Application of Low-Dosage Hydrate Inhibitors in Deepwater Operations

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Summary Novel low-dosage hydrate inhibitors (LDHI) have been developed for applications in oil and gas fields. A new generation of kinetic inhibitors has been used to prevent hydrate formation frequently encountered in deepwater operations. These chemicals effectively inhibit hydrate formation, regardless of the water cut in the system. They also exhibit a low toxicity that leads to very favorable environmental ratings. Valuable experience has been learned from recent laboratory studies and field trials with respect to the application limits and implementation techniques for these new products. The key to the overall success is a full integration of a good front-end design, a comprehensive deployment plan, and an effective monitoring program. An overview of the chemistry of these new inhibitors is discussed briefly along with their performance under simulated deepwater conditions. In addition, the effect of LDHI on hydrate formation and the effect of pressure on LDHI performance are addressed. Introduction Formation of natural gas hydrates is a major concern for the offshore production of oil and gas. Hydrates are crystalline, ice-like solids that form when gas molecules are trapped in hydrogenbonded water cages under high pressure and low temperature conditions. 1,2 These conditions are very typical for deepwater operations, where water depth is 3,000 ft or greater. For example, the temperature of water at this depth in the Gulf of Mexico stays around 39°F throughout the year. The challenges of hydrate control in deepwater operations emerge from the harsh environment and the inaccessibility. The cost of failure can be very high because of the high remediation cost and a significant loss in revenues. Deepwater wells must produce large volumes of oil and gas to justify their development costs. Even a short-term interruption in production can cost the operator millions of dollars. Hydrate formation is typically inhibited by a number of established methods, such as dehydration, heat management, and chemical inhibition.1,2 Though any one of these methods can be effective in preventing hydrates, some may not be feasible or desirable for deepwater operations. For example, dehydration is not possible for subsea wells or small platforms with limited space. Heating and insulation can be used independently or jointly; however, it may not be cost-effective for longer flowlines to carry high GOR (gas/oil ratio) fluids. Chemical inhibition with thermodynamic inhibitors is by far the most commonly used method for hydrate control. These inhibitors have the ability to shift hydrate equilibrium curves toward higher pressures and lower temperatures by lowering the activity of water molecules. As a result, the operating condition is forced out of the hydrate's stable region. Methanol and ethylene glycol are the most popular choices for this inhibitor type because of their low cost and widespread availability. Despite the fact that the use of thermodynamic inhibitors is very effective, the required concentrations can be extremely high. The effective dosage is dependent upon the severity of the condition. This is usually measured as the degree of subcooling, defined as the difference between the hydrate dissociation and the operating temperatures at a given pressure. Most of the new developments in deepwater environments are challenged with a high degree of subcooling. Controlling hydrates in these operations would mandate that a large volume of thermodynamic inhibitors be shipped offshore, which complicates logistics and raises safety concerns. In some cases, it is impossible to pump such a high volume of inhibitors because of constraints in the pressure rating and delivery capacity. Therefore, an alternative inhibitor with a much lower effective concentration is very desirable for deepwater operations. A new group of nonthermodynamic chemical inhibitors has been developed recently. These chemicals are very different from traditional thermodynamic inhibitors because they do not shift the thermodynamic equilibrium of hydrate formation.3-17 Instead, they interfere with the process of hydrate formation by means of a number of proposed mechanisms.17-19 Because the effective dosages for this new type of inhibitor are much lower than those required for thermodynamic inhibitors, the new inhibitors are usually classified as LDHIs. These inhibitors are categorized in different groups on the basis of their working mechanisms. Some inhibitors, such as special surfactants, disperse hydrate particles as they form.4-6 Some, such as kinetic hydrate inhibitors (KHI) or threshold hydrate inhibitors (THI), inhibit hydrate formation for a long period of time by extending the induction time for hydrate formation. 12-17,19 Others, such as antiagglomerants (AA), modify the hydrate particles by changing the agglomeration of hydrate crystals.7-11,18 Surfactant-type inhibitors can reduce the risk of hydrates sticking to the pipe, minimizing the chance of hydrate plug formation. Some of these surfactants can make oil-in-water emulsions that interfere with the hydrate crystallization process. AAs are thought to have the ability to change the crystal size of hydrates and the morphology of their agglomerates by incorporating the inhibitor molecule into the hydrate crystal lattice.18 As a consequence, the resulting hydrates are slush-like and transportable. KHIs are believed to interfere with the hydrate nucleation step and/or the crystal growth process. The interference slows the kinetics and, consequently, extends the induction time for hydrate formation.19 The induction time is defined as the duration beginning when the system falls into the hydrate-forming region until the onset of hydrate formation. KHIs are usually polymer-based chemicals. The inhibitors discussed in this paper belong to this group. Among various types of LDHIs, AA and KHI are the most popular in the petroleum industry. There are advantages and disadvantages associated with the use of both AA and KHI. In general, AA can handle a higher degree of subcooling and sustain a longer shut-in period. However, these chemicals are typically more toxic than KHI polymers. A minimum of 50 to 70% oil cut is needed for an AA to work. AAs may also cause production problems, such as bad water quality and emulsions. Also, pumping the resulting hydrate slurries can be a concern for the operator because of potential problems associated with erosion, overpressure, oversize pump availability/operability, increased energy consumption, and lack of experience. In contrast to AA, KHI is more environmentally friendly, works in any water/oil ratio (WOR), and provides a hydrate-free environment. However, the present KHI technology is limited to a lower degree of subcooling and a shorter shut-in period compared to AA technology.

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