The Successful Use of Both Kinetic Hydrate and Paraffin Inhibitors Together in a Deepwater Pipeline with a High Water Cut in the Gulf of Mexico

Abstract

Abstract Under deepwater operating conditions, hydrates and wax can often form blockages in a pipeline. The resultant costs to remediate the situation include not only those for removing the blockage, but also for lost production. Potential hydrate preventative measures include Low Dosage Hydrate Inhibitors (LDHIs) which are limited by hydrate formation potential (known as subcooling that is measured in F degrees) and both fluid compositions and ratios. The subcooling for this application is very challenging, since it is between 15 F degrees under normal operating conditions and 27 F degrees under shut-in conditions. This field application was conducted on a pipeline for a newly re-completed well which was predicted to have water cuts in the 20% range. Actual water-cuts have typically been about 35% but have also increased to above 60% at times. The continuing evaluation of different chemistries and consequently different mechanisms for preventing hydrate and wax problems in a sub-sea pipeline is reviewed. A kinetic hydrate inhibitor (KHI) was injected after the production rates had stabilized. A wax inhibitor was also used because of previous concerns about possible wax blockage. The kinetic hydrate inhibitor was chosen based on data from lab testing and computer modeling. Not only is steady state operation often an issue, but shut-down and, more importantly, start-up are often the major concerns. KHIs are classified as LDHIs since only low concentrations (generally below 3%) are used. The KHI provided lower operating costs plus better environmental conditions than methanol, which had been used before the well was re-completed. The advantages and disadvantages of this KHI product are reviewed. Some of the advantages of KHIs (compared to methanol) include reduced logistics, removal of the undesirable methanol from the crude, plus no oil/water quality issues. This continuous injection application in the deepwater Gulf of Mexico is special since KHIs have generally not been used there. Most previous continuous injection case histories have been from the North Sea. Also, wax control additives were used in conjunction with the LDHIs. Introduction We will first review hydrates and then wax/paraffin from a historical viewpoint, then contol issues, and finally chemistries. Hydrates History. Hydrates were first described by Sir Humphrey Davis1 in 1810. They are formed when gas (often methane) and water are at the correct low temperature and high pressure. Although they can look like snow, they can form at a temperature much higher than the freezing point of water (32°F/0°C). They can plug flow lines, pipelines, valves and other equipment. Removing the blockages can also be dangerous, since the hydrate plug can become a "missile" when it is unblocked and the volume of gas created when the hydrate dissociates can be 150 times greater than the hydrate solid. The hydrates are actually cage-like structures called clathrates. Different types of structures have been noted with Type I and II being the most common.2 The formation of hydrates in gas pipelines was reported by Hammerschmidt3 in 1934. Hydrate problems were also noted by Exxon in 19854 with hydrate formation while drilling in well control lines (blowout preventer, BOP, lines).