Wet gas contains a smaller quantity of methane occasionally can be less than 80 and a larger fraction of higher hydrocarbons (C2 to C6). These higher hydrocarbons components will imply a shift of the envelope to the right, when compared with the dry one, because the higher fraction of heavy components the fluid has, the further to the right is the two phase envelope. Like the dry gas, the isothermal conditions of the reservoir as the pressure is reduced while the fluid is being produced, the vapour phase is maintained, therefore, no liquid formation in the reservoir. However, the separator conditions will cross the dew point curve causing liquid formation at the surface (figure 1b). The heavier components are more valuable comparing with the light ones and they are sold at a premium price. With this assumption, it is worth to collect these liquids and leaving the vapour fluid as a dry gas for sale (mostly constituted by methane, CH4).
The prediction of the phase diagram of the gas in the reservoir has high importance. The behaviour of a gas constituted by pure components, has a well know two-phase region and only varies as a function of pressure and temperature, however, for multiple component fluids, like natural gas, the phase diagram varies as a function of pressure, temperature and composition. And this is who is possible to predict what kind of composes will be possible to collect at the surface facilities. Other important information possible to take from it is the amount of liquid possible to be produced that depends on the separator conditions and the iso-volume spacing lines for the mixture as shown in figure 2.
These two gases have a great importance for the field developments in offshore gas fields, since the production of them imply different types of facilities in the platform. The gas process has an effect on the gas quality and pressure regarding the delivery specifications. For the dry gas very little process is required, however for wet gases, some complex processes may be necessary (below is going to be explained in more detail). By all this reasons, is absolutely necessary to develop the phase diagram of the gas in the reservoir.
Figure 2: phase diagram for natural gases and iso-volume lines.
Gas export pipelines may be designed to operate in the dense-phase region. When the compression of the natural gas, is higher theÂ cricondenbar betweenÂ the critical temperature and cricondentherm, it becomes a dense, highly compressible fluid, and demonstrates properties of both liquid and gas The different regions of the phase envelope for a typical natural gas is shown in figure 3. "Fluid" is referred to anything that flows and is applied to gas and liquid.Â The dense phase presents a combination of both, similar viscosity to that of a gas, but a density closer of a liquid.Â These unique properties make dense phase attractive for transportation of natural gas. The gas pressure throughout the pipeline is maintained above the cricondenbar value, which ensures single phase state and no liquid formation will happen even if the temperature falls substantially. By this, is avoided slugging and a stable flow will be maintained. This is a favourable condition for transporting natural gas in dense phase.
Figure 3: Different regions of the phase envelope for a typical natural gas.
Gas processing facilities normally work at between 10 and 100 bar. Optimum recovery of heavy hydrocarbons is obtained between 20 and 40 bar. Long distance pipelines pressures can reach 150 bar and the gas re-injected as a gas drive can reach 700 bar. The gas process has an effect on the gas quality and pressure regarding the delivery specifications.
Surface Development for Gas Fields
The processing required in the gas field will depend on the composition of the gas and pressure and temperature that will be exposed during transportation. The process engineer has to develop conditions to avoid liquid formation, which may cause slugging, corrosion and possibly hydrate formation. The distinction of the dry and wet gas on the off-shore site is very important because for the dry gas the produced fluid is normally exported with little processing, and for the wet gases have to pass through some complex processes in order to avoid some components like:
Water vapour (can lead hydrate formation and in presence of CO2 and H2S may cause corrosion)
Heavy hydrocarbons (two phase flow or wax deposition in pipeline)
Contaminants such as carbon dioxide (corrosion) and hydrogen sulphide (corrosion, toxicity).
If the produced gas contains water vapour it may have to be dried by passing through a glycol-contacting tower, or by injection of glycol in the flow preventing hydrate formation (gas dehydration); to extract the heavy hydrocarbons the gas may be dried by dropping the pressure and temperature through a Joule-Thompson expansion valve. Contaminants removal is normally performed on-shore because of the equipment required. If the gas is dehydrated is enough to avoid corrosion. However, it may be necessary to perform some extraction to meet the pipeline specifications. Amine, an organic compound, can be used to absorb CO2 and H2S in contact towers. After all this processes, the gas may have to be pressurized before the evacuation, used for gas lift or re-injected as a gas drive.
For the re-injection, compression equipment is normally required to inject lean gas (mostly constituted by methane) into the reservoir to slow down the reduction of pressure. This process has great relevance for gas condensate reservoirs, because the reduction of pressure can spoil the extraction of the heavier components of the gas in the reservoir. Crossing the dew point curve under reduction of pressure at isothermal conditions, the gas starts to condense and liquid will be trapped inside the reservoir making impossible his recovery. In the figure 4, is an example when the gas compression is normally installed. The compression equipment represents high investment and large space in the surface facilities, and so, the installation can be delayed until becomes necessary reducing the initial investment and capital exposure.
Figure 4: Example of gas compression in a gas field.