No abstract

We compare the kinetics of intersystem crossing at room temperature in different solvents for a family of aromatic ketones: benzophenone, anthrone, xanthone, and para-substituted benzophenones. We report our recent observations: (1) fast buildup (kf1 < 10 ps) of anthrone transient absorption in dioxane followed by a long {k2l ~175 ps) decay; (2) fast buildup {hr1 < 10 ps) of anthrone transient absorption in benzene; (3) fast buildup {k~l = 8 ± 2 ps) of benzophenone transient absorption in ethanol; (4) fast buildup (fe™1 = 6.5 ± 2 ps) of 4,4'-dimethoxybenzophenone transient absorption in benzene. We conclude that the rates of intersystem crossing for this family of aromatic ketones are all approximately the same.

The major parameters for a hydrate slurry flow model are suggested. A field trial in a once-through pipeline indicated a significantly confined operating region without plugging. The implication of these results is that current versions of hydrate cold flow will need to address hydrate film growth and deposition on pipewalls. Flow loop tests alone do not simulate the extent of plugging because of film growth or deposition. A unique learning in this work is that emulsified droplet distributions were measured as a function of watercut, surfactant concentration, and fluid velocity. Droplet size and droplet size distribution increased with an increasing watercut below the inversion point. Droplet size and droplet size distribution decreased with an increasing surfactant concentration. An increasing surfactant concentration limited wall deposits to some extent. An increasing fluid velocity reduced wall deposits and hydrate slurry viscosity. Wall deposits decreased with a decreasing gas void fraction.

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.