Every natural gas storage facility is linked to the supply grid via an underground pipeline. Gas is transferred to the storage facility and fed back into the supply grid through this pipeline.
Incoming gas first flows through a filter, which separates solid particles and liquids. Then the gas flows through a calibrated volume meter. Compressor units powered by gas engines or turbines increase the gas pressure in order to inject the gas into the storage facility. Gas coolers then remove the heat generated during the compression process and the gas is pumped through high-pressure pipes into the wells and injected into the storage horizons.
The gas is withdrawn from the storage facility via the same wells through which it was injected. While in storage, gas absorbs water, which then has to be separated off to prevent any corrosion or gas hydrate formation in the pipeline.
The first step involves separating tiny free drops of water from the gas stream in the so-called free water knockout process. This water is injected into a water disposal well. The gas is then heated to prevent any gas hydrate formation in the processing facilities when pressure is reduced for the gas supply grid. The gas is dehydrated in a glycol absorption plant. Glycol’s hygroscopic qualities enable it to absorb the water vapour contained in the gas. After this, the gas is as it was when it was originally delivered to the storage facility and can be returned to the supply grid after calibrated volume measurement.
The process of withdrawing gas from the storage facility, described above, can only function if the pressure in the facility is high enough to press the gas into the pipeline. If this is no longer the case at the end of the withdrawal phase, compressors will again be employed.
During peak winter months, gas storage supplies almost 30 percent of all natural gas consumption in the United States.
The Energy Information Agency in the United States (“EIA”) reports weekly storage data. Most industry participants consider gas storage to be at full capacity when it hits approximately 3.2 Tcf and very empty when it gets down to approximately 0.7 Tcf. Therefore that actual amount of usable or practical storage capacity in the U.S. is approximately 2.5 Tcf.
The reality is that because storage capacity is very rate-sensitive, injection rates get lower as you fill up/pressure up the reservoirs. And withdrawal rates get lower as you empty storage reservoirs. With existing compression, there is only so much natural gas that can be moved into and out of storage during a year. We know that when the U.S. storage inventory gets down to 0.7 Tcf, the withdrawal rates are so low that in order to completely empty, it would likely take several years of continuous withdrawal.
Another interesting fact is that storage doesn’t always have to fill up. For example, when natural gas prices were running up in the summer of 2000, some of the non-regulated users of gas storage elected to take advantage of higher prices early, and didn’t top up storage levels going into the winter. This decision turned out to be a bad idea as low storage injection levels resulted in a subsequent price shock during the following winter.
The National Petroleum Council (NPC), a multi-company organization which studies supply and demand has advised that North America is “storage short” and that this problem isn’t going to go away.
An NPC study forecasts the need for about 700 Bcf of additional storage capacity out to 2025 to meet the demands of a normal winter. A more dramatic picture emerges if you drop the assumption that we will have normal weather every year.
The NPC analyzed a number of weather sensitivities by taking the last 25 years worth of heating degree days and cooling degree days and running this through their gas demand models for the future. The resulting forecasts showed the kind of wide variation in storage demand we have seen in the past.
More importantly, though, it shows that a significantly colder than normal winter, something we have not experienced for several years, would require a volume of seasonal gas storage which the industry has never before achieved. The most storage capacity that we have ever used in North America is 2.9 Tcf, and it is unlikely that current storage capacity could handle more than that without extreme price spikes and demand destruction in the winter, and possibly low prices and production shut-in in the fall.
So, in summary, these gas demand trends suggest that there will be a need for continued strong growth in storage capacity to meet “normal” weather requirements, and possibly points to inadequate gas storage capacity even now to meet the needs of a cold year.
Normally across North America, gas storage is either connected to or deemed connected to the major pooling points — called hubs or city gates. The transportation costs associated with moving gas in and out of storage vary from region to region, but generally shippers who use storage are not double-charged for transport; storage is typically viewed as a temporary holding point along the way from receipt to delivery rather than a “receipt and delivery” into storage and then again another “receipt and delivery” out of storage.
Also, most shippers and pipeline operators recognize there are system-wide operational benefits to having connected storage including improved load factors and efficiencies. On the TransCanada Alberta system, for example, there are no additional transportation tolls to move gas from the Nova Inventory Transfer pooling point (“NIT”) into or out of storage as long as the amount of gas that is stored comes back out onto the system. This same process works in a similar fashion with Niska’s operated storage in Oklahoma.
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