The History of Natural Gas

The history of natural gas extends to antiquity. In America it was known to the indians, who observed it issuing from the ground in various spots, chiefly along the western side of the Appalacian Highlands. It was used for illuminating purposes in Fredonia, N.Y., as early as 1821 and the effect was so striking compared to gas made from coal that a German scientist hailed the beautuful, clear gas lights as the eighth wonder of the world. Gas associated with Pennsylvania oil was used for industrial purposes first in Pittsburgh, and its general use then spread to other industrial centers.

TEG Dehydration Design Basis and Design Guidelines

Contactor Operating Pres
Contactor Operating Temp
Gas Rate MMSCFD
Gas Moisture Content Spec 0.05 lb w/MMSCF
-50°F hydrate at 2500 psia
Contactor Structured Packing
Contactor Struct Packing Wetting Rate 0.3 to 0.7 gpm/ft 2
Stripping Column Struct Packing
Reboiler Heat Flux Rate 6-8,000 BTU/Hr-Ft 2
Contactor Diameter Based on Fs=2.5
,whereFs= Vr½Contactor Packed Section 21.25 feet
Contactor Demister 16 inch Thk York Reid (Otto York )
Stripping Column Diameter 6”
Stripping Column Packed Section 8 Feet
Stripping Gas Rate 8 SCF/Gal
TEG Circulation Rate 3gal/lbw
Reboiler Operating Temperature 400°F
Reboiler Operating Pressure 1 psig
Reboiler Design Pressure >100 psig
Reboiler Design Temperature 450°F

TEG Dehydration

Gas Dehydration Pretreatment
This should include adequate vapor/liquid separation and solids filtration. I feel stronger about the adequate vapor/liquid separation than the solids filtration. If you have some liquid formation, that should help in the washing out of solids. If your operation has very little condensation upstream, then the need for solids filtration is stronger. The need for good upstream vapor liquid separation cannot be over emphasized. If you have liquid hydrocarbon entrainment into your system, the entire operation will be negatively impacted. If you have a trayed column, it will foam, with the accompanying heavy entrainment losses and lower column efficiency. The liquid hydrocarbon will carry through to the flash drum, also causing potential foaming problems there, and possible overloading the flash drum overhead system. With flashing hydrocarbons, the amount of gas coming off in the flash drum will be many times the normal operating rate. If you have a good flash drum it may be able to remove the liquid hydrocarbon here, if not it is off to the reboiler, to be vaporized there and possible overload the gas system there. Not all the hydrocarbon will be vaporized. The heavy ends will form a tar like substance to foul your surge drum, lean/rich exchanger and filters. It is far easier to do a good job upstream on the original vapor liquid separation, than to deal with the far more difficult job of liquid-liquid separation.
The upstream vapor liquid separator should be sized to handle more gas than the glycol contactor can handle. Eventually operations will push the system to a gas rate it cannot handle. May as well let the thing which fails be less annoying. If the upstream separator fails first the operation will require much attention, and have heavy TEG losses.
The upstream separator should be sized to handle 20% more gas the rest of the TEG system. Also the separator should be simple in nature, and less likely to fail. A vertical separator, with a horizontal mesh pad fits this criteria. Putting in an extra thick pad will help reduce the entrainment load. A 12 inch, multidensity wire mesh pad should do good. With a dp cell across the mesh pad to warn of its flooding.
The TEG Contactor can be either structure packing or bubble cap trays. I don’t think having an integral vapor-liquid separator below the contactor is the most reliable system. A failure of the seals between the glycol contactor and the vapor-liquid separator can result in losses of TEG, which would be hard to trouble shoot. Also now with the use of structured packing the capacity of the vapor liquid separator will not be as high as the TEG Contactor. Remember the liquid density in the vapor liquid separator will be lower than the TEG, resulting in a lower allowable velocity.
The only enhancement I would make is a thicker pad and make it composite (6 inches of type 421 and 6 inches of type 326).
A gas filter downstream of the knockout drum may be nice, but I am not sure it is that necessary. If you do install one, do not count on it to also remove liquids. They typically are designed for a very high rV²(150) and do not reliable remove liquid.
A good vapor/liquid separator is absolutely essential for the TEG unit to operate well and trouble free. The allowable velocity calculated for the mesh pad should be based on the vapor density and the liquid hydrocarbon density (not the water density or the average density of the liquid hydrocarbon and liquid water)
The maximum inlet temperature to the TEG system should be considered carefully. Just going from 90°F to 100°F can increase the water load on the reboiler system by 35%. Also the obtainable dewpoint will be effected directly (10°F higher)
TEG Contactor
Structured Packing Contactor
Contactor Diameter
If structured packing is used here it should be designed for a maximum Fs of 2.8.

Internals for the contactor should include:
York Reid Demister
This is a Dacron/316SS composite mesh pad designed specifically for TEG Dehydration service. I recommend a 16 inch thick pad, with 1 inch top and bottom grids. The contactor should have top and bottom rings to hold the mesh pad in place. Omission of the top ring sometimes results in loss of the mesh pad and increased TEG losses. The mesh should also be wired into place on the bottom ring. The top of the mesh pad needs to be far enough away from the gas outlet nozzle to prevent channeling. The distance is equivalent to drawing a 45° line from the outer edge of the mesh pad to the outlet nozzle. This results in a vertical distance = (mesh pad diameter - outlet Gas diameter)/2 The bottom of the mesh pad should be at least 3 feet above the top of the TNT 727 distributor (not counting the parting box).
Inlet TEG Distributor pipe
This is merely an internal extension of the lean TEG line to the contactor. It is routed to the parting box above the TEG Distributor
Glitsch TNT 727 Narrow Trough Distributor (316SS), with parting box
This will provide the ‘proper’ distribution of the TEG to the structured packing. It is constructed with small orifices for distribution. If the orifices plug, the TEG will rise and flow into the same drip tube via a V notch. The drip tube can be extended to be close to the packing surface. The final connection to the packing should be wire gauze which is tack welded to the drip tubes of the TNT 727 distributor. Glitsch can provide their distributor already configured in this manner. It is important that the liquid glycol does not free fall to the packing surface. If it is allowed to free fall, entrainment into the gas phase can take place, with a corresponding increase in glycol losses. Drip points/ft 2 should equal 4.
Glitsch HDG 421 Packing Holddown
Glitsch HPD 202 B High Performance Distributor
This is structured packing which is in 1/2 the normal thickness of 9.75 inches. Two layers of 4.875 inch thickness are used to speed up the distribution of the glycol. To prevent flooding and entrainment from the top of the packing, Glitsch normally uses one size larger of structured packing. In this case 1/2 inch crimp instead of the 1/3 inch crimp of the packed bed. I also recommend using a 60° crimp angle to further decrease the gas velocity at the top of the bed. This reduces the velocity by over 20%, which should in turn reduce the tendency to entrain.
The Packed Section
21.25 feet of Gempak 3A structured packing. The original PBU contactors had their bubble cap trays replaced with about 17 feet of packing.
Glitsch HPS 121 packing support
Inlet gas distributor
I’m not terribly knowledgeable on inlet gas distributor requirements. I have seen contactors with no distributor, half pipes, spreader pipe style distributors and chimney trays. I think if your inlet velocity is reasonable (in the area of 50 feet/sec) you should be able to use a half pipe, located about two feet from the bottom of the packing. Glitsch may have some comments in this area.
Contactor Surge Volume
This volume should be about 20 minutes. This will take care of normal upsets, etc and also allow for some volume for the holdup of TEG in the contactor. I recall the liquid holdup being about 5% at the high design gas rates. By putting the surge volume control on the contactor you maintain a even flow of TEG to the Reboiler and minimize upsets. Anytime you vary the flow to the reboiler, you stand the chance of changing the reboiler temperature. It is important to maintain the 400°F reboiler temperature. Even small upsets to this can throw off the lean teg. The original system of using a surge drum under the reboiler, and allowing its level to float up and down, leaves the TEG pump subject to running dry and cavitating. Having a large reciprocating pump cavitating can be quite exciting.
Bubble Cap Tray Contactor
If bubble cap trays are used, you just need to set the number of trays, and install a mesh pad. Again I recommend a York Reid Demister. I am aware of 12 foot diameter bubble tray tower operating at a C of 0.27 and a Demister K value of 0.3. The unit is operating well, except it is starting to carry over some glycol, which is causing trouble downstream in the Brazed Aluminum Heat Exchanger. The TEG freezes in the downstream heat exchanger, causing the pressure drop to increase. The frozen teg is removed by a high dosage of methanol. (15 gpm for 5 minutes). Please note the above quoted C is based on the tray area (with the downcomer area subtracted from the tower area). This is equivalent to about a C of 0.23 using the entire column area. The efficiency of the column is expected to fall off as the entrainment goes up. Since the total flow of glycol is very low for a contactor, even low entrainment rates between trays can dramatically hurt your efficiency. A 10 foot diameter column with 10 gpm internal entrainment has substantially decreased its efficiency since the total liquid rate to the column may only be 30 to 60 gpm. The entrainment of the rich teg from the tray below to the tray above, essentially makes the upper trays have richer teg, reducing their ability to dehydrate.
TEG Regeneration System
Rich TEG/Still column Reflux exchanger
This unit allows for some reflux (water) in the still column to reduce the TEG losses from the regeneration system. Typically you need to allow for about 20 degrees of temperature change in the rich teg to provide enough reflux in the still column to reduce the losses. I often see a temperature spec on the still column overhead. A temperature spec does not make a lot of sense if you are using stripping gas. Once you begin condensing water, the temperature of the overhead will remain relatively constant even with large changes in reflux duty. It is essentially a two component system: highly volatile gas and water. Once the gas rate is set, the overhead pressure of the still column, and the amount of water removed by the TEG system, then the mole fraction of water in the Still Column overhead gas is set. This essentially sets the overhead temperature, since the gas will be in equilibrium with liquid water on the top section of the Still Column. Once the reflux is high enough to reduce the TEG losses, you are only increasing the Reboiler Duty when you reflux more.
Rich/Lean Heat Exchanger
This heat exchanger adds more heat to the rich TEG to bring up the flash drum temperature to 150°F. Running the flash drum temperature up, reduces any foaming tendency. This exchanger also recovers heat from the lean TEG.
Flash Drum
The purpose of this drum is to degas the TEG and allow for decanting of any liquid hydrocarbon. As mentioned earlier, decanting the liquid hydrocarbon is often difficult. If you do a poor job of it, you lose TEG as well. Best option is to not let any liquid hydrocarbons into your system. This unit runs best at a relatively warm temperature. Low pressure also reduces foaming.
Another Lean/Rich heat Exchanger
This final lean/rich heat exchanger is for heat recovery. You should expect to be able to get the rich TEG up to 275 to 300°F. The remainder of the heat will have to be added by the reboiler.
Reboiler
Reboiler should be operated at 400°F and low pressure (as close to atmospheric as feasible). I am familiar with units that have operated at these temperatures for over 20 years with no degradation problems. Running at a lower temperature will make it more difficult to get the required TEG purity. The temperature controller should be a PID type controller (proportional, integrating, derivative). On-off control of the TEG Reboiler temperature is totally unacceptable at the required TEG purity of this system. Fire tube flux rate can be designed for 8,000 Btu/hr-ft 2 . Again I am familiar with units that have operated for years at 10,000 Btu/hr-ft 2 with no significant problems . As I said the pressure of the reboiler should be low. This makes it easier to make high purity TEG. Higher operating pressures can be offset with longer packed sections in the stripping column and more stripping gas. I would not be concerned with running up to 10 or 12 psig. We had a unit which was designed to run at 1.5 psig, but a badly designed overhead condenser had a 10 psig pressure drop, resulting in a high reboiler pressure. The unit still made its 99.98wt% TEG spec as a result of a 8 foot long structured packing section and design stripping gas rate of 8 scf/gal
Stripping Column
The stripping column ( the stand pipe that the glycol flows down from the Reboiler to the Surge Drum). I recommend using structured packing for the stripping column. The column will be highly liquid loaded (20 to 40 gpm/ft 2) The column should be designed with the upset liquid rates in mind. To avoid too large of an upset rate, do not over size the level control valve from the TEG Flash Drum.
Structured packing is about twice as efficient as pall rings (see attached graph) and doesn’t have the problem of packing leaving the column as pall rings sometimes do. I also recommend using 8 feet of packing. This allows for much easier attainment of the required lean TEG Concentration of 99.99 wt%. I have attached a graph depicting the TEG Reboiler/Stripping column performance for various numbers of theoretical trays. I have plotted the performance in terms of wt % H2O, instead of the usual wt % TEG, as it results in straighter lines, and are easier to read in the high TEG Concentrations. While it can be argued that you don’t need 99.99 wt % , it really doesn’t cost much to get the extra lean concentration once you are committed to putting in stripping column. The graph I have attached is based on a 2 psig reboiler pressure. This will likely require a blower. If your LP Compressor (say 5 psig), we should be able to operate at the higher pressure of 6 or 7 psig and compensate with more stripping column. The current spec’d 8 foot height might even do the job. The bottom of the stripping column should not extend far into the surge drum as is commonly the case. The column should end near the top of the surge drum. This will allow the stripping gas to flow from the surge drum to the bottom of the stripping column.
Stripping Gas
This gas should be routed to the bottom of the stripping column via the surge drum. Do not route this gas pipe through the reboiler. Since the stripping column will be using structured packing the gas pipe can not be routed down the column as is commonly done. Also the gas can be preheated by routing it along the bottom of the surge drum in the liquid phase. A rotameter should be provided for metering of the stripping gas prior to entering the surge drum. A manual throttle valve down stream of the rotameter will be adequate for control.
Surge Drum
Flow to the Surge drum should be in one end and out the opposite end of the vessel to ensure good mixing and discourage static areas. This vessel should be used to protect the pumps. The majority of the system surge should be taken at the contactor, as explained earlier.
Rich/Lean TEG Exchanger
Traditionally these units were shell and tube. More common is now to see plate and frame heat exchangers. The plate and frame heat exchangers are much more compact.
Still Column
The purpose of the still column is to reduce the TEG losses. It achieves this by having 2 trays (bubble cap) above the rich TEG feed point. The liquid for the trays typically comes from an internal still column condenser (a coiled tubing exchanger). This provides a small flow of liquid water for reflux. This is generally enough since the boiling points between water and TEG is so large (546°F versus 212°F).
Still Column Reflux Condenser
This is an area that has resulted in annoying TEG losses. The typical reflux condenser is a coiled tube. The tube can crack/fail and then rich TEG is sprayed into the outlet still column gas stream. If this system is still used, at least make it easy to pull the coil and replace it. Alternative overhead condensers should be considered which are more robust. I once had to trouble shoot a TEG system that was experiencing high losses. I did the usual inspection and found 20 volume % TEG in the Still Column Effluent Drum. I reviewed the stripping gas rate, etc to determine if the unit could be flooding, but it appeared alright. A performance test where I varied the amount of reflux in the overhead resulted in the losses increasing with increasing reflux. This is just the opposite of what one would expect. This operation ran parallel dehydration trains, so I repeated the test on the parallel unit and got the system response I originally expected. Shutdown and inspection of the reflux coil reviewed it to be cracked at the point it hangs from the top of the still column. This units can be difficult to reweld.
Still Column Effluent Condenser
Not all units will have one of these. Frequently this is the end of the line for TEG units. The effluent just vents into the air. This is becoming more and more unexceptable for more units with concerns and regulations regarging BTEX ( Benzene, Tolulene, ethlybenzend and xylene). Typically units with gas rates 25 MMSCFD may come under the regulations. This condenser cools the effluent gas down from around 200° to 100°F.
Still Column Effluent KO Drum
Same comments as above. This allows for the knock out of liquids, prior to routing the gas to a blower or compression system.
Effluent Blower
This unit recovers the stripping gas and any absorbed hydrocarbons and routes them else where in the plant for reuse. Some care is needed in specifying this unit. TEG absorbs a lot of heavy hydrocarbons and CO 2 . If the stripping gas is turned off or reduced, the mw of the gas going to the effluent blower can change dramatically. I was starting up a unit once, and to tune the recycle system I reduced the system flow by turning the stripping gas way down. The recycle system responded by opening the recycle valve. Shortly after that the blower motor tripped on high amps. This particular blower did not have a pressure gauge downstream of it, so I did not notice what must have been a substantial increase in mw as a result of the reduction in stripping gas. I expect the mw went from 22 to around 36 or so. To make matters worse the breaker broke and we were out of commission for a day. I did not realize why the amps went up on reduced gas flow until considerable later.
TEG Additions
This can be a problematic area for TEG Systems. The TEG should be added upstream of the Regenerator as the storage TEG is no where close to 99.99 wt%. I recently contacted a lab regarding the concentration as they receive it. It was 99.7 wt %. The TEG also must be added slowly to the system, otherwise the Reboiler will suffer a significant drop in temperature, with a corresponding drop in lean TEG concentration. I recommend a normal addition rate of no more than 10% of the circulation rate. I have been running performance tests on TEG Systems, and noted 30 to 40°F drops in the reboiler temperature, and find out the operator is adding teg at a rate similar to the normal circulation rate, greatly overloading the TEG Reboiler, and leaving the system upset for some time. Since I don’t expect your TEG loss rate to exceed 0.1 gal/mmscf, if you add TEG weekly, it will take about one hour to make up the losses. A transfer pump may have to be included for high rates (or use the spare TEG Circulation pump).

Lab Tests

Typical lab tests for the TEG Units are:
Water contents of Rich and Lean TEG - (Karl Fischer) dependent on your dewpoint spec
PH of rich and lean TEG 6.8 to 7 on the lean
particulates <1mg/liter
Still column Effluent (Refractive Index) <1 volume % TEG
Water content of Gas - Either Bureau of Mines Dewpoint Testor or Lockwood and McLorie Analyzer
On Line Analyzers
The only on line analyzer I ever see on a TEG system is a moisture analyzer and they usually don’t work well. The probes are easily fouled with TEG. Also they can be quite sensitive to pressure variations. I once was installing a new probe and thought it would be a good idea to pop and purge the sample loop to speed up the drying out of the sample system. Unfortunately the pop and purge cycle causing the gold foil on the probe to come apart. Another failed probe.
My best experience with moisture analyzers for the gas is the Lockwood and McLorie analyzer. This is quite a complicated device that involves flowing a know quantity of gas through a packed column of glycerol. The glycerol column is taken to the Lab and eluted into a special chromatograph. The chromatograph output is two peaks on graph paper, which is measured either manually with a planimeter or electronically with an integrator. This area of the peak is compared with a standard which is injected into the chromatograph before and after every set of samples is run. The standard is a 7 micro liter sample of ethyl ether that was in equilibrium with liquid water. Knowing the temperature of the ethyl ether and the solubility of water in it, allow you to calibrate the area of the chromatograph peaks to micro grams of water. The end result is a direct measurement of the lb water /MMSCF of gas. A very accurate instrument, which is able to reliable measure down to 0.02 lb water/MMSCF. It does require a reasonable lab to run and is some what labor intensive. If you don’t need this high accuracy a Bureau of Mines dewpoint testor does a very nice job.
The Bureau of Mines Analyzer is the original dewpoint tester. This device routes a sample of your gas past a chilled mirror. By viewing the chilled mirror you can determine the dewpoint of your gas. The temperature of the chilled mirror is varied by running a refrigerant by it. This device is rugged and reasonable accurate, but requires a skilled operator and is not an online device. This device can be purchased from Chandler Engineering, ph 918-250-7200; fax 918-459-0165. Cost runs about 3 to $5,000.
An automatic/online version of the Bureau of Mines testor has been developed by Bovar Western Research. They can be contacted in Calgary, Canada at 403-235-8300.The cooling capacity of this device is 90°F (50°C) below the temperature at the monitor installation. The cost is about $25,000.
Conversion of existing Bubble Cap Tray units to Structured Packing
This can work out very nicely. You may increase your capacity as much as 100%. Of course you will be loading up your regeneration system somewhat. The majority of the heat load in a regen system is in the heating up of the glycol. In one of these conversion jobs, the water load of the rich TEG starts to add up. To compensate for this, you may reduce the TEG circulation rate. The structured packing needs a wetting rate of at least 0.3 gal/ft². Additional problem areas are if you have an integral vapor liquid knock out drum in the bottom of the contactor, it will likely limit your capacity.
Conversion of the unit will require removal of all of the trays, and cutting of the tray support rings (don’t get carried away, you will need the bottom ring to support the packing and the top ring for the packing hold down and liquid distributor).
The very first installation of structured packing on the North Slope did not include the cutting off of the support rings. This was likely because structured packing was untested in glycol dehydration and removing the support rings would prevent the operator from reinstalling the trays. Unfortunately it also guaranteed the unit would fail. Leaving the support rings in place allowed wet gas to bypass the structured packing. When the inlet gas moisture content is 45 lb/MMSCF, and the outlet spec is 0.1 lb/MMSCF you don’t need to bypass much gas to be off spec.
The recommended procedure is to remove the support rings to 3/8” of the wall.
Any downstream TEG Knock drum will likely need to be upgraded to handle the higher gas rates. I recommend the York Reid Demister for this service. Ideally you should handle the mist removal at the top of the contactor. I don’t think you gain anything by exiting the contactor and shearing the teg entrainment particles into smaller particles to be removed downstream! Also proper use of a liquid distributor for the TEG and York Reid Demister should allow (if there is space in the contactor) you to recover the TEG in the Contactor, which is simpler anyways.
a

Stages in the Production of Pipeline-Quality Natural Gas and NGLs

The number of steps and the type of techniques used in the process of creating pipeline-quality natural gas most often depends upon the source and makeup of the wellhead production stream. In some cases, several of the steps shown in Figure 1 may be integrated into one unit or operation, performed in a different order or at alternative locations (lease/plant), or not required at all. Among the several stages (as lettered in igure 1) of gas processing/treatment are:

A) Gas-Oil Separators: In many instances pressure relief at the wellhead will cause a natural separation of gas from oil (using a conventional closed tank, where gravity separates the gas hydrocarbons from the heavier oil). In some cases, however, a multi-stage gas-oil separation process is needed to separate the gas stream from the crude oil. These gas-oil separators are commonly closed cylindrical shells, horizontally mounted with inlets at one end, an outlet at the top for removal of gas, and an outlet at the bottom for removal of oil. Separation is accomplished by alternately heating and cooling (by compression) the flow stream through multiple steps. Some water and condensate, if present, will also be extracted as the process proceeds.

B) Condensate Separator: Condensates are most often removed from the gas stream at the wellhead through the use of mechanical separators. In most instances, the gas flow into the separator comes directly from the wellhead, since the gas-oil separation process is not needed. The gas stream enters the processing plant at high pressure (600 pounds per square inch gauge (psig) or greater) through an inlet slug catcher where free water is removed from the gas, after which it is directed to a condensate separator. Extracted condensate is routed to on-site storage tanks.

C) Dehydration: A dehydration process is needed to eliminate water which may cause the formation of hydrates. Hydrates form when a gas or liquid containing free water experiences specific temperature/pressure conditions. Dehydration is the removal of this water from the produced natural gas and is accomplished by several methods. Among these is the use of ethylene glycol (glycol injection) systems as an absorption* mechanism to remove water and other solids from the gas stream. Alternatively, adsorption* dehydration may be used, utilizing dry-bed dehydrators towers, which contain desiccants such as silica gel and activated alumina, to perform the extraction.

D) Contaminant Removal: Removal of contaminates includes the elimination of hydrogen sulfide, carbon dioxide, water vapor, helium, and oxygen. The most commonly used technique is to first direct the flow though a tower containing an amine solution. Amines absorb sulfur compounds from natural gas and can be reused repeatedly. After desulphurization, the gas flow is directed to the next section, which contains a series of filter tubes. As the velocity of the stream reduces in the unit, primary separation of remaining contaminants occurs due to gravity. Separation of smaller particles occurs as gas flows through the tubes, where they combine into larger particles which flow to the lower section of the unit. Further, as the gas stream continues through the series of tubes, a centrifugal force is generated which further removes any remaining water and small solid particulate matter.

E) Nitrogen Extraction: Once the hydrogen sulfide and carbon dioxide are processed to acceptable levels, the stream is routed to a Nitrogen Rejection Unit (NRU), where it is further dehydrated using molecular sieve beds. In the NRU, the gas stream is routed through a series of passes through a column and a brazed aluminum plate fin heat exchanger. Using thermodynamics, the nitrogen is cryogenically separated and vented. Another type of NRU unit separates methane and heavier hydrocarbons from nitrogen using an absorbent* solvent. The absorbed methane and heavier hydrocarbons are flashed off from the solvent by reducing the pressure on the processing stream in multiple gas decompression steps. The liquid from the flash regeneration step is returned to the top of the methane absorber as lean solvent. Helium, if any, can be extracted from the gas stream in a Pressure Swing Adsorption (PSA) unit.

F) Methane Separation: The process of demethanizing the gas stream can occur as a separate operation in the gas plant or as part of the NRU operation. Cryogenic processing and absorption methods are some of the ways to separate methane from NGLs. The cryogenic method is better at extraction of the lighter liquids, such as ethane, than is the alternative absorption method. Essentially, cryogenic processing consists of lowering the temperature of the gas stream to around -120 degrees Fahrenheit. While there are several ways to perform this function the turbo expander process is most effective, using external refrigerants to chill the gas stream. The quick drop in temperature that the expander is capable of producing condenses the hydrocarbons in the gas stream, but maintains methane in its gaseous form.The absorption* method, on the other hand, uses a “lean” absorbing oil to separate the methane from the NGLs. While the gas stream is passed through an absorption tower, the absorption oil soaks up a large amount of the NGLs. The “enriched” absorption oil, now containing NGLs, exits the tower at thebottom. The enriched oil is fed into distillers where the blend is heated to above the boiling point of the NGLs, while the oil remains fluid. The oil is recycled while the NGLs are cooled and directed to a fractionator tower. Another absorption method that is often used is the refrigerated il absorption method where the lean oil is chilled rather than heated, a feature that enhances recovery rates somewhat.

G) Fractionation: Fractionation, the process of separating the various NGLs present in the remaining gas stream, uses the varying boiling points of the individual hydrocarbons in the stream, by now virtually all NGLs, to achieve the task. The process occurs in stages as the gas stream rises through several towers where heating units raise the temperature of the stream, causing the various liquids to separate and exit into specific holding tanks.

* Adsorption is the binding of molecules or particles to the surface of a material, while absorption is the filling of the pores in a solid. The binding to the surface is usually weak with adsorption, and therefore, usually easily reversible.

Spherical Separators

These separators are occasionally used for high pressure service where compact size is desired and liquid volumes are small.  Factors considered for a spherical separator are:
· compactness;
· limited liquid surge capacity;
· minimum steel for a given pressure.

Horizontal Separators :

Horizontal separators are most efficient where large volumes of total fluids and large amounts of dissolved gas are present with the liquid. The greater liquid surface area in this configuration provides optimum conditions for releasing entrapped gas. In the horizontal separator,the liquid which has been separated from the gas moves along the bottom of the vessel to the liquid outlet. The gas and liquid occupy their proportionate shares of shell cross-section. Increased slug capacity is obtained through shortened retention time and increased liquid level.Fig also illustrates the separation of two liquid phases (glycol and hydrocarbon). The denser glycol settles to the bottom and is withdrawn through the "boot." The glycol level is controlled by a conventional level control instrument. In a double barrel separator, the liquids fall through connecting flow pipes into the external liquid reservoir below. Slightly smaller vessels may be possible with the double barrel horizontal separator where surge capacity establishes the size of the lower liquid collection chamber.
As an example of a horizontal separator consider a rich amine flash tank. In this service:
· There is relatively large liquid surge volume leading to longer retention time (this allows more complete release of the dissolved gas and, if necessary, surge volume for the circulating system).
· There is more surface area per liquid volume to aid in more complete degassing.
· The horizontal configuration would handle a foaming liquid better than a vertical.
· The liquid level responds slowly to changes in liquid inventory.

Vertical Separators

Vertical separators, are usually selected when the gas-liquid ratio is high or total gas volumes are low. In the vertical separator, the fluids enter the vessel striking a diverting baffle which initiates primary separation. Liquid removed by the inlet baffle falls to the bottom of the vessel. The gas moves upward, usually passing through a mist extractor to remove suspended mist, and then the "dry" gas flows out. Liquid removed by the mist extractor is coalesced into larger droplets which then fall through the gas to the liquid reservoir in the bottom. The ability to handle liquid slugs is typically obtained by increasing height. Level control is not critical and liquid level can fluctuate several inches without affecting operating efficiency. Mist extractors can significantly reduce the required diameter of vertical separators. As an example of a vertical separator, consider a compressor suction scrubber. In this service the vertical separator: · Does not need significant liquid retention volume.

Separators

Process of Separation:
Momentum.  Fluid phases with different densities will have different momentum. If a two phase stream changes direction sharply, greater momentum will not allow the particles of the heavier phase to turn as rapidly as the lighter fluid, so separation occurs. Momentum is usually employed for bulk separation of the two phases in a stream.
Gravity Settling.  Liquid droplets will settle out of a gas phase if the gravitational force acting on the droplet is greater than the drag force of the gas flowing around the droplet. These  forces can be described mathematically using the terminal or free settling velocity.
Very small droplets such as fog or mist cannot be separated practically by gravity. These droplets can be coalesced to form larger droplets that will settle by gravity.
Coalescing. Coalescing devices in separators force gas to follow a tortuous path. The momentum of the droplets causes them to collide with other droplets or the coalescing device, forming larger droplets. These larger droplets can then settle out of the gas phase by gravity. Wire mesh screens, vane elements, and filter cartridges are typical examples of coalescing devices.

Filter Separators: A filter separator usually has two compartments.The first compartment contains filter-coalescing elements. As the gas flows through the elements, the liquid particles coalesce into larger droplets and when the droplets reach sufficient size, the gas flow causes them to flow out of the filter elements into the center core. The particles are then carried into the second compartment of the vessel (containing a vane-type or knitted wire mesh mist extractor) where the larger droplets are removed. A lower barrel or boot may be used for surge or storage of the removed liquid.
Flash Tank: A vessel used to separate the gas evolved from liquid flashed from a higher pressure to a lower pressure.
Line Drip: Typically used in pipelines with very high gas to liquid ratios to remove only free liquid from a gas stream, and not necessarily all the liquid. Line drips provide a place for free liquids to separate and accumulate.
Liquid-Liquid Separators: Two immiscible liquid phases can be separated using the same principles as for gas and liquid separators. Liquid-liquid separators are fundamentally the same as gas-liquid separators except that they must be designed for much lower velocities. Because the difference in density between two liquids is less than between gas and liquid, separation is more difficult.
Scrubber or Knockout: A vessel designed to handle streams with high gas-to-liquid ratios. The liquid is generally entrained as mist in the gas or is free-flowing along the pipe wall. These vessels usually have a small liquid collection section. The terms are often used interchangeably.

Separator: A vessel used to separate a mixed-phase stream into gas and liquid phases that are "relatively" free of each other. Other terms used are scrubbers, knockouts, line-drips, and decanters.
Slug Catcher: A particular separator design able to absorb sustained in-flow of large liquid volumes at irregular intervals. Usually found on gas gathering systems or other two phase pipeline systems. A slug catcher may be a single large vessel or a manifolded system of pipes.

Three Phase Separator: A vessel used to separate gas and two immiscible liquids of different densities (e.g. gas, water, and oil).
Parts of a Separator: Regardless of shape, separation vessels usually contain four major sections, plus the necessary controls. These sections are shown for horizontal and vertical vessels in Fig. The primary separation section, A, is used to separate the main portion of free liquid in the inlet stream. It contains the inlet nozzle which may be tangential, or a diverter baffle to take

advantage of the inertial effects of centrifugal force or an abrupt change of direction to separate the major portion of the liquid from the gas stream.The secondary or gravity section, B, is designed to utilizethe force of gravity to enhance separation of entrained droplets.It consists of a portion of the vessel through which the gasmoves at a relatively low velocity with little turbulence. In some designs, straightening vanes are used to reduce turbulence. The vanes also act as droplet collectors, and reduce the distance a droplet must fall to be removed from the gas stream. The coalescing section, C, utilizes a coalescer or mist extractor which can consist of a series of vanes, a knitted wire mesh pad, or cyclonic passages. This section removes the very small droplets of liquid from the gas by impingement on a surface where they coalesce. A typical liquid carryover from the mist
extractor is less than 0.1 gallon per MMscf. The sump or liquid collection section, D, acts as receiver for all liquid removed from the gas in the primary, secondary, and coalescing sections. Depending on requirements, the liquid section should have a certain amount of surge volume, for degassing or slug catching, over a minimum liquid level necessary for controls to function properly. Degassing may require a horizontal separator with a shallow liquid level while emulsion separation may also require higher temperature, higher liquid level, and/or the addition of a surfactant.
Separator Configurations :
Factors to be considered for separator configuration selection include:
· How well will extraneous material (e.g. sand, mud, corrosion products) be handled?
· How much plot space will be required?
· Will the separator be too tall for transport if skidded?
· Is there enough interface surface for three-phase separation (e.g. gas/hydrocarbon/glycol liquid)?
· Can heating coils or sand jets be incorporated if required?
· How much surface area is available for degassing of separated liquid?
· Must surges in liquid flow be handled without large changes in level?
· Is large liquid retention volume necessary?

Product Specifications

Specifications for natural gas liquid products:
Fig. 1: GPA specifications for commercial propane, commercial butane, commercial butane-propane mixtures, and Propane HD-5.1

Fig.2: GPA specifications for natural gasoline.
These are "official" industry standards, representing a broad industry consensus for minimum quality products. Producers, purchasers, or pipeline companies may adopt variations of these specifications.

The gas plant designer and operator, as well as purchasers, will also be concerned with specifications for other plant products, including residue gas, raw mix streams, ethane, propane, ethane-propane mixes, normal butane, iso-butane, and plant condensate. Although there are no "official" industry specifications for normal butane, common commercial transactions for normal butane stipulate that the product shall meet all specifications for commercial butane and, in addition, be composed of a minimum of 95 volume percent normal butane.

Common commercial specifications for iso-butane stipulate that the product contain a minimum of 95 volume percent isobutane, and also meet all specifications for commercial butane. Likewise, there are no industry standard specifications for ethane or ethane-propane (EP) mixes.
of typical quality criteria in industry use as shown in Fig.3.

Quality specifications for natural gas have historically been individually negotiated and prescribed in contracts between purchasers or pipeline companies and the producer or processor. Specification parameters for pipeline quality natural gas may include heating value, composition, contaminants, water content, and hydrocarbon dew point. Specification limits for these parameters may vary widely depending on the pipeline system, climatological conditions, end use, and other factors. Example pipeline quality gas specification parameters are shown in Fig.4.

LP-GAS SPECIFICATION PARAMETERS.
LP-gas specifications of GPA Standard 2140, shown in Fig.1, are the industry standards in the United States. International specifications, adopted in ISO 9162, are shown in Fig.5

In many cases, specification parameters for LP-gas are based on simple "pass-fail" test methods that can be performed quickly and easily by field personnel. These specifications and test methods are intended to assure products that can be safely handled in transport systems, and that will perform adequately and safely in their end-use markets. Unfortunately, many of these tests tell the design engineer or plant operator little about product composition or quantitative limits. The following discussion is intended to provide an indication of product composition and quantitative limits imposed by these industry specifications.


Vapor Pressure
Vapor pressure is a critical specification that must be observed for safe and efficient utilization of propane, butane, and butane/propane mixtures in domestic and commercial installations, and to comply with various regulations governing transport vessels and cylinders. 
The GPA vapor pressure specification limit for propane meets the requirements of U.S. Department of Transportation regulations by effectively limiting the ethane content of commercial propane and propane HD-5 to a maximum of approximately 7 volume percent. Any appreciable quantity of propylene, permitted in commercial propane only, would necessarily reduce the amount of permissible ethane due to the  higher vapor pressure of propylene relative to that of propane.
Likewise, variations in the butane content of propane, limited to 2.5 volume percent, will impact the amount of ethane permitted by the vapor pressure specification.
Moisture Content
Moisture in propane must be controlled to very low concentrations to avoid hydrate formation in pipelines and freezing in tanks, regulating equipment, and other equipment in the distribution system.


Although a properly designed and operated dehydration system produces very dry propane, moisture can and does enter the transportation and distribution system at many points, such as storage tanks, loading racks, and transport vessels. 
There are two recognized methods for determining acceptable levels of moisture in propane products: the GPA Cobalt Bromide Test, and the Valve Freeze method (ASTM D-2713). Both are "pass-fail" tests that provide qualitative determinations of commercially "dry" propane, but neither method yields quantitative measures of moisture in the product. The Cobalt Bromide test is based on the work of Hachmuth4, which determined acceptable levels of moisture in commercial equipment, and correlated these levels with results of the test procedure. The test is based on observation of color changes of cobalt bromide salt caused by the humidity of the gas or vapor surrounding it. In practice, the cobalt bromide is supported on white cotton wadding and exposed to a stream of propane vapors chilled to 32°F. The color of the cobalt bromide changes from green to lavender at about 30% relative humidity, indicating "wet" propane. Propane-water system data7,8,11 indicate that the water content of saturated propane vapors at 32°F is approximately 530 ppmw. The water content of saturated propane liquid is approximately 35 ppmw at 32°F. At 30% saturation at 32°F, commercially "dry" propane as measured by the Cobalt Bromide test will be about 159 ppmw in the vapors and about 10  ppmw in the liquid. Based on these specification limits at 32°F, Fig.6 gives maximum allowable water content of liquid propane at other system temperatures.

The valve freeze method was developed to detect excessive moisture in liquid propane, and is preferred by some over the Cobalt Bromide test. The test device is a specially constructed and calibrated orifice valve designed to simulate expansion of  propane through a pressure regulator. A liquid sample of the product to be tested is passed through the valve at a preset flow rate. The time required for the valve to freeze and interrupt flow due to moisture in the product determines whether or not the product is commercially "dry." Test data reveals that a freeze-off time of more than 60 seconds indicates less than  30 ppmw moisture in the liquid product. The method is not applicable to propane products containing anti-freeze agents such as methanol. It is also affected by the temperature of the liquid sample.

A third method, the Bureau of Mines dew point tester, is a simple field test still used by some, but is not recommended because its accuracy is dependent on many poorly controlled variables, such as temperature and pressure of the system. This method was originally developed by the U.S. Bureau of Mines and is still used as a field method to determine moisture content in natural gas systems. Butane specifications stipulate "no free water." Since butane cannot be used in vapor withdrawal systems at temperatures below its boiling point, water content is not detrimental for most butane uses.

Water Removal

In addition to separating oil and some condensate from the wet gas stream, it is necessary to remove most of the associated water. Most of the liquid, free water associated with extracted natural gas is removed by simple separation methods at or near the wellhead. However, the removal of the water vapor that exists in solution in natural gas requires a more complex treatment. This treatment consists of 'dehydrating' the natural gas, which usually involves one of two processes: either absorption, or adsorption.
Absorption occurs when the water vapor is taken out by a dehydrating agent. Adsorption occurs when the water vapor is condensed and collected on the surface.
Glycol Dehydration.
An example of absorption dehydration is known as Glycol Dehydration. In this process, a liquid desiccant dehydrator serves to absorb water vapor from the gas stream. Glycol, the principal agent in this process, has a chemical affinity for water. This means that, when in contact with a stream of natural gas that contains water, glycol will serve to 'steal' the water out of the gas stream. Essentially, glycol dehydration involves using a glycol solution, usually either diethylene glycol (DEG) or triethylene glycol (TEG), which is brought into contact with the wet gas stream in what is called the 'contactor'. The glycol solution will absorb water from the wet gas. Once absorbed, the glycol particles become heavier and sink to the bottom of the contactor where they are removed. The natural gas, having been stripped of most of its water content, is then transported out of the dehydrator. The glycol solution, bearing all of the water stripped from the natural gas, is put through a specialized boiler designed to vaporize only the water out of the solution. While water has a boiling point of 212 degrees Fahrenheit, glycol does not boil until 400 degrees Fahrenheit. This boiling point differential makes it relatively easy to remove water from the glycol solution, allowing it be reused in the dehydration process.
A new innovation in this process has been the addition of flash tank separator-condensers. As well as absorbing water from the wet gas stream, the glycol solution occasionally carries with it small amounts of methane and other compounds found in the wet gas. In the past, this methane was simply vented out of the boiler. In addition to losing a portion of the natural gas that was extracted, this venting contributes to air pollution and the greenhouse effect. In order to decrease the amount of methane and other compounds that are lost, flash tank separator-condensers work to remove these compounds before the glycol solution reaches the boiler. Essentially, a flash tank separator consists of a device that reduces the pressure of the glycol solution stream, allowing the methane and other hydrocarbons to vaporize ('flash'). The glycol solution then travels to the boiler, which may also be fitted with air or water cooled condensers, which serve to capture any remaining organic compounds that may remain in the glycol solution. In practice, according to the Department of Energy's Office of Fossil Energy, these systems have been shown to recover 90 to 99 percent of methane that would otherwise be flared into the atmosphere.

Solid-Desiccant Dehydration.
Solid-desiccant dehydration is the primary form of dehydrating natural gas using adsorption, and usually consists of two or more adsorption towers, which are filled with a solid desiccant. Typical desiccants include activated alumina or a granular silica gel material. Wet natural gas is passed through these towers, from top to bottom. As the wet gas passes around the particles of desiccant material, water is retained on the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto the desiccant material, leaving the dry gas to exit the bottom of the tower.

Solid-desiccant dehydrators are typically more effective than glycol dehydrators, and are usually installed as a type of straddle system along natural gas pipelines. These types of dehydration systems are best suited for large volumes of gas under very high pressure, and are thus usually located on a pipeline downstream of a compressor station. Two or more towers are required due to the fact that after a certain period of use, the desiccant in a particular tower becomes saturated with water. To 'regenerate' the desiccant, a high-temperature heater is used to heat gas to a very high temperature. Passing this heated gas through a saturated desiccant bed vaporizes the water in the desiccant tower, leaving it dry and allowing for further natural gas dehydration.

Sulfur and Carbon Dioxide Removal

In addition to water, oil, and NGL removal, one of the most important parts of gas processing involves the removal of sulfur and carbon dioxide. Natural gas from some wells contains significant amounts of sulfur and carbon dioxide. This natural gas, because of the rotten smell provided by its sulfur content, is commonly called 'sour gas'. Sour gas is undesirable because the sulfur compounds it contains can be extremely harmful, even lethal, to breathe. Sour gas can also be extremely corrosive. In addition, the sulfur that exists in the natural gas stream can be extracted and marketed on its own.

Gas Sweetening Plant
Sulfur exists in natural gas as hydrogen sulfide (H2S), and the gas is usually considered sour if the hydrogen sulfide content exceeds 5.7 milligrams of H2S per cubic meter of natural gas. The process for removing hydrogen sulfide from sour gas is commonly referred to as 'sweetening' the gas.
The primary process for sweetening sour natural gas is quite similar to the processes of glycol dehydration and NGL absorption. In this case, however, amine solutions are used to remove the hydrogen sulfide. This process is known simply as the 'amine process', or alternatively as the Girdler process, and is used in 95 percent of U.S. gas sweetening operations. The sour gas is run through a tower, which contains the amine solution. This solution has an affinity for sulfur, and absorbs it much like glycol absorbing water. There are two principle amine solutions used, monoethanolamine (MEA) and diethanolamine (DEA). Either of these compounds, in liquid form, will absorb sulfur compounds from natural gas as it passes through. The effluent gas is virtually free of sulfur compounds, and thus loses its sour gas status. Like the process for NGL extraction and glycol dehydration, the amine solution used can be regenerated (that is, the absorbed sulfur is removed), allowing it to be reused to treat more sour gas.
Although most sour gas sweetening involves the amine absorption process, it is also possible to use solid desiccants like iron sponges to remove the sulfide and carbon dioxide.
Sulfur can be sold and used if reduced to its elemental form. Elemental sulfur is a bright yellow powder like material, and can often be seen in large piles near gas treatment plants, as is shown. In order to recover elemental sulfur from the gas processing plant, the sulfur containing discharge from a gas sweetening process must be further treated. The process used to recover sulfur is known as the Claus process, and involves using thermal and catalytic reactions to extract the elemental sulfur from the hydrogen sulfide solution.

Oil and Condensate Removal

In order to process and transport associated dissolved natural gas, it must be separated from the oil in which it is dissolved. This separation of natural gas from oil is most often done using equipment installed at or near the wellhead.
The actual process used to separate oil from natural gas, as well as the equipment that is used, can vary widely. Although dry pipeline quality natural gas is virtually identical across different geographic areas, raw natural gas from different regions may have different compositions and separation requirements. In many instances, natural gas is dissolved in oil underground primarily due to the pressure that the formation is under. When this natural gas and oil is produced, it is possible that it will separate on its own, simply due to decreased pressure; much like opening a can of soda pop allows the release of dissolved carbon dioxide. In these cases, separation of oil and gas is relatively easy, and the two hydrocarbons are sent separate ways for further processing. The most basic type of separator is known as a conventional separator. It consists of a simple closed tank, where the force of gravity serves to separate the heavier liquids like oil, and the lighter gases, like natural gas.
In certain instances, however, specialized equipment is necessary to separate oil and natural gas. An example of this type of equipment is the Low-Temperature Separator (LTX). This is most often used for wells producing high pressure gas along with light crude oil or condensate. These separators use pressure differentials to cool the wet natural gas and separate the oil and condensate. Wet gas enters the separator, being cooled slightly by a heat exchanger. The gas then travels through a high pressure liquid 'knockout', which serves to remove any liquids into a low-temperature separator. The gas then flows into this low-temperature separator through a choke mechanism, which expands the gas as it enters the separator. This rapid expansion of the gas allows for the lowering of the temperature in the separator. After liquid removal, the dry gas then travels back through the heat exchanger and is warmed by the incoming wet gas. By varying the pressure of the gas in various sections of the separator, it is possible to vary the temperature, which causes the oil and some water to be condensed out of the wet gas stream. This basic pressure-temperature relationship can work in reverse as well, to extract gas from a liquid oil stream.

NGL (Natural Gas Liquids) Extraction

There are two principle techniques for removing NGLs from the natural gas stream: the absorption method and the cryogenic expander process. According to the Gas Processors Association, these two processes account for around 90 percent of total natural gas liquids production.

The Absorption Method 
The absorption method of NGL extraction is very similar to using absorption for dehydration. The main difference is that, in NGL absorption, an absorbing oil is used as opposed to glycol. This absorbing oil has an 'affinity' for NGLs in much the same manner as glycol has an affinity for water. Before the oil has picked up any NGLs, it is termed 'lean' absorption oil. As the natural gas is passed through an absorption tower, it is brought into contact with the absorption oil which soaks up a high proportion of the NGLs. The 'rich' absorption oil, now containing NGLs, exits the absorption tower through the bottom. It is now a mixture of absorption oil, propane, butanes, pentanes, and other heavier hydrocarbons. The rich oil is fed into lean oil stills, where the mixture is heated to a temperature above the boiling point of the NGLs, but below that of the oil. This process allows for the recovery of around 75 percent of butanes, and 85 - 90 percent of pentanes and heavier molecules from the natural gas stream.
The basic absorption process above can be modified to improve its effectiveness, or to target the extraction of specific NGLs. In the refrigerated oil absorption method, where the lean oil is cooled through refrigeration, propane recovery can be upwards of 90 percent, and around 40 percent of ethane can be extracted from the natural gas stream. Extraction of the other, heavier NGLs can be close to 100 percent using this process.

The Cryogenic Expansion Process.
Cryogenic processes are also used to extract NGLs from natural gas. While absorption methods can extract almost all of the heavier NGLs, the lighter hydrocarbons, such as ethane, are often more difficult to recover from the natural gas stream. In certain instances, it is economic to simply leave the lighter NGLs in the natural gas stream. However, if it is economic to extract ethane and other lighter hydrocarbons, cryogenic processes are required for high recovery rates. Essentially, cryogenic processes consist of dropping the temperature of the gas stream to around -120 degrees Fahrenheit.
There are a number of different ways of chilling the gas to these temperatures, but one of the most effective is known as the turbo expander process. In this process, external refrigerants are used to cool the natural gas stream. Then, an expansion turbine is used to rapidly expand the chilled gases, which causes the temperature to drop significantly. This rapid temperature drop condenses ethane and other hydrocarbons in the gas stream, while maintaining methane in gaseous form. This process allows for the recovery of about 90 to 95 percent of the ethane originally in the gas stream. In addition, the expansion turbine is able to convert some of the energy released when the natural gas stream is expanded into recompressing the gaseous methane effluent, thus saving energy costs associated with extracting ethane.
The extraction of NGLs from the natural gas stream produces both cleaner, purer natural gas, as well as the valuable hydrocarbons that are the NGLs themselves.
Natural Gas Liquid Fractionation
Once NGLs have been removed from the natural gas stream, they must be broken down into their base components to be useful. That is, the mixed stream of different NGLs must be separated out. The process used to accomplish this task is called fractionation. Fractionation works based on the different boiling points of the different hydrocarbons in the NGL stream. Essentially, fractionation occurs in stages consisting of the boiling off of hydrocarbons one by one. The name of a particular fractionator gives an idea as to its purpose, as it is conventionally named for the hydrocarbon that is boiled off. The entire fractionation process is broken down into steps, starting with the removal of the lighter NGLs from the stream. The particular fractionators are used in the following order:
• Deethanizer - this step separates the ethane from the NGL stream.
• Depropanizer - the next step separates the propane.
• Debutanizer - this step boils off the butanes, leaving the pentanes and heavier hydrocarbons in the NGL stream.
• Butane Splitter or Deisobutanizer - this step separates the iso and normal butanes.
By proceeding from the lightest hydrocarbons to the heaviest, it is possible to separate the different NGLs reasonably easily.

Natural gas Processing

Natural gas, as it is used by consumers, is much different from the natural gas that is brought from underground up to the wellhead. Although the processing of natural gas is in many respects less complicated than the processing and refining of crude oil, it is equally as necessary before its use by end users.
The natural gas used by consumers is composed almost entirely of methane. However, natural gas found at the wellhead, although still composed primarily of methane, is by no means as pure. Raw natural gas comes from three types of wells: oil wells, gas wells, and condensate wells. Natural gas that comes from oil wells is typically termed 'associated gas'. This gas can exist separate from oil in the formation (free gas), or dissolved in the crude oil (dissolved gas). Natural gas from gas and condensate wells, in which there is little or no crude oil, is termed 'nonassociated gas'. Gas wells typically produce raw natural gas by itself, while condensate wells produce free natural gas along with a semi-liquid hydrocarbon condensate. Whatever the source of the natural gas, once separated from crude oil (if present) it commonly exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and other compounds. To learn about the basics of natural gas, including its composition, click here.
Natural gas processing consists of separating all of the various hydrocarbons and fluids from the pure natural gas, to produce what is known as 'pipeline quality' dry natural gas. Major transportation pipelines usually impose restrictions on the make-up of the natural gas that is allowed into the pipeline. That means that before the natural gas can be transported it must be purified. While the ethane, propane, butane, and pentanes must be removed from natural gas, this does not mean that they are all 'waste products'.
In fact, associated hydrocarbons, known as 'natural gas liquids' (NGLs) can be very valuable by-products of natural gas processing. NGLs include ethane, propane, butane, iso-butane, and natural gasoline. These NGLs are sold separately and have a variety of different uses; including enhancing oil recovery in oil wells, providing raw materials for oil refineries or petrochemical plants, and as sources of energy.
While some of the needed processing can be accomplished at or near the wellhead (field processing), the complete processing of natural gas takes place at a processing plant, usually located in a natural gas producing region. The extracted natural gas is transported to these processing plants through a network of gathering pipelines, which are small-diameter, low pressure pipes. A complex gathering system can consist of thousands of miles of pipes, interconnecting the processing plant to upwards of 100 wells in the area. According to the American Gas Association's Gas Facts 2000, there was an estimated 36,100 miles of gathering system.

In addition to processing done at the wellhead and at centralized processing plants, some final processing is also sometimes accomplished at 'straddle extraction plants'. These plants are located on major pipeline systems. Although the natural gas that arrives at these straddle extraction plants is already of pipeline quality, in certain instances there still exist small quantities of NGLs, which are extracted at the straddle plants.
The actual practice of processing natural gas to pipeline dry gas quality levels can be quite complex, but usually involves four main processes to remove the various impurities:
• Oil and Condensate Removal
• Water Removal
• Separation of Natural Gas Liquids
• Sulfur and Carbon Dioxide Removal

In addition to the four processes above, heaters and scrubbers are installed, usually at or near the wellhead. The scrubbers serve primarily to remove sand and other large-particle impurities. The heaters ensure that the temperature of the gas does not drop too low. With natural gas that contains even low quantities of water, natural gas hydrates have a tendency to form when temperatures drop. These hydrates are solid or semi-solid compounds, resembling ice like crystals. Should these hydrates accumulate, they can impede the passage of natural gas through valves and gathering systems. To reduce the occurrence of hydrates, small natural gas-fired heating units are typically installed along the gathering pipe wherever it is likely that hydrates may form.

Process in oil and Gas Industry

Main Process  in oil and Gas Industry


Well fluids are often a complex mixture of liquid hydrocarbons, gas and some impurities. It is necessary to remove liquid hydrocarbons & objectionable impurities from natural gas before the gas is supplied to the buyer.
The separation/purification of natural gas, liquid hydrocarbons and removal of impurities is accomplished by various processes such as gas dehydration, gas sweetening, dew point control, LPG/condensate fractionation, liquid recovery etc. depending upon the composition of the well stream and the desired specifications of the end products.

MATERIALS OF CONSTRUCTION

Vessel/Tank Materials

Metallic

Shop welded, field welded, and bolted storage tanks are customarily fabricated from mild quality carbon steel. Most common for welded tanks are A-36 structural steel and A-283 grade “C” structural quality carbon steel. Sheet gauge steels for bolted tanks are of commercial quality having a minimum tensile strength of 52,000 psi. A-612, A-515, and A-516 mild quality low carbon steels are used for fabricating the higher pressure storage products such as spheres and “bullets.”Various API and ASME Codes (listed in the References) to which the storage tank is fabricated, set forth the welding procedures, inspection procedures, testing requirements, and material selection. Some storage applications or service con-ditions (low temperature storage) require storage tanks to be fabricated from metals such as low alloy stainless steel, aluminum, or other specialty materials.

Non-Metallic 

Older non-metallic tanks were customarily constructed from wood. Plastic materials have now replaced wood.  These materials have the advantage of being non-corroding, durable, low cost, and lightweight. Plastic materials used in the construction are polyvinyl chloride, polyethylene, polypropylene, and fiberglass-reinforced polyesters. The fiberglass- reinforced polyester (FRP) tanks are available in the larger sizes and are the most common. FRP tanks are suitable for outdoor as well as indoor applications. FRP tanks with special reinforced shells are designed for underground storage service. Above ground  tanks are primarily vertical, with or without top heads. Non-metallic tanks constructed of unreinforced plastics such as polyvinyl chloride or polyethylene materials are available in sizes up to about 6 ft in diameter by 11 ft high (2400 gallons). Horizontal underground FRP tanks will hold up to 12,000 gallons. Above ground vertical FRP tanks can store from 12,000 to 24,000 gallons, depending upon the shell construction. The temperature limits of plastic tanks are 40°F to 150°F. Color must be added to the outer liner for protection against ultraviolet radiation. The inner liner must be selected for compatibility with the chemical or product stored. Protection from mechanical abuse such as impact loads is a necessity. Good planning dictates that plastic storage should not be located next to flammable storage tanks. All closed plastic tanks should be equipped with pressure relief devices.

Protective Coatings:

 Internal

Use of internal coatings is primarily to protect the inside surface of the tank against corrosionwhile also protecting the stored contents from contamination. Consideration must always be given to such factors as the type of product being stored, type of coating available, type of surface to be coated, surface preparation, compatibility of coatings, and number of coats required to obtain maximum protection. Many types of internal coatings are available. Due to the unlimited types and applications, only a few will be described as follows:
Coal Tar

Among the oldest and most reliable coatings. Extremely low permeability; protects surface by the mechanical exclusion of moisture and air; extremely water resistant; good resistance to weak mineral acids, alkalis, salts, brine solutions, and other aggressive chemicals.
Epoxy Resin Coatings 

Excellent adhesion, toughness, abrasion resistance, flexibility, durability, and good chemical and moisture resistance. Typical applications include linings for sour crude tanks, floating roof tanks, solvent storage tanks, drilling mud tanks, sour water, treated water, and pipelines.
Rubber Lining — Used as internal lining for storage tanks which are subjected to severe service such as elevated temperatures or for protection from extremely corrosive contents, such as concentrated chlorides and various acids such as chromic, sulfuric, hydrochloric, and phosphoric.
Galvanized — Galvanizing (zinc coating) is highly resistant to most types of corrosion. Bolted steel tanks are ideally suited for galvanizing since all component parts are galvanized by the hot-dip process after fabrication but before erection. Galvanized bolted tanks are recommended where the oil produced contains sulfur compounds and/or is associated with hydrogen sulfide gas. Galvanizing is also effective against corrosion in seacoast areas where atmospheric salt conditions accelerate
corrosion problems.

External 

The basic requirements for external coatings are appearance and weather protection. Numerous types of external coatings are available, ranging from basic one-coat primers to primers with one or more topcoats. Environmental conditions usually dictate the extent of coating applied. Offshore and coastal installations require  more extensive coatings as compared to inland locations.

STORAGE CLASSIFICATION

Above Ground
Atmospheric — Atmospheric pressure tanks are designed and equipped for storage of contents at atmospheric pressure. This category usually employs tanks of vertical cylindrical configuration that range in size from small shop welded to large field erected tanks. Bolted tanks, and occasionally rectangular welded tanks, are also used for atmospheric storage service.
Low Pressure (0 to 2.5 psig) — Low pressure tanks are normally used in applications for storage of intermediates and products that require an internal gas pressure from close to atmospheric up to a gas pressure of 2.5 psig. The shape is generally cylindrical with flat or dished bottoms and sloped or domed roofs. Low pressure storage tanks are usually of welded design. However, bolted tanks are often used for operating pressures near atmospheric. Many refrigerated storage tanks operate at approximately 0.5 psig.
Medium Pressure (2.5 to 15 psig) — Medium pressure tanks are normally used for the storage of higher volatility intermediates and products that cannot be stored in low pressure tanks. The shape may be cylindrical with flat or dished bottoms and sloped or domed roofs. Medium pressure tanks are usually of welded design. Welded spheres may also be used, particularly for pressures at or near 15 psig.
High Pressure (Above 15 psig) — High pressure tanks are generally used for storage of refined products or fractionated components at pressure above 15 psig. Tanks are of welded design and may be of cylindrical or spherical configuration.

Underground:

Gas processing industry liquids may be stored in underground, conventionally mined or solution mined caverns. No known standard procedures are available for this type storage; however, there are many publications and books covering the subject in detail.

WORKING PRESSURES
A design working pressure can be determined to prevent breathing, and thereby save standing storage losses. However, this should not be used in lieu of any environmental regulatory requirements regarding the design of storage tanks. The environmental regulatory requirements for the specific location should be consulted prior to the design of storage facilities. Generally there are regulatory requirements specifying the type of storage tank to be used, based on the storage tank capacity and the vapor pressure of the product being stored. In addition there are usually specific design requirements, for example in the type of seals to be used in a floating roof tank. The working pressure required to prevent breathing losses depends upon the vapor pressure of the product, the temperature variations of the liquid surface and the vapor space, and the setting of the vacuum vent.

Above fig is presented as a general guide to storage pressures for gasolines of various volatilities in uninsulated tanks , using the following assumptions:
· Minimum liquid surface temperature is 10°F less than the maximum liquid surface temperature.
· Maximum vapor space temperature is 40°F greater than the maximum liquid surface temperature.
· Minimum vapor space temperature is 15°F less than the maximum liquid surface temperature.
· Stable ambient conditions (ambient temp. 100°F).

These temperature variations are far greater than would be experienced from normal night to day changes. Therefore, the lower, nearly horizontal line, which shows a required storage pressure of 2.5 psig for the less volatile gasolines is conservative and allows a wide operating margin.
Maximum liquid surface temperatures vary from 85 to 115°F. Sufficient accuracy will generally result from the assumption that it is 10°F higher than the maximum temperature of the body of the liquid in a tank at that location. Example  — To illustrate the use of above Fig., suppose a 24 psia true vapor pressure (TVP) natural gasoline is to be stored where the liquid surface temperature may reach a maximum of 100°F. A vertical line extended upward from the 24 psia mark at the bottom of the chart intersects the 100°F line at 9.3 psig. The design pressure of the tank should be a minimum of 10.23 psig (9.3 psig + 10%).

Fig. given below can be used as follows:
· As quick reference to determine true vapor pressures of typical LPGs, natural gasolines, and motor fuel components at various temperatures.
· To estimate the operating pressure of a storage tank necessary to maintain the stored fluid in a liquid state at various temperatures.
· For converting from true vapor pressure to Reid Vapor Pressure (RVP).
· For simple evaluation of refrigerated storage versus ambient temperature storage for LPGs.

Example — Determine the TVP of a 12 psi RVP gasoline. In addition, estimate the design pressure of a tank needed to store this same 12 RVP gasoline at a maximum temperature of 120°F. Using Fig. 6-4, a vertical line is extended upwards from the 100°F mark (100°F is used as the reference point for determining RVP) at the bottom of the chart to the intersection of the 12 psi RVP line, read true vapor pressure of 13.2 psia. A vertical line is also extended from the 120°F mark to intersect the 12 RVP gasoline line. Now going horizontal, the true vapor pressure axis is crossed at approximately 18.1 psia. The storage tank should therefore be designed to operate at 18.1 psia (3.4 psig) or above. The design pressure of the tank should be a minimum of 10% above the operating gauge pressure
or approximately 18.5 psia.

TYPES OF STORAGE
Above Ground
For operating pressures above 15 psig, design and fabrication are governed by the ASME Code, Section VIII. 

Spheres — Spherical shaped storage tanks these are generally used for storing products at pressures above 5 psig.

Spheroids — A spheroidal tank is essentially spherical in shape except that it is somewhat flattened. Hemispheroidal tanks have cylindrical shells with curved roofs and bottoms. Noded spheroidal tanks are generally used in the larger sizes and have internal ties and supports to keep shell stresses low. These tanks are generally used for storing products above 5 psig.

Horizontal Cylindrical Tanks — The working pressure of these tanks (Fig. 6-7) can be from 15 psig to 1000 psig, or greater. These tanks often have hemispherical heads.

Fixed Roof — Fixed roofs are permanently attached to the tank shell.Welded tanks of 500 barrel capacity and larger may be provided with a frangible roof (designed for safety release of the welded deck to shell joint in the event excess internal pressure occurs), in which case the design pressure shall not exceed the equivalent pressure of the dead weight of the roof, including rafters, if external.

Floating Roof — Storage tanks may be furnished with floating roofs (Fig. 6-8) whereby the tank roof floats upon the stored contents. This type of tank is primarily used for storage near atmospheric pressure. Floating roofs are designed to move vertically within the tank shell in order to provide a constant minimum void between the surface of the stored product and the roof. Floating roofs are designed to provide a constant seal between the periphery of the floating roof and the tank shell.  They can be fabricated in a type that is exposed to the weather or a type that is under a fixed roof. Internal floating roof tanks with an external fixed roof are used in areas of heavy snowfalls since accumulations of snow or water on the floating roof affect the operating buoyancy. These can be installed in existing tanks as well as new tanks. Both floating roofs and internal floating roofs are utilized to reduce vapor losses and aid in conservation of stored fluids.

Bolted—Bolted tanks are designed and furnished as segmental elements which are assembled on location to provide complete vertical, cylindrical, above ground, closed and open top steel storage tanks. Standard API bolted tanks are available in nominal capacities of 100 to 10,000 barrels, designed for approximately atmospheric internal pressures. Bolted tanks offer the advantage of being easily transported to desired locations and erected by hand. To meet changing requirements for capacity of storage, bolted tanks can be easily dismantled and re-erected at new locations.

Flat-Sided Tanks— Although cylindrical shaped tanks may be structurally best for tank construction, rectangular tanks occasionally are preferred. When space is limited, such as offshore, requirements favor flat-sided tank construction because several cells of flat-sided tanks can be easily fabricated and arranged in less space than other types of tanks. Flat sided or rectangular tanks are normally used for atmospheric type storage.1

Lined Ponds2 — Ponds are used for disposal, evaporation, or storage of liquids. Environmental considerations may preclude the use of lined ponds for the storage of more volatile or toxic fluids. Linings are used to prevent storage liquid losses, seepage into the ground, and possible ground water contamination. Clay, wood, concrete, asphalt, and metal linings have been used for many years. More recently, a class of impervious lining materials has been developed that utilize flexible synthetic membranes. Commonly used lining materials are polyvinyl chloride, natural rubber, butyl rubber, and Hypalon®. Polyethylene, nylons, and neoprenes are used to a lesser extent. Some of the most important qualities of a suitable liner are:

· High tensile strength and flexibility.
· Good weather ability.
· Immunity to bacterial and fungus attack.
· Specific gravity greater than 1.0
· Resistance to ultraviolet-light attack.
· Absence of all imperfections and physical defects.
· Easily repaired.

Leak detection sometimes must be built into the pond system, especially where toxic wastes or pollutants are to be stored. Types of leak-detection systems that are commonly used are underbed (French) drainage system, ground resistively measurement, and monitor wells, and any combination thereof.

Pit Storage — Pit storage is similar to pond storage but is only used on an emergency basis. The use of this type of storage is limited by local, state, and federal regulations.

Underground: 
Underground storage is most advantageous when large volumes are to be stored. Underground storage is especially advantageous for high vapor pressure products.
Types of underground storage are:

(1) caverns constructed in salt by solution mining or conventional mining. (2) caverns constructed in nonporous rock by conventional mining. (3) caverns developed by conversion of depleted coal, limestone, or salt mines to storage.

Refrigerated Storage
The decision to use refrigerated storage in lieu of pressurized storage is generally a function of the volume of the liquid to be stored, the fill rate, the physical and thermodynamic properties of the liquid to be stored, and the capital investment and operating expenses of each type of system. 
The parameters involved in selecting the optimum refrigerated storage facility are:
· Quantity and quality of product to be stored.
· Fill rate, temperature, and pressure of incoming stream.
· Shipping conditions for the product.
· Composition of the product.
· Cooling media (air, water, etc.) available.
· Availability and cost of utilities.

The proper choice of storage and the proper integration of the storage facility with the refrigeration facilities are important to overall economy in the initial investment and operating costs. Fig given as under provides some general guidelines to use when selecting a storage system for propane.

When using refrigerated storage, the liquid to be stored is normally chilled to its bubble point temperature at atmospheric pressure. Refrigerated storage tanks normally operate at an internal pressure between 0.5 and 2.0 psig. In some cases, pressurized-refrigerated storage is attractive. In this type of refrigerated storage, the product to be stored is chilled to a temperature that allows it to be stored at a pressure somewhere between atmospheric pressure and its vapor pressure at ambient temperature. Refrigeration requirements normally include the following basic functions:
            · Cooling the fill stream to storage temperature.
            · Reliquefying product vaporized by heat leak into the system.
            · Liquefying vapors displaced by the incoming liquid.

Other factors which should be considered are:
            · Pump energy requirements
            · Barometric pressure variations
            · Product compositions
            · Non-condensables
            · Solar radiation effects
            · Superheated products