Hydrocarbon Compression

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Iron Sponge Unit Design Procedures

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The iron-sponge process generally uses a single vessel to contain the hydrated ferric oxide wood shavings. A drawing of an iron-sponge unit showing typical provisions for internal and external design requirements was presented in Figure 7-3.

 Iron Sponge Unit Design Procedures

The inlet gas line should have taps for gas sampling, temperature measurement, pressure measurement, and for an injection nozzle for methanol, water, or inhibitors. The gas is carried into the top section of the vessel in a distributor and discharged upward. This causes the gas to reverse flow downward and provides for more uniform flow through the bed, minimizing the potential for channeling.

Supporting the hydrated ferric oxide chips is a combination of a perforated, heavy metal support plate and a coarse support packing material. This material may consist of scrap pipe thread protectors and 2-3-in. sections of small diameter pipe. This provides support for the bed, while offering some protection against detrimental pressure surges.

Gas exits the vessel at the bottom through the vessel sidewall. This arrangement minimizes entrainment of fines. Additionally, a cone strainer should be included in the exit line. This line should also have a pressure tap and sample test tap.

The vessel is generally constructed of carbon steel that has been heat treated. Control of metal hardness is required because of the potential of sulfide-stress cracking. The iron-sponge vessel is either internally coated or clad with stainless steel.

The superficial gas velocity (that is, gas flow rate divided by vessel cross-sectional area) through the iron-sponge bed is normally limited to a maximum of 10 ft/min at actual flow conditions to promote proper contact with the bed and to guard against excessive pressure drop. Thus, the vessel minimum diameter is given by:

 Iron Sponge Unit Design Procedures

A maximum rate of deposition of 15 grains of H2S/min/ft2 of bed cross-sectional area is also recommended to allow for the dissipation of the heat of reaction. This requirement also establishes a minimum required diameter, which is given by:

 Iron Sponge Unit Design Procedures

The larger of the diameters calculated by Equation 7-18 or 7-19 will set the minimum vessel diameter. Any choice of diameter equal to or larger than this diameter will be an acceptable choice.

At very low superficial gas velocities (less than 2 ft/min) channeling of the gas through the bed may occur. Thus, it is preferred to limit the vessel diameter to:

 Iron Sponge Unit Design Procedures

where dmax = maximum recommended vessel diameter, in.

A contact time of 60 seconds is considered a minimum in choosing a bed volume. A larger volume may be considered, as it will extend the bed life and thus extend the cycle time between bed change outs. Assuming a minimum contact time of 60 seconds, any combination of vessel diameter and bed height that satisfies the following is acceptable:

 Iron Sponge Unit Design Procedures

In selecting acceptable combination, the bed height should be at least 10 ft for H2S removal and 20 ft for mercaptan removal. This height will produce sufficient pressure drop to assure proper flow distribution over the entire cross-section. Thus, the correct vessel size will be one that has a bed height of at least 10 ft (20 ft if mercaptans must be removed) and a vessel diameter between dmin and dmax.

Iron sponge is normally sold in the U.S. by the bushel. The volume in bushels can be determined from the following equation once the bed dimensions of diameter and height are known:

 Iron Sponge Unit Design Procedures

where Bu = volume, bushels
The amount of iron oxide that is impregnated on the wood chips is normally specified in units of pounds of iron oxide (Fe2O3) per bushel. Common grades are 9, 15 or 20 Ib Fe2O3/bushel.

Bed life for the iron sponge between change outs is determined from:

 Iron Sponge Unit Design Procedures

The iron-sponge material is normally specified to have a size distribution with 0% retained on 16 mesh, 80% between 30 and 60 mesh, and 100% retained on 325 mesh. It is purchased with a moisture content of 20% by weight and buffering to meet a flood pH of 10. Because it is necessary to maintain a moist alkaline condition, provisions should be included in the design to add water and caustic.

Written by Jack

September 19th, 2009 at 9:36 am

Acid Gas Treating Process Selection

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Each of the previous treating processes has advantages relative to the others for certain applications; therefore, in selection of the appropriate process, the following facts should be considered:
1. The type of acid contaminants present in the gas stream.
2. The concentrations of each contaminant and degree of removal desired.
3. The volume of gas to be treated and temperature and pressure at which the gas is available.
4. The feasibility of recovering sulfur.
5. The desirability of selectively removing one or more of the contaminants without removing the others.
6. The presence and amount of heavy hydrocarbons and aromatics in the gas.

Figures 7-11 to 7-14 can be used as screening tools to make an initial selection of potential process choices. These graphs are not meant to supplant engineering judgment. New processes are continuously being developed. Modifications to existing proprietary products will change their range of applicability and relative cost. The graphs do enable a first choice of several potential candidates that could be investigated to determine which is the most economical for a given set of conditions.

To select a process, determine flow rate, temperature, pressure, concentration of the acid gases in the inlet gas, and allowed concentration of acid gases in the outlet stream. With this information, calculate the partial pressure of the acid gas components.

 Acid Gas Treating Process Selection

Next, determine if one of the four following situations is required and use the appropriate guide:
Removal of H2S with no CO2 present (Figure 7-11)
Removal of H2S and CO2 (Figure 7-12)
Removal of CO2 with no H2S present (Figure 7-13)
Selective removal of H2S with CO2 present (Figure 7-14)

 Acid Gas Treating Process Selection

 Acid Gas Treating Process Selection

 Acid Gas Treating Process Selection

 Acid Gas Treating Process Selection

Written by Jack

September 19th, 2009 at 8:43 am

Posted in Acid Gas Treating

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