Gas Hydrates recovery methods, issues and solution for its prevention

Recovery of Gas Hydrates

We can recover gas hydrates through various methods;

1. Thermal Stimulation Method.
2. Depressurization Method.
3. Inhibitor Injection Method.
4. Carbon Dioxide Injection Method.

Thermal Stimulation Method

The thermal stimulation approach involves raising the hydrate temperature above the stability point, causing the hydrate to dissociate. Thermal stimulation requires a continuous energy source to overcome the endothermic heat of dissociation.

Figure 1 Thermal injection method.

Depressurization Method

Depressurization involves lowering the hydrate pressure below the stability point, causing the hydrate to dissociate. Depressurization results in rapid hydrate dissociation, but with an associate drop in the hydrate temperature. Without an external heat source, depressurization lowers the hydrate temperature to a new equilibrium condition, halting the depressurization process.

Figure 2 Depressurization method.

Disadvantages

There are the following disadvantages of the depressurization methods; i.e., Production of water and disturbing the marine life.

Inhibitor Injection Method

Inhibitor injection involves the injection of an organic or inorganic compound that shifts the hydrate equilibrium point to lower temperatures for isobaric conditions. As with depressurization, inhibitor injection could require additional inhibitor or a heat source to compensate for the decrease in hydrate temperature with dissociation.

The most common thermodynamic organic inhibitors are methanol, monoethylene glycol (MEG) and diethylene glycol (DEG) commonly referred to as glycol. Dissolved salts (e.g., NaCl, CaCl2, KCl, NaBr) can also be inhibitors.

Figure 3 Inhibitor injection method.

Disadvantages

The disadvantages of the inhibitor injection method are; environmental impact, economic costs and thermal self regulation of gas hydrates.

Carbon dioxide Injection Method

Under high pressure, low temperature sub oceanic conditions the hydrate structure can accommodate small molecules other than methane (CH4), such as carbon dioxide (CO2) and nitrogen (N2) in both the small and large cages. Although CO2 and N2 clathrates generally are not naturally as abundant as those of CH4, their occurrence forms the foundation of an unconventional approach for producing natural gas hydrates that involves the exchange of CO2 with CH4 in the hydrate structure.

Figure 4 Carbon dioxide injection method.

Gas Hydrate Resource Pyramid

The methane hydrate resource pyramid depicts hydrate resources according to reservoir type, gas recoverability, and estimated total in-place gas quantity.

Hydrate resources that are considered to be the most easily recoverable are found at the peak of the pyramid, while those that are the most technically challenging to extract lie at the base.

For example, hydrate in arctic sandstone reservoirs contains an in-place gas volume estimated to be in the 100’s of Tcf, while hydrate in marine sands is estimated to contain 1,000’s to 10,000’s of Tcf, and hydrate dispersed through marine muds is estimated to contain 100,000’s of Tcf.

Figure 5 Resource pyramid, Boswell et al., 2006 Peak Oil.

Issues of Gas Hydrates

Drilling in offshore regions: Increasingly complex challenges will be faced in offshore oil and gas drilling with increasing water depths. One of these challenges is the formation of gas hydrates. If shallow sediments that contain natural gas are encountered during deep-water drilling, this gas will enter into the drilling fluid leading to gas hydrate formation under low temperature and high pressure. Gas hydrate could easily formed when mud circulation was stopped and gas entered into the drilling fluid, Resulting in an unexpected gas kick during drilling operation, which will block the pipe, annular clearance or blowout preventer (BOP).

Figure 6 Offshore hydrate formation.

Therefore, since the 1990s, strict measures have been taken to prevent gas from forming hydrates in deep-water drilling. The main preventive measure is to add certain chemical compounds that cause drilling fluid to inhibit formation of gas hydrates like thermodynamic inhibitors and low-dosage hydrate inhibitors (LDHI). During deep-water oil and hydrate drilling, thermodynamic inhibitors normally are added to the drilling fluid, whereas kinetic hydrate inhibitors (KHI) are still under investigation.

Resource information: Although the Hikurangi Margin has been surveyed to some degree, more research is still required to map and appraise gas hydrate sweet spots in the area, and prioritize sweet spots for future development when the technology becomes available. More research into the characterization of the New Zealand gas hydrate resource is also required as methane compositions in hydrates can vary geographically, with resulting implications for extraction and production.

Technology & equipment: Commercial production technology is currently unavailable, although conventional oil and gas technologies could be adapted. Significant technical issues currently exist around extraction and transportation of gas hydrates.

Investment: The high levels of gas hydrate research may be an indicator of the potentially high cost of extraction and production technology when they become available. Access to the technology may require some level of government involvement or support, as occurred with the development of Maui. Attracting inwards private investment on the scale anticipated will require attractive policies and incentives, or better promotion of the higher prospectivity of the New Zealand gas hydrate resources relative to Alaska and Gulf of Mexico (the current focus of hydrate research by USA, Japan and Canada).

Infrastructure: Existing onshore Taranaki infrastructure could be utilized if the technical issues around extraction and transportation are successfully addressed. There may also be a business case for the development of new infrastructure on the East Coast of the North Island to be in closer proximity to the sweet spots on the Hikurangi Margin. Such infrastructure is likely to follow successful petroleum development in the region.

Environmental impacts: Negative feedback: Global warming leads to sea level rise and in increase of pressure. This leads to an increased hydrate stability and a decrease of the methane amount released from gas hydrates. Cooling results. Positive feedback: Global warming leads to an increase of bottom water temperature. This decreases hydrate stability and leads in turn to an increase of the methane amount released from gas hydrate. Further warming is the result. There are a number of environmental issues currently being debated internationally around gas hydrates. The ‘Smoking Gun’ hypothesis suggests that the release of methane into the atmosphere from disassociating gas hydrates creates one of two climate change scenarios.

Figure 7 Positive and negative feedback of  climate change. 

Solutions for Prevention of Gas Hydrates

By the use of model: The first step in controlling hydrate formation is to know the¡ pressure and temperature conditions in the well by PVT simulators.  A number of computer simulators are available for this purpose usually as adjuncts to more general phase PVT simulators. The models vary in how well they compute the chemical activity of the water phase, the effect of higher-molecular-weight hydrocarbons, and the effect of hydrate inhibitors. The second control step is the comparison of this information with the measured or expected PT profile within the production system. A method of coping with hydrate formation is then selected.

Environmental Inhibitors: The conceptually simplest “environmental inhibition” method is to dry the gas before it is cooled remove the water and hydrates so they cannot form. This involves adsorption onto, for example, silica gel, or cooling and condensation, absorption of water into alcohols, or adsorption onto hydroscopic salts.

Drilling Fluids and strings: Hydrates can plug drill strings, blowout preventers, chokes, and other equipment, sometimes requiring the abandonment of drilling operations because of safety constraints. Water-based drilling fluids are particularly susceptible to hydrate formation. The most important variable affecting hydrate formation is the activity of the water, which is decreased by chemicals that dissolve by bonding to water molecules.

It is important to recognize that other non soluble drilling-fluid components (e.g., mud solid particles or fluidizers) may affect the kinetics or rate of hydrate formation to determine how rapidly hydrates will form or decompose.

Kinetic inhibitors: These chemicals are polymers with carbon backbones and pendant groups, which adsorb into partially formed hydrate cages to keep the polymer anchored along the hydrate-crystal surface. Growing hydrate crystals are forced to grow around the polymer, stabilizing the hydrates as small particles in the aqueous phase. No liquid hydrocarbon need be present. Field tests have shown these chemicals to be effective at sub coolings up to ΔT = 20°F, at dosages from 550 to 3,000 ppm in the water phase. There is concern about these chemicals with respect to performance on shut-in and restart; also, a substantial amount of hydrate normally forms upon inhibitor failure.

Emulsifiers: These chemicals work by stabilizing small hydrate particles in an oil phase. Some oils contain natural emulsifiers such that, even with favorable hydrate formation conditions, the water, which might convert to hydrates, is stabilized within the oil phase. Artificial emulsifiers have been shown to be effective, preventing hydrate plugs in flow loops. There are concerns about these chemicals regarding the expense of tailoring them for each oil application and the cost associated with emulsion breaking.

Insulation and heating: Because fluids come from the reservoir at high temperatures, a low cost solution is to preserve the reservoir temperature (or add heat to the line) to keep the system out of the hydrate region. There are three types of insulation listed in ascending order of cost: coatings applied to pipes; pipe-in-pipe (PIP) or bundling; and vacuum-insulated pipes or pipes with insulating gases. In combination with insulation, line heating may be done through resistance or induction heating, with practice favoring the former. Heating costs are very high, second only to chemical treatment, and the power for heating is generated on platforms, where typically only 5 to 10 MW may be available.