Natural gas hydrates are composed of approximately 85 mol% water; therefore, they have many physical properties similar to those of ice. For instance, the appearance and mechanical properties of hydrates are comparable to those of ice. The densities of hydrates vary somewhat due to the nature of the guest molecule(s) and the formation conditions, but are generally comparable to that of ice. Thus, hydrates typically will float at the water/hydrocarbon interface. However, in some instances, hydrates have been observed to settle on the bottom of the water phase. If a hydrate plug breaks from the pipe walls, it can be pushed down along the flowline by the flowing of hydrocarbon fluid like an ice bullet, potentially rupturing the flowline at a restriction or bend.
Four components are required to form gas hydrates: water, light hydrocarbon gases, low temperature, and high pressure. If any one of these components is absent, then gas hydrates will not form. Hydrate problems can appear during normal production, but transient operations are often more vulnerable. For instance, during a shut-down, the temperature of the subsea line drops to that of the surrounding environment. Given sufficient time under these high pressures and low temperatures, hydrates will form.
The extent to which the gas, oil, and water partition during shutdown somewhat limits the growth of hydrates; although direct contact between the gas phase and the water phase is not needed for hydrate formation, an intervening oil layer slows transport of the hydrate-forming molecules. Additionally, hydrates typically form in a thin layer at the water/oil interface, which impedes further contact between the water and gas molecules. Even if the flowlines do not plug during shutdown, when the well is restarted, the agitation breaks the hydrate layer and allows good mixing of the subcooled water and gas. Rapid hydrate formation often leads to a blockage of flow at low spots where water tends to accumulate. Plugging tendency increases as the water cut increases, because there is a higher likelihood that sufficient hydrate particles will contact each other and stick together. Other typical locations include flow restrictions and flow transitions, as occurs at, for instance, elbows and riser bases.
Hydrate plugs may also occur in black oil subsea systems. Most deepwater black oil systems are not producing significant volumes of water. As water cuts rise, the incidence of hydrate plugs in black oil lines will certainly increase. Some black oils have a tendency not to plug, even when hydrates are formed. The hydrates remain small particles dispersed in the liquid phase and are readily transported through the flowline. These back oils will eventually plug with hydrates if the water cut gets high enough.
Hydrate Formation and Dissociation
Hydrate formation and dissociation curves are used to define pressure/ temperature relationships in which hydrates form and dissociate. These curves may be generated by a series of laboratory experiments, or more commonly, are predicted using thermodynamic software such as Multi-Flash or PVTSIM based on the composition of the hydrocarbon and aqueous phases in the system. The hydrate formation curve defines the temperature and pressure envelope in which the entire subsea hydrocarbons system must operate in at steady state and transient conditions in order to avoid the possibility of hydrate formation.
of the dissociation curve is the region in which hydrates do not form; operating in this region is safe from hydrate blockages.
To the right of the dissociation curve is the region in which hydrates do not form; operating in this region is safe from hydrate blockages. To the left of hydrate formation curve is the region where hydrates are thermodynamically stable and have the potential to form. This does not mean that hydrates will necessarily form or that formed hydrates will cause operational difficulties. The stability of hydrates increases with increasing pressure and decreasing temperature. There is often a delay time or the temperature must be lowered somewhat below the hydrate stability temperature in order for hydrates to form. The subcooling of a system is often used when discussing gas hydrates, which is defined as the difference between hydrate stability temperature and the actual operating temperature at the same pressure. To the right
The subcooling of a system without hydrate formation leads to an area between the hydrate formation temperature and the hydrate dissociation temperature, called the metastable region, where hydrate is not stable. Some software packages attempt to predict this metastable region. Regularly operation within this metastable region is risky. While such differences in hydrate formation and dissociation temperatures are readily observed in the laboratory, the quantitative magnitude of this hysteresis is apparatus and technique dependent. Hydrates may not form for hours, days, or even at all even if a hydrocarbon system containing water is at a temperature and pressure conditions close to the hydrate dissociation curve. A certain amount of “subcooling” is required for hydrate formation to occur at rates sufficient to have a practical impact on the system.
When subcooling increases, the hydrate formation time decreases exponentially. In general, subcooling higher than 5 F will cause hydrate formation to occur at the hydrocarbon/water interface in flowlines. A thermodynamic understanding of hydrates indicates the conditions of temperature, pressure, and composition at which a hydrate may form. However, it does not indicate where or when a hydrate plug will form in the system. Hydrate plugs can form in just a few minutes, or take several days to block production. There are two mechanisms of plug formation, one in which hydrates slowly build up on the bottom of the pipe, gradually restricting flow, and the other in which hydrates agglomerate in the bulk fluid, forming masses of slush that bridge and eventually block the flow. Both mechanisms have been observed in the field, although the latter is believed to be more prevalent.
The mechanics of plug formation are not yet well understood, although it is known that certain geometries, such as flow restrictions at chokes, are prone to hydrate plug formation. Control of hydrates relies on keeping the system conditions out of the region in which hydrates are stable. During oil production operations, temperatures are usually above the hydrate formation temperature, even with the high system pressures at thewellhead (on the order of 5000 to 10,000 psi). However, during a system shutdown, even well-insulated systems will fall to the ambient temperatures eventually, which in the deep GoM is approximately 38 to 40 F.
Many methods are available for hydrate formation prediction. Most of them are based on light gas hydrocarbon systems and vary in the complexity of the factors utilized within the computational procedures. The Peng-Robinson method is one typical equation of state (EOS) method that is currently extensively utilized to predict hydrate boundaries. Knowledge about hydrates has significantly improved in the past 10 years. Hydrate disassociation can be predicted within 1 to 3 with the exception of brines that have a high salt concentration. The hydrate disassociation curves typically provide conservative limits for hydrate management design. The effects of thermodynamic hydrate inhibitors, methanol and ethylene glycols, can be predicted with acceptable accuracy. When the temperature and pressure are in the hydrate region, hydrates grow as long as water and light hydrocarbons are available and can eventually develop blockages. Clearing hydrate blockages in subsea equipment or flowlines poses safety concerns and can be time consuming and costly.
Hydrate formation is typically prevented by several methods including controlling temperature, controlling pressure, removing water, and by shifting thermodynamic equilibrium with chemical inhibitors such as methanol or monoethylene glycol, low-dosage hydrate inhibitors.
Effects of Salt, MeOH, and Gas CompositionThe hydrate dissociation curve may be shifted toward lower temperatures by adding a hydrate inhibitor. Methanol, ethanol, glycols, sodium chloride, and calcium chloride are common thermodynamic inhibitors. Hammerschmidt suggested a simple formula to roughly estimate the temperature shift of the hydrate formation curve:
The Hammerschmidt equation was generated based on more than 100 natural gas hydrate measurements with inhibitor concentrations of 5 to 25 wt% in water. The accuracy of the equation is 5% average error compared with 75 data points. The hydrate inhibition abilities are less for substances with a larger molecular weight of alcohol, for example, the ability of methanol is higher than that of ethanol and glycols. With the same weight percent, methanol has a higher temperature shift than that of glycols, but MEG has a lower volatility than methanol and MEG may be recovered and recycled more easily than methanol on platforms.
Salt, methanol, and glycols act as thermodynamic hydrate inhibitors that shift the hydrate stability curve to the left. Salt has the most dramatic impact on the hydrate stability temperature. On a weight basis, salt is the most effective hydrate inhibitor and so accounting correctly for the produced brine salinity is important in designing a hydrate treatment plan. In offshore fields, MEG found more application than DEG and TEG because MEG has a lower viscosity and has more effect per weight. The solubility of salt to water has a limit based on the temperature. More small molecular components results in a lower hydrate formation at the same pressure. More weight percentage of methanol leads to a greater temperature shift of the hydrate formation curve.
Mechanism of Hydrate InhibitionTwo types of hydrate inhibitors are used in subsea engineering: thermodynamic inhibitors (THIs) and low-dosage hydrate inhibitors (LDHIs).
The most common THIs are methanol and MEG, even though ethanol, other glycols (DEG, TEG), and salts can be effectively used. They inhibit hydrate formation by reducing the temperature at which hydrates form. This effect is the same as adding antifreeze to water to lower the freezing point. Methanol and MEG are the most commonly used inhibitors. LDHIs include anti-agglomerates and kinetic inhibitors. LDHIs have found many applications in subsea systems in recent years. LDHIs prevent hydrate blockages at significantly lower concentrations, for example, less than 1 wt%, than thermodynamic inhibitors such as methanol and glycols. Unlike thermodynamic inhibitors, LDHIs do not change the hydrate formation temperature. They either interfere with formation of hydrate crystals or agglomeration of crystals into blockages. Anti-agglomerates can provide protection at higher subcooling temperatures than can kinetic hydrate inhibitors. However, low-dosage hydrate inhibitors are not recoverable and they are expensive. LDHIs are preferred for regular operations because they reduce volumes and can work out to be cheaper. For transient events, the volumes required are not usually that large, so there is not much benefit in LDHIs, and methanol becomes the preferred inhibitor.
THIs inhibits hydrate formation by reducing the temperature at which hydrates form by changing the chemical potential of water. This effect is the same as adding antifreeze to water to lower the freezing point. This includes methanol, glycols, and others. In general, methanol is vaporized into the gas phase of a pipeline, and then dissolves in any free water accumulation to prevent hydrate formation. Hydrate inhibition occurs in the aqueous liquid, rather than in the vapor or oil/condensate. Although most of the methanol dissolves in the water phase, a large amount of methanol remains in the vapor or oil/condensate phase; therefore, the proportions of methanol dissolved in the vapor or oil/condensate liquid phases are usually counted as an economic loss.
Low-Dosage Hydrate Inhibitors
Kinetic inhibitors (KIs) are low-molecular-weight water-soluble polymers or copolymers that prevent hydrate blockages by bonding to the hydrate surface and delaying hydrate crystal nucleation and/or growth. They are dissolved in a carrier solvent and injected into the water phase in pipelines. These inhibitors work independently of water cuts, but are limited to relatively low subcooling temperatures (less than 20 F), which may not be sufficient for deepwater applications. For greater subcooling, KIs must be blended with a thermodynamic inhibitor. Additionally, the inhibition effect of KIs is time limited and, thus, their benefit for shut-down is limited. KIs have been applied in the North Sea and the Gulf of Mexico. Long-term shutdowns will require depressurization, which complicates the restart process, and methanol without KIs will be required for restarts. KIs are generally environmentally friendly.
Anti-agglomerates (AAs) are surfactants, which cause the water phase to be suspended as small droplets. When the suspended water droplets convert to hydrates, the flow characteristics are maintained without blockage. They allow hydrate crystals to form but keep the particles small and well dispersed in the hydrocarbon liquid. They inhibit hydrate plugging rather than hydrate formation. AAs can provide relatively high subcooling up to 40 F, which is sufficient for deepwater applications and have completed successful field trials in deepwater GoM production systems. AA effectiveness can be affected by type of oil or condensate, water salinity, and water cut. For deepwater gas developments, AAs can only be applied where there is sufficient condensate, such that the in situ water cut is less than 50%. Methanol may still be required for shutdown and restart. AAs have toxicity issues and may transport microcrystals of hydrate into and remain in the condensed/oil phase.
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