This paper presents the first offshore commercial application of a proprietary kinetic hydrate inhibitor (KHI) developed by Exxon. KHIs are water-soluble, non-toxic1 polymers that inhibit hydrate formation in pipelines at much lower dose rates than methanol or glycol by greatly slowing the rate of hydrate crystal formation. The KHI first underwent laboratory testing in Exxon's 4-in diameter, 275-foot-long hydrate flowloop at pressures up to 1800 psi. It was then field-tested in a 2-in diameter, 1.5-mi-long buried gas flowline in Alberta, Canada in 1996-1997.2 Tests were conducted over a range of salinities and in the presence of methanol and glycol. The offshore KHI application took place in 1998 in an Exxon-operated gas pipeline in the Gulf of Mexico. Before KHI was introduced, the 8-in diameter, 28-mi pipeline required 300 L/day methanol injection to avoid hydrates. KHI injected at 5 L/day inhibited hydrate formation for over six months at approximately 6°F subcooling. Results will be presented for subcooling performance, start-up procedures, operability data, shut-in performance achieved, and cost omparisons to methanol inhibition. The major conclusion of this work is that kinetic hydrate inhibitors are more cost-effective than methanol in many applications. Successful shut-ins and restarts are achievable with kinetic inhibitors. Operability of kinetic inhibitors is similar to methanol. Introduction This paper describes the first offshore demonstration of a kinetic hydrate inhibitor (KHI) developed by Exxon. The KHI is comprised of a water-soluble polymer with the chemical name N-vinyl, N-methyl acetamide-co-vinyl caprolactam (VIMA-VCap). VIMA-VCap successfully inhibited hydrates in an 8-in, 28 mi long gas pipeline between Exxon Company USA's South Pass 89A (SP89A) and West Delta 73A/D (WD73) platforms. This pipeline, which experiences 5-10 °F subcooling year round, operated for over 6 months with as little as 1.3 gallons/day of dilute KHI solution. Prior to the demonstration, 79.3 gallons/day of methanol were injected into this pipeline for hydrate prevention. Hydrates and their impact on oil and gas production are widely discussed in the literature.3,4,5,6 Natural gas hydrates are ice-like solids which form when free water and natural gas combine at high pressure and low temperature. At these conditions, water molecules form polyhedral cages stabilized by light hydrocarbons or other natural gases (e.g., CO2 or H2S) inside the cage. Gas molecules in water cages combine with each other to form a macroscopic hydrate crystal. In a pipeline, hydrate crystals may flow as a slurry or adhere to the pipe wall and form a blockage depending on the contents and geometry of the line. Motivation for KHI Development. Hydrate inhibitor research is motivated by the cost to prevent the plugging tendency of hydrates. A flowline hydrate plug can cause significant downtime, especially offshore where access is difficult and hydrostatic pressures are high.7 Avoiding hydrate formation is preferable to removing a hydrate plug. The most common hydrate prevention methods include: Chemical hydrate inhibition. Traditional chemical inhibition has been to use large doses of methanol or glycols, to shift the hydrate equilibrium to lower temperatures and higher pressures. Methanol is also highly effective at melting hydrates that have already formed. However, large doses of these inhibitors increases operating costs and poses logistical difficulties in remote or offshore applications. Methanol can also cause the total hydrocarbon content of produced water to exceed the allowable limit for water disc

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

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This paper compares experimental data obtained on three high‐pressure devices and one atmospheric apparatus that measure hydrate formation onset and dissociation temperatures. The high‐pressure devices are rocking sapphire tubes, a 0.5‐inch diameter miniloop, and a 4‐inch diameter flowloop. High‐pressure miniloop results are compared to atmospheric pressure, tetrahydrofuran (THF) rig results in which chemically similar inhibitors ranked in different order. Although high‐pressure, stirred tank apparatus is considered by many to be effective in obtaining data of this kind, this paper does not include any stirred‐tank data. Many kinetics experiments are insensitive to the high‐pressure apparatus used. However, results of kinetic experiments obtained in different types of screening apparatus may not agree if the methods of hydrate detection are different. An example of a gas/condensate/brine system that would be difficult to characterize in a rocking‐cell or stirred‐tank apparatus is discussed.

In the fundamental (l=2) mode, the frequency spectrum of a magnetically levitated inviscid droplet exhibits three distinct peaks. If the modes that correspond to each of these peaks is known, the surface tension of the droplet may be calculated. In experiments that make use of this principle, there is no unambiguous method of assigning mode numbers to these peaks. The dynamics of the oscillating droplet depend on the magnetic pressure on the droplet surface. Consequently, the order of the peaks in the l=2 mode oscillations is determined by the magnetic pressure distribution. In this paper, the magnetic pressure distribution on the surface of the droplet is calculated as a function of the parameters that govern the external magnetic field. The frequencies of the droplet oscillation and its static shape deformation are also expressed in terms of these same parameters. The frequencies of oscillation are used to determine the surface tension of the liquid droplet. Finally, the magnetic pressure distribution on the droplet is shown to yield the well-known ‘‘pear-like’’ shape that is assumed by liquid metal droplets in a conical levitator.