OxygenStripperDesign

1. Purpose

This procedure provides guidelines for the design of reboiled oxygen strippers.

2. General

The presence of oxygen in a feed stream is normally the result of the feed stream being transported via tanker or stored in a poorly blanketed or non blanketed storage tank. These streams will not only contain dissolved oxygen but also peroxides that form from the reaction of oxygen and hydrocarbon. Peroxides react with olefins to form a polymer or gum. The rate of reaction is a strong function of temperature. In an oxygen stripper the peroxides are heated enough to have them break down and yield O2. This oxygen is then swept up the column and hence minimizes the formation of additional gums. Note that any gums that were already produced will still be present and will tend to foul down stream equipment.

The best way to avoid problems is to keep the oxygen out of the feed. If the oxygen presence is due to transport, there is not much that can be done. However if the oxygen presence to due to poor blanketing or no blanketing, then it is clearly better to correct this situation rather than deal with the fouling that will occur to exchangers that heat up streams that have been exposed to oxygen.

Gas stripping, with streams such as separator gas, is generally not recommended. Gas stripping is expected to yield poor stripping of molecular oxygen and no stripping of peroxides.

3. General Design Considerations

3.1 Operating Pressure and Temperature

Elevate the operating pressure as needed to obtain a reboiler outlet temperature of at least 350F. This helps any combined oxygen compounds to break down via thermal degradation. As a result, most naphtha oxygen strippers operate at a pressure above atmospheric. Most kerosene oxygen strippers float on the relief gas header.

3.2 Reflux and Trays

Very little reflux and very few trays are needed in an oxygen stripper. If oxygen stripping is the only function of the column, set the external reflux to feed ratio to 0.15 with 15 actual trays. As with any column that has water in the feed, check the design to make sure that a water phase does not form on the top tray or trays. If this is a problem a reflux to feed ratio of more than 0.15 may be required.

Some columns may be designed to produce a net hydrocarbon receiver liquid. In this case tray to tray calculations are needed to determine the appropriate amount of reflux and trays. Note that the net overhead liquid stream contains oxygen and purge gas components.

3.3 Feed Composition

In addition to the hydrocarbon composition that is provided by the customer, the feed should be considered to be saturated with water and to contain 300 mol ppm of oxygen. (For naphtha this is equivalent to about 100 wt ppm) If the customer provides a value for the oxygen concentration it may be used instead of the above value.

While combined oxygen, such as peroxides, may be present, do not show these in the feed. High vapor pressure feeds are self blanketing and will limit the oxygen concentration. If desired, the blanketing effect can be included by use of the following chart. The HC vapor pressure should be based on a cold expected transport temperature. A 60 F temperature should normally be assumed.

This chart assumes:

1. The O2 K*(pressure) value is constant with pressure and equal to 8500 psi.

2. The stream is assumed to blanket itself with its own vapor pressure.

3. The remaining vapor is assumed to contain 21% O2.

Inflection Point Engineering test method 678 can be used to analyze for dissolved O2. Inflection Point Engineering test method 649 can be used to analyze for all oxygen content, including dissolve, organic, water, CO and CO2. Peroxides can be measured with test method D2340.

3.4 Receiver Purge Gas

Sufficient gas needs to be purged from the receiver in order to keep the oxygen concentration to less than half of the minimum oxygen concentration to support combustion (MOC). The MOC for most hydrocarbons is about 10 mol %. The MOC for hydrogen is about 2 mol %. Calculate and use a mol average MOC for the receiver gas. The low MOC for hydrogen will generally make hydrogen containing streams look unattractive for use as a receiver purge gas.

Normally connect the purge gas into the condenser rundown line to the receiver. An alternate location is close to one end of the receiver. Connect the net gas from the receiver to the other end of the receiver. The most frequently used purge gas is nitrogen, however hot vapor from the column overhead could also be used as well as a hydrogen or fuel gas stream. Note that the components in the purge gas will be present in the receiver liquid. This may be an important consideration if a net receiver liquid is to be produced.

3.5 Feed Preheat

If the feed goes into the receiver, normally some heating of the receiver liquid to the top tray is required. This is normally done via heat exchange with the column bottoms. Due to fouling concerns the feed temperature for naphtha streams is normally limited to 200F. If energy concerns dictate that a higher feed temperature should be used, then check the following points. First, the molar V/L in the bottom of the column should be at least 0.35. Second, specify a spare feed preheater so to allow cleaning of the exchanger without stopping the operation.

In the case of a kerosene feed, the oxygen stripping is normally done by the stripper in a strip and rerun operation. The feed to the stripper goes to the column rather than to the receiver. Energy concerns almost always result in the feed being heated to between 350 to 400F. Use of a spare preheater is recommended.

3.6 Vent Gas Destination

The vent gas destination is usually the relief gas header. The composition of this gas presents several problems to the refinery. This gas is expected to be saturated with water and may contain up to 5 mol% oxygen. In addition there is normally a significant concentration of nitrogen. If the oxygen comes in contact with H2S, they may react to form H2O and elemental sulfur.

4. Recommended Flow Schemes

The four recommended oxygen stripper flow schemes are shown in Figures 1 through 4. Figures 1 through 3 show a pressurized column with a control valve in the net gas line from the receiver. Figure 4 shows a non pressurized column with the receiver floating on the relief gas header. For the pressurized columns shown in Figures 1 through 3 the net gas flow rate is metered and is controlled either directly or indirectly. Indirect control is done by changing the purge gas rate.

4.1 Feed to Receiver Non Condensable Purge Gas Used Pressurized Column

In Figure 1, cold feed comes from storage with the only desired overhead product being a vapor. This flow scheme has the advantage that the receiver will help avoid feeding any slugs of water to the column. The feed going to the receiver results in the receiver operating at a temperature close to that of the feed. This relatively cold temperature helps to minimize the loss of hydrocarbon out the net vapor line. Normally some type of heating is done to the receiver liquid prior to it going onto tray one.

4.2 Feed to Column Non Condensable Purge Gas Used Pressurized Column

In Figure 2, feed goes to the column rather than to the receiver. This is normally so that a net overhead receiver liquid can be produced that is relatively clean of bottoms material. Normally a net overhead liquid is removed from the receiver to allow for some composition control. Depending on the size of this flow, its rate may be either manually set or its rate may be set by a composition controller.

4.3 Feed to Column No Non Condensable Purge Gas Used Pressurized Column

In Figure 3, the flow scheme is the same as Figure 2 with the exception that the pressure control is done via a butterfly valve prior to the condenser and a vapor by-pass line around the butterfly valve and condenser. One of the advantages of this flow scheme is that there is no need for an external purge gas such as nitrogen.

4.4 Feed to Column Non Condensable Purge Gas Used Non Pressurized Column

In Figure 4, the flow scheme is again very similar to Figure 2. However, in this case the column pressure is allowed to float on the relief gas header. A non condensable purge gas stream is put into the condenser rundown line in order to insure that the oxygen concentration is at a safe level. This flow scheme is normally used on streams that are kerosene or heavier.

Drafting File: purgegas.dgn