Laboratory Validation Of Kinetic Hydrate Inhibitors For Use In Sour Gas Fields

Abstract

Abstract A kinetic hydrate inhibitor (KHI) can only delay hydrate formation for a limited period of time (the hold time). Larger thermodynamic driving forces for hydrate formation result in shorter hold times. When using a KHI, an element of water must be produced out of a production system before the hold time elapses. The thermodynamic driving force for hydrate formation that a water molecule is exposed to whilst traveling through a production system is time-dependent and often complex. Detailed transient thermo-hydraulic simulations must be carried out to evaluate the worst-case "time-subcooling" history that a water molecule can experience during steady state flow and various transient operations. This time-subcooling history is taken as the basis for the experimental conditions of hydrate formation under which a KHI has to be tested in the lab. It also determines the required hold time. In addition to the time/driving force history, the hold time strongly depends on the composition of the condensate and gas and therefore the composition of the test fluids must closely match the composition of the pipeline fluids. The presence of other oil-field chemicals, in particular corrosion inhibitors that are used in sour gas/condensate systems, can significantly reduce the hold time and these chemicals must therefore be present during the testing. To further complicate matters, the observed hold times usually show large variations and depend on the type of test equipment used. Many kinetic inhibitors tend to precipitate or even form sticky clumps after injection in a warm water/condensate mixture. This behavior is affected by several factors, amongst which the pH of the water. This paper presents the procedures that Shell compiled to validate kinetic inhibitors for use in sour gas/condensate fields as well as some important (and sometimes surprising) observations made during this exercise. Introduction Natural gas hydrates (hereafter simply referred to as hydrates) are solid compounds that are formed when natural gas and water are in contact at elevated pressures and at reduced temperatures. Typically 85 % of the molecules contained in hydrates are water molecules that form smaller and larger cages which, when stacked together, form a relatively open crystal lattice. To form thermodynamically stable hydrates, part of the cages must contain smaller molecules amongst which the C1-C4 hydrocarbons, H2S and CO2 are the most familiar to the oil industry. Whilst forming under flowing conditions in pipelines, hydrates behave like wet snow in that the hydrate crystals accumulate into larger masses that can block even large diameter pipelines. The process of hydrate slug, and subsequently hydrate plug, formation is especially effective in gas/condensate lines. It has been observed, both in the field and in the lab, that the transition from a flow of gas, water and condensate into a fully developed hydrate slug flow can occur within minutes, even in systems that operate a few degrees inside the hydrate region. This rapid transition into hydrate slug flow is responsible for the formation of multiple hydrate plugs that have been observed in several gas/condensate systems that operated inside the hydrate region. To enable uninterrupted production, measures to prevent hydrate plug formation in gas condensate systems must be taken, even if such systems operate marginally inside the hydrate region. Chemical inhibition (the use of chemicals to prevent hydrate, or hydrate plug, formation) is one of these measures. Most commonly applied are the so-called thermodynamic hydrate inhibitors which, when dissolved in the water phase, depress the melting temperature of the hydrates to such an extent that this melting temperature becomes lower than the operating temperature of the system in which hydrate formation has to be prevented. As a ballpark figure one can assume that the melting temperature of the hydrates is depressed by 0.6–0.7 degrees centigrade for every mole% of thermodynamic inhibitor that is dissolved in the water phase1. This normally implies that significant amounts of inhibitor must be dissolved in the water phase to achieve sufficient suppression. For example, approximately 10 mol% (some 28w%) of MEG must be added in the aqueous phase to achieve a hydrate suppression of 7 degrees.