Kinetic Hydrate Inhibitors - Sensitivity towards Pressure and Corrosion Inhibitors

Abstract

Abstract Replacement of the traditional thermodynamic hydrate inhibitors (methanol and glycols) in wet gas applications is more and more highly desirable for cost savings and for Health, Safety & Environment (HSE) considerations. This seems achievable by using alternative Kinetic Hydrate Inhibitors (KHI). KHIs are able to delay hydrate formation for the time needed to transport the effluents in hydrate region conditions. The KHI efficiency is generally based both on the subcooling that can be matched by the inhibitor and on the hydrate formation time delay that the inhibitor can provide. Within the frame of various Field Development studies carried out since 1990, we have had the opportunity to evaluate the performance of several KHIs. These evaluations have been conducted on two hydrate loop facilities with a service pressure of respectively 80 bara and 165 bara. Thanks to these two pilots, we have been able to observe and to quantify the influence of various parameters on the KHI efficiency. Among these parameters, two of them have proved to be of importance: the presence of other inhibitors, such as corrosion inhibitors (CI), and the operating pressure. Their strong influence is illustrated in this paper through the results obtained in three different case studies. The practical conclusion is that KHIs selected in "routine" lab tests may be not efficient in the field and that appropriate selection tests are required. Introduction From a flow assurance point of view, gas hydrate formation is undoubtedly dreaded as the major risk of plugging the oil and gas subsea production systems. Natural gas hydrates. Natural Gas hydrates are ice-like crystalline compounds that form whenever water molecules contact hydrocarbon gas molecules of low molecular weight (from methane to butane) or other gas molecules such as N2, CO2 or H2S. The hydrate crystals can be represented as a network of hydrogen-bonded water molecules forming cages with gas constituents trapped within. Three different structures have been identified: I, II and H. However, it is unlikely that the structure H exists in the oil and gas production systems. Consequently, only structure I and II are expected to form with natural gases under production conditions. These structures are illustrated in figure 1. Structure I and II are constituted by two kinds of cavity: a small one 512 found in both structures and a large one 512 62 and 512 64 for the structure I and II, respectively. These two structures can be stabilized by gas molecules having the molecular size in the range 3.5 - 7.5 Å. The structure I is stabilized by small gas molecules such as methane or ethane, and mixtures of both; but the presence of a small amount of a larger molecule like propane or iso-butane with methane/ethane results in the formation of structure II. As a consequence, structure II is, by far, the most common hydrate structure that can potentially form in the oil and gas production systems. Contrary to ice crystals, natural gas hydrate crystals are able to form at temperatures higher than 0°C as soon as the pressure is higher than a few tens of bar. Conditions promoting gas hydrate formation are high pressure (typically > 30 bara) and low temperature (typically < 20°C). Precise conditions in terms of pressure and temperature depend on the composition of the fluids. Hydrate formation can occur for all the produced fluids if required P-T conditions are reached: natural gas, gas with condensate and crude oil with associated gas, with condensed or formation water. Figure 2 shows typical curves delimiting, in a P-T diagram, the thermodynamic hydrate stability zones for a natural gas with condensate from North Sea, and for crude oil with associated gas from Gulf of Guinea. The region where hydrate crystals are thermodynamically stable is on the left side of the curve, no hydrate can form on the right side of the curve. General discussions on hydrate properties can be found in the literature1–4.