Hydrocarbon dew point

When a customer agrees to purchase gas, product quality is specified in terms of the calorific value of the gas, measured by the Wobbe index (calorific value divided by density), the hydrocarbon dew point and the water dew point, and the fraction of other gases such as Nj, COj, HjS. The Wobbe index specification ensures that the gas the customer receives has a predictable calorific value and hence predictable burning characteristics. If the gas becomes lean, less energy is released, and if the gas becomes too rich there is a risk that the gas burners flame out . Water and hydrocarbon dew points (the pressure and temperature at which liquids start to drop out of the gas) are specified to ensure that over the range of temperature and pressure at which the gas is handled by the customer, no liquids will drop out (these could cause possible corrosion and/or hydrate formation). 

Gas Water and hydrocarbon dew point, hydrocarbon composition, contaminants content, heating value. 

Facilities for the treatment and compression of gas have already been described in earlier sections. However, there are a number of differences in the specifications for injected gas that differ from those of export gas. Generally there are no technical reasons for specifications on hydrocarbon dew point control (injected gas will get hotter not cooler) although it may be attractive to remove heavy hydrocarbons for economic reasons. Basic liquid separation will normally be performed, and due to the high pressures involved it will nearly always be necessary to dehydrate the gas to avoid water drop out. 

Absorber oil units offer the advantage that Hquids can be removed at the expense of only a small (34—69 kPa (4.9—10.0 psi)) pressure loss in the absorption column. If the feed gas is available at pipeline pressure, then Httle if any recompression is required to introduce the processed natural gas into the transmission system. However, the absorption and subsequent absorber-oil regeneration process tends to be complex, favoring the simpler, more efficient expander plants. Separations using soHd desiccants are energy-intensive because of the bed regeneration requirements. This process option is generally considered only in special situations such as hydrocarbon dew point control in remote locations. 

Natural gas must meet certain specifications before it qualifies for fuel. It should also meet certain dew point characteristics before entering a transmission pipeline. Water dew point is controlled and maintained by stationary equipment such as molecular sieves or dehydration by glycol. Hydrocarbon dew point, on the other hand, can... 

Onshore or offshore gas plants are designed for either LNG rejection and gas injection, or LNG rejection and transmission for sale. In the case of offshore plants, onshore facilities further process the natural gas before transmission for sale. In either case, natural gas must be treated and then refrigerated to make rejection of heavy hydrocarbons possible. In plants where natural gas is treated for sale purposes, water and hydrocarbon dew points of the gas must also be controlled. 

The hydrocarbon dew point is reduced to such a level that retrograde condensation (i.e., condensation resulting from pressure drop) cannot occur under the worst conditions likely to be experienced in the gas transmission system. Similarly, the water dew point is reduced to a level sufficient to preclude formation of Cl to C4 hydrates in the system. 

A hydrocarbon dew point meter uses a chilled-mirror instrument by which almost invisible films, having sensitivities on the order of 1 ppm, become detectable. Optical fibers are used to detect the reduction of light intensity, and miniature thermocouples measure the surface temperature of the mirror. For total hydrocarbon measurement, the flame ionization analyzer is reliable and accurate, but it requires the attention of operators and also consumes compressed gases. 

In liquefied petroleum gas where the composition is such that the hydrocarbon dew point is known to be low, a dew point method will detect the presence of traces of water (ASTM D-1142). 

Figure 1. HYDROCARBON DEW POINT DIAGRAMS FOR SEVERAL NATURAL GAS BLENDS, AS PPEDICTED BY SRK EQUATION-OF-STATE...

We still had to determine the cause of the mechanical problems with the meter. A thorough analysis of the problem led to a simple solution that also eventually solved some of the other problems. A vaporizer was added to the enrichment LPG and the injection point was moved down stream of the meter. This addition solved not only the mechanical problems with the meters but also reduced the variation in gas composition seen by the meter. The Dew Point was now read before the addition of emichment, eliminating the question of hydrocarbon Dew Points. 

Natural gas produced at the well head has to be treated in several processing steps especially dehydration and hydrocarbon dew pointing to meet the required pipeline and quality specifications. Water and higher hydrocarbon have to be removed in order to avoid the build-up of gas hydrates. The commonly used state-of-the-art processes, such as absorption and cryogenic condensation, have shortcomings with respect to environmental aspects, energy consumption, weight and space requirements. A reliable and proven membrane process could offer a serious alternative in comparison to established techniques. 

Water from the reflux drum is recirculated into the overhead system just before the point at which water condensation begins. Where there are parallel condensing trains, the water must be uniformly distributed through spargers with a 10-psi to 20-psi pressure drop. Enough wash water must be recirculated to bring the overhead vapors to their calculated water dew-point temperature (see Appendix). Note that the vapor from the overhead of the crude lower is already at its hydrocarbon dew-point. 

As long as product is deposited within the micropores of the catalyst by capillary condensation only, there should be no problem, as the particle will behave as a dry one. Incipient wetness corresponds to a situation where hydrocarbon product starts to condense on the outer surface of the porous catalyst particle. This situation, which is characterized by the hydrocarbon dew point, marks the onset of particle agglomeration and defluidization. 

Sie et al. (1988) have derived a relation that gives the maximum a value permissible, and the limits of operating pressure, temperature and conversion level, ensuring trouble-free fluid-bed operation. For the synthesis of a product following AFS kinetics with a probability of chain growth a, the condition for operation above the hydrocarbon dew point can be stated as... 

The entering vapor quickly is cooled to the adiabatic saturation temperature with respect to water. Thus, the vapor superheat, plus the heat of vaporization of the higher-boiling hydrocarbons, is converted to heat of vaporization of water. The vapor then progresses up the column at the water dew point as well as the hydrocarbon dew point. The vapor leaving the quench tower normally is at a temperature about 8° to 14°F above the water feed temperature to the column top when trays are used. 

Regenerated catalyst solution is extracted via a nozzle located about midway on the oxidizer-settler vessel. This solution is recirculated back to the absorber column. The portion fed to the venturi-mixer is first heated to 120°F to ensure that the absorber is operated above the hydrocarbon dew point of the inlet gas. 

Carbon contamination of the produced sulfur can result from liquid hydrocarbon droplets in the feed gas or by condensation of feed gas hydrocarbons. This problem is besr avoided by operating the process about 10°F above the feed gas hydrocarbon dew point and by removing any hydrocarbon aerosol in the feed gas (compressor lube oil, etc.) with a coalescing filter (Allen, 1995). Yet another potential form of sulfur contamination can occur when the feed gas contains a significant amount of mcrcaptans. Any disulfides formed will lend to coat the surface of the sulfur particles. If the sulfur is to be recovered as a salable product, special attention needs to be paid to the design of the overall system to avoid production of low-quality, disulfide-contaminated sulfur. Elimination of mercaptans and heavy hydrocar-... 

Commercial applications of the Selexol solvent for simultaneous hydrocarbon dew-point control and natural gas dehydration are de.scribed by Epps (1994). A plant design used in several European installations pretreats natural gas before it enters a molecular sieve unit. The design is intended to meet a treated gas specification of a maximum of 0.50 mole% CO2 and a maximum of 6.5 mole% ethane and heavier components. A plant is de.signed to treat 26 MMsefd of gas at 32"F and 603 psia. Operating data for this plant, given in Table 14-12, show that it meets the CO2 and ethane-plus removal specifications. The plant also reduces the water content of the gas from 75 ppmv to 12 ppmv, decreasing the load on the molecular sieve unit, and removes a major fraction of the sulfur components. 

Preheat or reheat steps to raise the gas temperature sufficiently above its water and hydrocarbon dew point to prevent condensation in the module... 

The 850 Mscfd unit was installed in the No. 2 Reformer at the Cosmo Oil Refinery in Chiba. Japan. The process flow for the unit is shown in Figure 15-12. The reformer effluent is cooled, the liquid and gas separated, and the gas fed to an absorber to remove the heavy components. Gas from the absorber, containing approximately 80% hydrogen and 20% ntethane and saturated with absorption oil components at a dew point of 9S°F and a pressure of 398 psia, is fed to a filter separator to remove any residual liquids. It is then preheated to a temperature above the hydrocarbon dew point of the residual gas leaving the membrane unit and fed to the membrane separator. Heating the gas prevents condensation of the heavy hydrocarbons as the gas dew point increases with hydrogen removal. 

X3.3.1 Nonrepresentative samples frequently occur because of condensation of liquid. Maintain all samples above the hydrocarbon dew point. If cooled below this, heat 10 C or more above the dew point for several hours before using. If the dew point is unknown, heat above the sampling temperature. 

X3.6.1 Maintain the reference standard at +15 °C or a temperature that is above the hydrocarbon dew point. If the reference standard should be exposed to lower temperatures, heat at the bottom for sever hours before removing a sample. If in doubt about the composition, check the n-pentane and isopentane values with pure components by the procedure prescribed in Annex A2. 

A vapor sample must be kept at least 10 C above the hydrocarbon dew point temperature to prevent condensation of the sample. The sample line should be heat traced and insulated when appropriate. 

The dew point calculation depends upon the accuracy of the stream composition. Small errors in the composition (especially in the heavier hydrocarbons) will cause large errors in the hydrocarbon dew point. 

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