Automatic Welding Procedures For CRA Pipelines
Authors: Thompson T.S. , Laing B.S. 
Published: October 2008

The development by Shell Oil Company of the Fairway Field in the Gulf of Mexico, about four miles outside the entrance to Mobile Bay in Alabama, required installing four natural gas flowlines from well platforms to a central facility platform (CFP). The natural gas is at high pressure (10,600 psig), hot (up to 280 F), sour (2.1% H2S, 6.0% CO2, and 4.9% water), and very' corrosive. This required the use of corrosion-resistant-alloy (GRA) pipe. The pipe selected for the flowlines was 4 1/4-inch I.D., Nippon C-II, bimetallic pipe with a 3-mm thick Incoloy 825 liner pipe inside and mechanically bonded to a 0.623-inch-thick, API 5LX-70 carrier pipe.

Automatic welding procedures were developed and qualified for girth welding this C-II pipe by GRG-Evans Automatic Welding in Houston, Texas. The welding was done with GRC-Evans' proprietary welding system by the contractor, J. Ray McDermott. Special techniques had to be developed for this project.

DESCRIPTION OF PROJECT

The Fairway Field flowline project is located in the Gulf of Mexico, approximately four miles outside the entrance of Mobile Bay, Alabama. Offshore facilities are in the State of Alabama waters in Mobile Bay in blocks 113 and 132.

The field is operated by Shell Oil Company and produces natural gas from the deep Northlet formation at production rates presently averaging 40 MMcfd per well. In addition to having high wellhead pressure, the gas is hot, sour, and highly corrosive.

Gas is produced from four, outlying, single-well platforms and transported through the flowlines to a Central Facility Platform (CFP). The lengths of the four flowlines were as Follow:(Table available in full paper)

The maximum design operating pressure for the flowlines was defined by the maximum shut-in tubing pressure of 10,600 psig. However, under normal operating conditions, the gas pressure will be reduced at the wellhead to less than 2000 psig. The gas is produced at temperatures up to 280F, and cooled on the wellhead platforms to a maximum of 230F before entering the flowlines. The design natural gas composition includes 2.1 percent hydrogen sulfide, 6.0 percent carbon dioxide, and 4.9 percent water.

A very excellent, detailed description of the design and construction of the various components of this project was presented by Lanan and Barry at the 24th Annual OTC in Houston, Texas, May 4–7, 1992.

The paper presented here describes the development, and qualification of the procedures for girth welding the flowlines and the production welding of these flowlines.

BIMETALLIC FLOWLINE PIPE

The highly-corrosive gas required the use of a corrosion resistant alloy (CRA) pipe. Corrosion tests showed that a 3-mm-thick liner of Incoloy 825 (API 5LC LC30-2242) inside a carbon-steel carrier pipe was more than adequate for internal corrosion resistance. The bimetallic pipe was more economical than a solid CRA pipe design. The pipe diameter was 4.24-inch 1.0. of the Incoloy 825 liner inside a 0.623-inch thick API 5LX-70, carbon steel carrier pipe. Only the carbon steel diameter/wall thickness was considered in the design.