination of silica aerogel and reinforcing fibers has a maximum use temperature of 390° F. and a nominal density of 9.4 lb/cu ft. Its R-value = 10.3/in. Fig. 5 shows its ASTM C 177 thermal conductivity.

Technip Offshore UK previously prequalified Aspen aerogel products for pipe-in-pipe reeling and offshore operations, deploying subsea pipe-in-pipe systems in both the Gulf of Mexico and offshore West Africa (OGJ, July 10, 2006, p. 57).

Reference

  1. Zimmerman, C., Edwards, R., de la Cruz, D., Talmont, P., Duley, D., and Maroju, S., "Recent Experience With A Comprehensive Riser Tower Monitoring System," DOT International conference, New Orleans, Feb. 3-5, 2009.