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Dry gas is mainly composed by methane (normally above 90%), contain small amounts of higher hydrocarbons components and also non hydrocarbons such as N2 and CO2. For dry and wet gases the temperature in the reservoir is higher than the maximum of the two-phase envelope, so in the reservoir conditions of pressure and constant temperature the dew point will never be reached (figure 1 - point 1 to point 2), so the gaseous state is maintained in the reservoir. In the figure 1, is possible to see the evolution of the pressure and temperature in the reservoir till the separator located at the surface (point 1 to point 3). As the production evolves and the fluid starts to enter in the surface facilities, the pressure and temperature decreases. The temperature and pressure of the separator at the surface for the dry gas is still out of the two-phase region, so no liquids are produced during the separation process. The reason for this is due to the lack of heavy components, the two-phase envelope is located mostly below the surface temperature.
Figure 1: Phase diagram for natural gases and iso-volume lines.
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, 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, for separator conditions it will cross the dew point curve causing liquid formation at the surface (figure 1 ââ‚¬" point 1 to 4).
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). These liquids are called plant products.
Also important to note the confusion of word wet means. The wet is referred to the hydrocarbons condensed liquids produced at the surface, not referring to be wet because of the water. However, reservoir gas is typically saturated with water.
Properties analysis for dry and wet gases, and required processes
The prediction of the phase diagram of the gas in the reservoir has high importance. The behaviour of a gas constituted by mixture of 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.
The phase diagram supported by Kayââ‚¬â„¢s rules is not enough to fully understand the amount of components in the reservoir. Like in figure 1, as an example, this phase diagram is for a mixture of components, being impossible to infer any conclusion of the individual pure components behaviour under pressure and temperature changes. The ideal gas approximation is not equations are not accurate enough, and real gases models have to be used to infer with high detail the condensation point of gases, at very high pressures (which is the case inside the reservoir). For this reason equation of state developed by, for example, Redlick-Kwong or Peng-Robinson models are used for pure gases analysis. These equations are an attempt to represent the behaviour of a pure gas by the initial proposal of the equation of state of Van der Waals for real gases.
Dry and wet gases have different have different composition, and this will affect the amount of processes in the surface facilities.
For the dry gas very little process is required. In terms of composition the surface dry gas is the same as the composition in the reservoir, and the specific gravity of the reservoir is also the same as the specific gravity of the reservoir gas. By this, a gas sample taken at the surface facilities can be analysed resulting the composition and specific gravity of the gas in the reservoir.
Instead for wet gases, while the fluid is being produced the pressure is dropping, from the reservoir to the surface facilities some liquid will condense. Thus, the composition of the gas at the surface will not be the same as the reservoir gas because of the condensation of some of intermediate and heavy components. This is important because is necessary to know the substances that will be possible to recover when the gas reaches the surface facilities.
Also is important to know the composition of the gas, in terms of water content levels and CO2 and H2S levels, because solid hydrates formation and corrosion has to be prevented in the production line to the surface and also in evacuation pipelines. By these reasons is strictly necessary to have the phase diagram available before making any decision on the field development scheme and the amount of processes necessary to take.
To evaluate the properties of the gas in the reservoir and decide if the gas has good viability to be produced it must be analysed the composition of the gas. But the production of phase diagram of the gas from the reservoir can be difficult to achieve with good accuracy. The reason why, is that the quality of the sample may not in its perfect condition. Then it has to be sent to the lab, which can take three weeks to arrive. After this a software program will make the prediction based on this sample. Depending on the software program can give different results, being subjected to some tuning, where software programs are based in different equations of state for real gases (like Redlick-Kwong or Peng-Robinson models). For all these reasons some deviation will be produced on the real arrangement of the phase diagram of the gas in the reservoir.
Wet gas field processes
Wet gases are normally separated in two-stage separation system. At the surface, this well stream is separated into stock tank liquid, stock tank gas and separator gas. The recombination calculations of the surface liquid and gases can determine the properties of the gas in the reservoir. Producing gas oil ratio of these three elements must also be known. This calculation simulates the laboratory recombination by the quantities of the gas oil ratio. But if the composition of the gas in the surface is unknown, the field engineer must base the estimation of the specific gravity of the reservoir gas from the production data. In this case, the quantities and properties of all surface gas streams are used for the calculation.
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 form solid hydrate which can cause obstruction and blockage in flow lines, chokes, valves, 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 or methanol 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 can be pressurized for the evacuation, used for gas lift or re-injected as a gas drive.
However, some offshore fields can evacuate gas and liquid in the same pipeline processing only the water vapour removal. This is enough to prevent any formation of solid hydrates, which can cause obstruction and blockage in flow lines, chokes, valves, Christmas trees, and for pipelines. This formation can happen in a pressure drop causing as well a substantial drop in temperature due Joule-Thompson effect. This drop in temperature is sufficient for the formation of hydrates. One common method to inhibit the hydrate formation is the injection of glycol or methanol into the upstream before the valve, choke or any other fitting causing pressure drop. For the pipeline evacuation the water vapour removal is important to reduce the risk of corrosion when CO2, H2S and nitrogen exist in significant quantities.
For example, in Troll field water removal is the only process made in offshore site before evacuation of the fluid. Was also build twin pipelines, because if any plugging starts to occur in one of them, the other pipeline is available to work without any loss of time for the plug be eliminated and normal condition be again achieved. To erase the plug is necessary to reduce the pressure until the fluid temperature lies above the hydrate formation temperature, equalise the pressure in both side of the pipeline, and inject inhibitors (like methanol) reducing by this the hydrate formation temperature for a given pressure. For the Gulfalks field, the pipeline is design with smaller pipelines connected to the production fluid pipeline to worm up the fluid throughout the entire pipeline and also methanol injection points to avoid the hydrate formation.