Pipeline rehabilitation is becoming an economic necessity as aging flowlines are required to last longer. Regulatory agencies in North America are also requiring that the pipelines carrying the crude oil, produced water and raw natural gas be more reliable and have fewer leaks. Combine the economic climate and the environmental and safety issues with the increasing cost to inhibit these systems and the need for a maintenance free pipeline corrosion system becomes a requirement for long term operation of corrosive oilfield systems. Polyamide 11 liners are now being used to extend the useful life of production flowlines under conditions than other liner materials previously used.
High density polyethylene (HDPE) has been used as a liner material more extreme in oilfield water injection systems for several years with an excellent service record. The broad range of operating temperatures, good chemical resistance to oilfield waters, cost and ease of joining has allowed the HDPE to become the primary choice of liner material for water handling systems.
Because of the success in lining water handling systems, HDPE liners were then installed in oil producing systems at relatively low operating temperatures (20 ºC - 30 ºc). Most of these systems had high percentages of water produced with the oil and again the HDPE liners were successful. Some of the effects on the liners in the oil systems noted were discoloration of the HDPE and swelling of the liner in either the radial direction or in the axial direction.
The discoloration of the HDPE was due to the hydrocarbon being absorbed in the material and does not effect the liner integrity but can cause porosity if a fusion is attempted.
Axial growth of the liner can cause the liner to fail by tearing the HDPE pipe away from the HDPE flange. The liner would expand into the adjoining flange area and usually had to be cut to allow spreading of the flanges. Radial growth generally resulted in slight collapse of the liner due it’s inability to move in the radial direction. Collapse of the liner near the flange face has resulted in failures due to tearing of the HDPE pipe.
Discussion
High temperature and gas systems
Because of the previous successes in oil systems, liners were then installed in higher GOR and hotter oil systems as well as gas and gas condensate flowlines. An HDPE liner was installed in a high water cut, sour gas and condensate well in Canada which operated at approximately 65° C and 7 Mpa, see table 1. The produced fluids were extremely corrosive and the cost to inhibit the flowline were prohibitive; therefore, it was decided to install a HDPE liner in the flowline.
A problem with the HDPE liner began to show up after approximately six months in the flowline with excessive pressures building up in the annulus space between the liner and the steel carrier pipe.
