Save 20% on select titles with code HIDDEN24 - Shop The Sale Now
As traditional reserves deplete onshore and offshore, the oil industry is moving into increasingly deeper waters and harsh environments in the pursuit of hydrocarbons. As the industry drills deeper, the challenges that face infrastructure increase markedly with the longstanding issues of corrosion. One of the major challenges to corrosion management is the extreme pressure and temperature.
High pressure, high temperature (HPHT) corrosion in sour conditions is a major concern in oil and gas production. Here, the selection of corrosion inhibitor is a significant challenge in oil and gas industry. This paper presents the results using HPHT Hastelloy RC autoclave for the performance study of corrosion inhibitor with high H2S/CO2 environments and high shear stress of 25 Pa in 80 % water cut. The sour corrosion testing conditions were the combination of 16.8 bar H2S concentration and 12 bar CO2 concentration with the temperature of 121 oC. Triplicate API 5L X65 weight-loss coupons were used in the test. Some important standard tests (e.g. thermal stability, emulsification tendency, foaming tendency, and solubility) with material compatibility test (Alloy 825) were also presented. The test results show that the average corrosion rates using weight-loss coupons are less than 0.1 mm/yr with low corrosion inhibitor concentration. No pitting corrosion was observed.
Cast Iron with its ancient history, traced back to 6th century BCE1, has been used for centuries to anything from manhole covers & fire hydrants to bridges. However, the development of Spheroidal Graphite Cast Iron (SGCI) or Nodular Cast Iron, in the 1940’s, with resulting improvement in mechanical properties such as ductility and fracture toughness, paved the way for further growth in industrial usage of cast iron.2 The material has been adopted by several industries such as automotive-, nuclear-, and wind turbine industry. During the last decade, SCGI has gained increased attention as construction material for subsea equipment in offshore oil & gas production, mainly competing with welded and bolted steel assemblies.
We are unable to complete this action. Please try again at a later time.
If this error continues to occur, please contact AMPP Customer Support for assistance.
Error Message:
Please login to use Standards Credits*
* AMPP Members receive Standards Credits in order to redeem eligible Standards and Reports in the Store
You are not a Member.
AMPP Members enjoy many benefits, including Standards Credits which can be used to redeem eligible Standards and Reports in the Store.
You can visit the Membership Page to learn about the benefits of membership.
You have previously purchased this item.
Go to Downloadable Products in your AMPP Store profile to find this item.
You do not have sufficient Standards Credits to claim this item.
Click on 'ADD TO CART' to purchase this item.
Your Standards Credit(s)
1
Remaining Credits
0
Please review your transaction.
Click on 'REDEEM' to use your Standards Credits to claim this item.
You have successfully redeemed:
Go to Downloadable Products in your AMPP Store Profile to find and download this item.
Metallizing in NH was a coating used only sparingly in the past at critical locations on two major bridges. Its greater use was severely limited by the lack of qualified applicators, absence from bridge fabricator operations, and overall excessive cost. This picture changed dramatically with the impetus of the new metallized Memorial Bridge project and the massive investment in metallizing equipment at a large local bridge fabricator that made metallizing possible for this bridge. The successful use and ten-year performance of the thermal spray coating (TSC), i.e. metallizing, on this bridge has had a significant impact on metallized New England bridges tofollow.
Offshore assets such as drilling rigs, production platforms, and wind turbines present challenges for corrosion prevention maintenance. The primary defense against atmospheric corrosion on structural steel in offshore saltwater environments is a protective coating system.
Several factors cause protective coatings to degrade rapidly: besides wearing and damage encountered in installation and use, ultraviolet light breaks down the organic resins and corrosive seawater causes under creep at any breaks in the coating. Maintenance coating for offshore atmospheric systems can therefore be necessary as early as the second year.