System To Remove Hydrogen Sulfide Biology Essay
Kuwait is located at the Northern tip of the Persian Gulf in the Middle East as shown below in Figure-1, and well known as an oil producing country. Due to its location, Kuwait has an extremely harsh and dry environment, with relatively high temperatures all year round.
Crude oil wells are scattered Throughout Kuwait's desert. The oil produced by the wells is gathered in Gathering Centers (GCs) to separate crude oil from naturally accompanied natural gas and water. Once the separation process is final in the GCs, the crude oil and natural gas are transferred through separate transit lines TLs to shore located petroleum refineries.
The transferred crude oil and natural gas are considered "sour" at this point, meaning they contain high levels of sulfur and hydrogen sulfides (H2S). Once the sulfides are removed from the crude oil and natural gas, the crude oil and natural gas is said to be "sweet". H2S is highly corrosive and toxic, where it causes corrosion to TL's pipes, valves, and fittings, which leads to unfavorable leaks all along the TLs, which are a serious threat to employees and the public. Figure-2 shown in Appendix A (Google Maps), shows that currently the TLs pass though residential areas, to transfer the oil products from of oil field and GC locations to reach the shore located refineries.
The scope of this study is to recommend a system design that removes hydrogen sulfide from gas streams, in a location closer to the oil fields and GCs in Kuwait desert, to avoid transferring it through residential areas, and to minimize corrosivity to TLs and equipment.
H2S – Health problems
How people are exposed
Hydrogen Sulfide H2S is a naturally occurring gas mixed with natural gas, released upon exposure to atmospheric conditions. It is a colorless, highly flammable and toxic gas that may be liquefied under pressure and is detectable in low concentrations by an odor resembling “rotten eggs”. Prolonged exposure inhibits and destroys the sense of smell, which eliminates a person's ability to detect the smell after certain levels of exposure. This is inherently dangerous, since those at the most risk of prolonged exposure will be unaware of situations where they are continuously exposed to this gas. Relatively short exposure to high concentrations can be fatal. It is toxic by ingestion and inhalation. Hydrogen Sulfide is heavier than air and tends to accumulate in low places such as pits, sumps, trenches and level areas with poor ventilation (KOC).
H2S has the ability to corrode equipment, piping, valves, compressor, pumps and other ferrous and non-ferrous materials as shown in Figure-3, for a pipe corroded by H2S. Exposure of welded material to H2S can cause weld embitterment and subsequent weld cracking leading to potential failure, especially with the high temperatures in Kuwait desert (KOC).
Fig. 3 - H2S pipe corrosion
Sour crude oils contain up to 4% weight Sulfur, and the gas streams produced contain significant quantities of H2S. This highly poisonous, corrosive and odorous compound must normally be removed from the gas prior to further processing. Apart from H2S, Liquefied Petroleum Gas (LPG) propane and butane also contain carbonyl sulfide and mercaptans, and these too may have to be removed, because upon combustion they are converted in SO2/SO3, which has a major environmental impact e.g. acid Rain (Mamrosh).
Specific processes used commonly today
Because of the great variety of combination of contaminants in naturally occurring gasses (H2S, carbonyl sulfides, mercaptans, CO2, etc.), these projects usually pose the most problems to the process designer. Currently, the natural gas contains more than 5% H2S (KOC), Where typical specifications for natural gas for domestic use are 4 parts-per-million-volume (ppmv) H2S and about 100 ppmv for other sulfur components. The CO2 specification may be set by calorific value of product, or by secondary processing, such as cryogenic plants. Complete liquefaction, for example, requires a CO2 specification of about 100 ppmv (GPSA).
The CLAUS process is by far the most widely applied means of sulfur recovery, and is based on partial combustion of H2S to SO2 at 1200-1400˚C and the second step CLAUS reaction of H2S and SO2 to form elemental sulfur in accordance with
Thermodynamic equilibrium limits sulfur recovery to about 95%, favored by lower operating temperatures (OSHA). In order to achieve a reasonable speed of reaction, the Claus reaction takes place in a reactor over a Sodium Oxyde/Alumina catalyst.
The so-called "tail-gas" from a sulfur recovery unit is a mixture of sulfur gases SO2, H2S, etc. remaining after condensing the sulfur. It is usually incinerated to SO2 and vented. More stringent environmental requirements have led to the development of several tail-gas treating processes, which remove the remaining sulfur compounds. The best known tail-gas treating processes are Superclaus (Comprimo) and Scot (Shell). The combined CLAUS and tail-gas treating process normally has a sulfur recovery of about 99 % (Higman). Although most gas treatment processes are accompanied by a sulfur recovery unit, but it is not within the scope of this study.
Air Absorption Scrubbing
The removal of the contaminants discussed above is almost always carried out by absorption in re-generable solvents as shown in Figure-4.
Fig. 4 - Air Absorption Scrubbing
The re-generable solvents can be classified as chemical, physical and mixtures of physical and chemical. The choice of solvent depends on pressure and type of feed gas, amount and combination of contaminants in the feed, and treated gas specification.
Another relevant factor in choice of solvent is the composition of the sulfur-rich stream removed when the solvent is regenerated, in cases in which a process for recovering sulfur from this stream is required (Marmosh).
H2S is acidic in aqueous solution, and early in the development of gas-treating processes a weakly basic water-soluble solvent was sought, which would react reversibly to it (Zare).
High pressure gas treating
A typical high pressure gas treating process shown in Figure-5 is always accompanied with a sulfur recovery unit (GPSA). In the gas treating unit, the H2S is removed by counter-currently contacting the gas with di-ethanolamine (DEA) solution in a column with trays or random packing. The amount of solution and number of trays or packing height is chosen to meet specification on H2S. The DEA solution leaving the absorber is reduced in pressure to allow dissolved entrained hydrocarbons to escape.
Fig. 5 - High Pressure Treatment
These gases are usually sent to the fuel gas system. After picking up heat from the hot regenerated solvent, the DEA solution enters the regenerator, where it is contacted counter-currently with steam. The solvent is raised to its boiling point of about 110˚C and stripped by the steam. The regenerated solvent, after giving up heat to the loaded solvent, is cooled to about 40˚C before re-entering the absorber. Typically, the solvent inventory is circulated 50 times per hour between regenerator and absorber. A single regenerator may serve several gas absorbers and also LPG extractors (GPSA).
The steam in the H2S stream from the regenerator is largely condensed by cooling to 40˚C and the water is returned to the top of the regenerator or sent to the sour water stripper. The H2S gas is then fed to the sulfur recovery unit to remove 99.9% of the sulfur.
Combined Chemical & Physical Absorption
Chemical absorption processes consume appreciable amounts of steam, and in an effort to reduce costs, there is a move towards higher concentrations of alkanolamines such as DEA and higher H2S loadings. This tends to go with higher degradation and corrosion rates in the process equipment, so a compromise must be found.
The solubility of H2S is much higher than that of methane, carbon monoxide and hydrogen in many liquids, methanol for example (OSHA). Since the heat of solution is much lower than the heat of reaction in chemical solvents, desorption can be achieved by pressure reduction, possibly combined with moderate heating or inert gas stripping.
Such solvents are only feasible, however, when sufficiently high loadings of contaminants in the solvent can be achieved, avoiding excess solvent requirements. Such high loadings are possible when the partial pressure of the contaminant is very high, typically above 10 bar, or when refrigeration is used to cool the solvent to increase solubility (GPSA).
The application of other physical solvents for natural gas treating is limited to feeds with low concentrations of propane and heavier hydrocarbons, since the solubility of these components is too high.
The Sulfinol solvent, developed in the early sixties, combines many of the attractive properties of physical and chemical solvents. It is a mixture of Sulfolane, an alkanolamine and water. It has been found to have wide application in treating natural gases. Its main features are deep removal of H2S, carbonyl sulfide, mercaptans and when required CO2. Operating costs are in general significantly lower than for a purely chemical processes.
It is found more practical to have the scrubbers installed near or within the GCs, since it is the location where the natural gas is first encountered after leaving the wells and after being separated from the crude oil. Also, to avoid transferring the sour natural gas in TLs and through residential areas. Therefore, it is considered to install multiple scrubbing loops as a process unit within the GC's vicinity.
The waste water from the H2S scrubbers will be transferred to the GC's waste water facility, where the H2S waste should be transferred to a sulfur recovery unit such as the CLAUS process.
Alternative 1: Scrubbing using excess NaOH.
For very small capacity or infrequent usage, caustic (NaOH) scrubbers may be designed to operate using a large excess amount of caustic. This design strategy assures the maximum H2S abatement at the cost of excess NaOH usage. This unit would be designed as simply as possible; it would typically consist of a single packed tower with a surge tank, a circulation pump and a heat exchanger as shown in Figure-6.
Fig. 6 – Single loop H2S scrubbing system
A large liquid recirculation flowrate is maintained to provide adequate contact with the gas phase. Makeup caustic is added, and spent caustic is withdrawn continuously or as needed. Excess NaOH amounts should be used e.g., NaOH:H2S > 2:1.
When large excesses of NaOH are used, the equilibrium partial pressure of the H2S solution is so low that it is typically negligible. Column design for this situation is straightforward. Well known strategies for evaluating the height of a transfer unit (HTU) of the column packing can be used, such as from a packing vendor and HTU literature. For single recirculation-Ioop systems, the excess caustic utilization will be the primary factor in determining the H2S removal efficiency. Because of the high caustic consumption and low value of the sulfidic caustic (NaSH) product, this scrubber is limited to very low sulfur throughputs.
Alternative 2: Scrubbing while minimizing excess NaOH.
When a large excess of NaOH can-not be used e.g., NaOH:H2S < 2:1 for economic or product quality reasons, the chemical equilibrium of the system must be considered in the design calculations, especially when operating at higher temperatures. At a lower pH, the literature HTU data may not be accurate. It must be recognized that the equilibrium partial pressure of H2S above the liquid phase represents the minimum H2S partial pressure that can be achieved in the treated gas. One design strategy for these cases is applying two caustic recirculation loops as shown in Figure-7.
Fig. 7 – Double loop H2S scrubbing system
Fresh caustic is fed to a top loop, which is used as a polishing section to maximize H2S removal. The caustic overflows from the top to the bottom section. The bulk of the H2S removal is done in the bottom recirculation loop, which operates at a lower pH. Double-loop systems are sometimes avoided due to greater complexity and cost, but this design can achieve very low outlet H2S concentrations with less caustic consumption than would be possible using a single-loop system.
Alternatives Analysis & Selection
A comparison between the two alternatives is done based on criteria shown in sections 4.1 – 4.4. Each criteria will have a weight factor assigned to it, where this factor will be multiplied by a scale. The scale will range between 0 and 10, where 0 will represent "very poor", and "excellent" for 10. A score representing the sum of all criteria for each alternative, where the alternative with the highest score will be selected.
The main reason for performing this feasibility study is to reduce the health, assets, and environmental risks associated with the H2S contaminant accompanying the natural gas which passes through residential areas through the TLs. Therefore, a weight factor of 35% (0.35) is assigned for the environmental effectiveness criteria.
Alternative 1 has a higher efficiency in removing H2S from the natural gas than that of Alternative 2, but Alternative 2 has less caustic waste that has to be dealt with further on, with a considerably high H2S removal capability. Therefore, Alternative 1 was assigned a score 8, and 7 for Alternative 2.
Cost is given a weight factor of 20% (0.2), because this is a feasibility study although cost is very important. Since this is only a feasibility study, no detailed cost break down for the alternatives was done. But a cost estimate can be determined by comparing the two alternatives based on how much construction material and time will be invested in each, and how much caustic will be utilized.
Based on Figure-7 (Alternative 2) shown above and by comparing it to Figure-6 (Alternative 1) also shown above, it is obvious that Alternative 2 will require more construction material, thus more construction time. Also, Alternative 1 consumes more caustic. Keeping in mind that caustic costs will be required continually once the H2S scrubbers are operational. Therefore, Alternative 1 was assigned a score of 7, and 5 for Alternative 2.
Operation is an important criteria, due to the fact that a GC operates around the hour, and the natural gas flow is continuous. Operators must know that they can depend on a system to work continuously, without interruptions. Based on that, a weight of 30% (0.3) was assigned for the operation criteria.
Alternative 1 lacks the capability of working continuously, and can only operate on minimal flow of natural gas. Whereas Alternative 2 is capable of working efficiently on continuous bases. This is a reason for assigning a score of 3 for Alternative 1 and an 9 for Alternative 2.
Maintenance easiness was assigned a weight factor of 15% (0.15), because it affects the operation of the system. The more complex a system is, the longer and more difficult it will be to maintain it, which will lead to disruption of the system operation.
Alternative 2 is obviously more complex than Alternative 1, which is a reason that Alternative 1 was assigned a score of 7 and Alternative 2 was assigned a score of 5.
Table 1 below shows the decision matrix built to establish an alternative selection. Alternative 2 has a higher score than Alternative1, which lead to selecting Alternative 2.
Table 1 Design Decision Matrix
It is found that Alternative 2 is capable of removing hydrogen sulfide from gas streams for a petroleum facility in an open rural area of Kuwait desert. Even though Alternative 2 with the double loop configuration has a higher cost and most complex for construction, but it is found more acceptable by the design assigned criteria. The amount of caustic used had considerable effect on both environmental and cost effectiveness. It is also more reliable in regards to its operation, where it can operate continuously. By implementing the double loop H2S scrubbing system, the H2S contaminant concentration will be minimized to the acceptable ranges that will not have harm to the residential area population where the TLs pass through. It will also protect the GCs equipment and TLs from corrosion caused by H2S.
A recommendation is made for installing not less than 2 units of Alternative 2 with a preference of having 3 units, to insure H2S removal efficiency and to have a system redundancy. It is also recommended to initially install a pilot system within a single GC, to assess the capability of the installed system prior to installing it in al GCs.
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