Separation, dehydration, desalting, sweetening and stabilization of oil and natural gas
Prepared by Said Merheb Graduate Graduate Piping Engineer Supervisor: Shrinivas Honavarkar January, 2006
Constituents The desirable constituents of crude oil and natural gas are the hydrocarbons. The major proportion is of the family of paraffin (alkanes). The family resemblance is in their form C nH2n+2 . The range of n=1 to n=4 are gases (at atmospheric pressure) methane, methane, ethane, propane and butane. li quefied under pressure and at low • Methane mainly and a small proportion of ethane are liquefied temperatures (cryogenically) (cryogenically) in order to be transported safely over long distances. This mixture is called Liquefied Natural Gas (LNG). • Ethane, propane and butane can be liquefied under pressure at normal temperature and this is normally called Liquefied Petroleum Gas (LPG). This is what is normally used where gas is supplied in small canisters for domestic use. The paraffins of C5 and C6, pentane and hexane, are generally regarded as condensate liquids. These hydrocarbons can be liquefied l iquefied at normal pressure and temperature and are commonly called Natural Gas Liquids (NGL). In some references, NGL also include propane and butane. The hydrocarbons are produced as oil, clearly of increasing viscosity and decreasing volatility from n=7 to n=120.
Processing Wellhead Wellhead fluids - crude oil, natural gas, and brine must be processed before sale, storage, transport, transport, re-injection or disposal di sposal in order to meet sale / transportation / reinjection specifications and / or environmental regulations.
Therefore oil and gas production involve a number of surface unit operations between the wellhead and the point of transfer or transport transport from the production facilities. These operations are called field handling or oilfield processing and are as follows: foll ows:
• • • • •
Separation Dehydration Desalting Sweetening Stabilization
Oilfield processing also includes water treatment, whether produced water for disposal additional injection water for formation flooding or reservoir pressure maintenance.
Acid Gas
Sulfur Removal
Flare
Sulfur
Gas
Sweetening
Dehydration
Condensate Removal
Transport
Compression/ Pipeline/Flare/ Reinjection
Condensate
Wellheads
Gathering
Phase Separation
Oil
Water
Sand
Dehydration/ Desalting
Skimming
Cleanup
Sweetening
Filtration
Stabilization
Storage/Pipeline
Stabilization
Storage/Pipeline
Softening/ Deaeration
Disposal/Reinjection
Disposal
Separation Separation is the operation of separating the produced wellhead stream of gas, oil and water into single phases.
WHY?? Phase separation of the production stream is usually performed as soon as possible because: • It is technically easier and less costly to process the gas, crude oil, and produced water phases separately. • The produced water is often corrosive. Therefore, removing the water often allows less costly materials of construction to be used downstream and reduces corrosion damage. • Less energy is required to move the separated single phases; so phase separation permits the back pressure to be lowered and this, in turn, increases well production.
A typical oil-gas separation sequence that includes water and incidental sediment removal.
This operation is performed in separating vessels which are referred to by many names such as: • Separator • Scrubber • Knockout
•
Expansion vessel…
Separators: They are usually field vessels used to separate gas, oil, and water coming directly from wells into phases that are relatively free of each other.
Scrubbers: They are vessels normally more efficient than conventional separators in removing small liquid drops from a gas phase. Scrubbers are often used ahead of compressors, glycol and amine units and they are often applied downstream of field separators to remove entertained and/or condensed liquids. Scrubber is not intended to handle large slugs of liquid.
Filter, Dust scrubber, or Coalescer: These separators are designed to remove small quantities of mists, rust, scales, and dust from gases. Typical applications are upstream of compressors, dehydration units, amine units and custody transfer stations. Solids are trapped by the filter fibers while liquid droplets are coalesced into large droplets. These
filter separators are often used for final “polishing”, and are often preceded, or protected, by a conventional scrubber or separator.
Classification Wellhead separators are often classified by the geometrical configuration (vertical, horizontal, horizontal double-barrel, or spherical) and by their function; two-phase (vaporliquid), or three-phase (gas-oil-water) separation.
Vertical Separators Advantages:
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occupies small plot area
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more versatile than horizontal
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liquid-level control is not so critical
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have good bottom-drain and cleanout facilities
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can handle more sand, mud, paraffin, wax without plugging
Disadvantages:
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more expensive than horizontal
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require larger diameter for a given gas capacity, therefore, most competitive for very low GOR or very high GOR or scrubber applications
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more difficult to skid mount and ship
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for small flow rates
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more difficult to reach and service top-mounted instruments and safety devices
Horizontal Separators Advantages:
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cheaper than vertical
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require smaller diameter for a same gas capacity
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lend themselves to skid mounting and shipping
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large liquid surface area for foam dispersion generally reduces turbulence
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large volume of gas and/or liquids
Disadvantages:
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only part of shell available for passage of gas
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occupy more space unless stack mounted
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liquid level control is more critical
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more difficult to clean produced sand, mud, wax, paraffin…
Several types of separator internals are used to improve effectiveness. At the minimum, a well designed separator should contain the following:
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Inlet baffle to break fluid momentum, reducing incoming fluid velocities so that quiescent settling can complete the phase separation;
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Mist extractor to remove small droplets and liquid mists from the gas stream;
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Vortex breakers to prevent vortex formation at the outlets which causes large amounts of liquid carry-over and gas slippage.
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Process Controls. The separator pressure is generally controlled by a backpressure regulator in the exit gas line. And liquid-level controllers are used in the liquid accumulation section to activate a valve to maintain the desired liquid level. A thermowell, a pressure gage, and gage glass are usually provided;
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Safety Devices. The ASME Boiler and Pressure Vessel Code requires that all separators be protected by pressure relief devices such as relief valves.
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Dehydration (Oil) After free water removal in the separation phase, produced oil often contains excessive residual emulsified water. Dehydration is the removing of remaining water droplets or S&W or BS&W from the crude and breaking the water in oil emulsions. WHY?? The major reasons for dehydrating and desalting crude oil are:
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In order to be marketable, crude oil must meet a water specification. This is often expressed in terms of BS&W (Basic Sediment and water) content and typical values range from 0.1% for light crude to 3% for heavy crude.
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Crude oil is bought and sold on API gravity basis and high gravity oils command high prices. Water lowers the API gravity and reduces the selling price of oil.
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The viscosity of crude oil increases as the water content is increased
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Costly transportation occupied by valueless water in the emulsified oil water
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Mineral salts present in oilfield waters corrode production equipment, pipelines and storage tanks.
What’s an emulsion??
An emulsion is a quasi-stable suspension of fine drops of one liquid dispersed in another liquid. There are three requirements for forming an emulsion: 1. Two immiscible liquids 2. Enough agitation to disperse one liquid into small drops 3. An emulsifier to stabilize the dispersed drops
Treating methods Crude dehydration involves optimizing the use of four techniques; demulsifying chemicals, retention time, heat and electricity to produce clean oil and clean water. Retention time and heating are usually less costly than injecting chemicals and creating electrostatic fields. Chemicals The main actions of demulsifiers are:
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Neutralizing the emulsifying agents
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Flocculation. Neutralizing any repulsive electrical charges between the dispersed drops and so allow the drops to touch
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Coalescence. They must permit small droplets to combine into drops large enough to settle
Demulsifiers should be injected as early as possible (at the wellhead). This allows more time for the chemicals to work and can also prevent possible downstream emulsion formation. It is seldom economic to break emulsions by chemicals alone. Usually additional energy (heat or electricity) is needed to reduce the dosage and hence cost of the chemicals.
Retention time Retention time is usually achieved in large holding vessels called free-water knockouts and in settling tanks. Gravitational separation fails when the crude is heavy and/or contains a high proportion of emulsion.
Free water knockouts are usually intended to remove only large percentages of free water, water that is carried in the produced stream, but not emulsified in the oil. FWKOs are of simple construction and operation and are usually designed for an oil retention time of around 10 minutes. The FWKO is often used in conjunction with other methods as a preliminary step or firststage brine removal especially when the separation is only a two phase operation. Final oil dehydration takes place in settling tank, heater treaters or electrostatic treaters. Emulsion breaking chemicals can of course be added upstream of the FWKO.
Settling Tanks are tanks with sufficient cross sectional area and retention time to allow oil to meet sales specifications. Retention times may vary from 424 hours depending on oil gravity and viscosity. For difficult emulsions, these vessels are often heated. Heater treaters are effectively FWKOs with heating coils to raise oil and water temperature, which can be effective for resolving difficult emulsions. Disadvantages include cost of fuel to heat fluids and loss of light crude factions which vaporize. Electrostatic treaters are compact treaters, which use electric field effect to induce flocculation and coalescence. They require inlet water content greater than about 5% to induce coalescence but oil must be the dominant phase to prevent short-circuiting. These treaters are used where space and weight are at a premium.
Desalting After dehydration, crude oil still contains some sediment and water, mainly salt crystals dispersed in the crude. When crude is processed in the refinery, salt can cause numerous operating problems. Salt cakes inside equipment, causes poor flow and plugging, reduces heat transfer rates in exchangers, not mentioning that brine is also very corrosive.
Desalting, which follows the initial dehydration, consists of:
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Adding dilution (or less saline) water to the crude;
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Mixing this dilution water with the crude to dilute the S&W droplets in the crude;
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Dehydration (emulsion treating) to separate the crude oil and diluted brine.
The water leaving the second desalter, while certainly more concentrated than the dilution water, is usually less saline than the brine drops entertained in the crude entering the first stage. Therefore, the dilution water required can be reduced by injecting the second-stage desalter effluent water into the crude ahead of the first stage. The reason for this operation is that ironically, field desalting is often required in regions where fresh water is the scarcest.
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Sweetening (Oil) Sulfur compounds occur to some extent in all crude oils, although some crudes contain very small amounts.
Crude oils (and Natural gases ) were originally described as sour if they contained significant amounts of hydrogen sulphide and other sulphur compounds, most of which have a characteristic disagreeable smell. Sweet crude is that which contains less than 0.5% of sulphur. Sour crude is that which contains more than 2.5% sulphur.
Sweetening consists of removing sulphur components especially H 2S. Even small amounts of H2S make the crude oil extremely toxic and corrosive. The other sulfur compounds (Mercaptans, Sulfides, disulphides …) are far less toxic and not so aggressively corrosive. The presence of liquid water exacerbates the corrosion as does CO2.
Personal safety, equipment protection and sales specifications require that H2S and (to a lesser extent) other sulfur compounds be removed.
Removal of H2S from crude oil is usually accomplished by stripping with hot or cold natural gas. Crude is stripped by flowing the oil downward over trays in a multistage column. Natural gas flows counter currently upward to remove or strip the H 2S from the crude. The gas may be available sweet gas stream or it may be vapor generated by reboiling the bottoms crude or in some cases both.
Because H2S cannot be vented to the surroundings, the overhead gas from stripping must be sweetened. Different processes are available for gas sweetening and are discussed later.
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Stabilization Dissolved gas in the crude oil must be removed to meet pipeline, storage, or Reid vapor
pressure (RVP) specifications. The presence of the most volatile hydrocarbons (C1, C2, C3…) increases the RVP dramatically. Removal of theses components is called crude oil stabilization. Stabilization can also sweeten the crude because the chief sulfur-containing or sour contaminant H2S, has a boiling point intermediate to that of ethane and propane. Crude oil can be stabilized by passing it through a series of flash drums or vapor-liquid separator vessels at successively lower pressures (multistage separation).
The last separator can be replaced by reboiled stabilizer column. Vapor, which is produced in the reboiler, flows up the column, stripping out the methane, ethane, propane and sufficient butanes to produce a stabilized crude oil. The separation obtained is much better than in a simple flash drum.
In the previous case, the produced gas is assumed to be flared or vented. No allowance is made for recompressing the gas. Current gas prices, energy conservation and environmental regulations usually prohibit such wasteful disposal of separator gas. The gas must be compressed and delivered to a pipeline or reinjected into the formation.
And the condensate may be transported separately by pipeline, tanker…; or, recycled to extinction by injecting back into separator feeds.
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Sweetening (Gas) It has been found that when gases contain significant quantities of hydrogen sulphide, carbon dioxide is often present as well. Hence sweetening is now used to refer to the removal of carbon dioxide as well as to the removal of sulphur compounds.
The primary element to be removed is H 2S on account of its toxic nature and its corrosive properties. It is a practice to use a specification of hydrogen sulphide of 4 ppm on a volume basis.
In addition to H2S, other sulphur compounds maybe present, such as mercaptans, carbonyl sulphide (COS), and disulphides. Typically, a requirement of not more than 40 ppm of total sulphur (including H2S) is laid down. In the presence of liquid water, hydrogen sulphide and carbon dioxide are highly corrosive, and removing these gases is a must otherwise expensive alloy steels are to be used for pipeline construction in cases where such gases are to be transported.
Many different sweetening processes are available. Theses processes can be broadly classified as follows:
• • • •
absorption by chemical solvents; absorption by physical solvents; adsorption; physical separation (for example using distillation or semi-permeable membranes).
Chemical solvents Processes using chemical solvents to remove acid gases have been in widespread use for many years. Alkanolamines or simply amines are mostly used with more stable and effective ones becoming available like: MEA, DEA), MDA and DIP A. These chemicals are used in water solutions. Therefore sweetening will precede dehydration in gas. The general principle of operation is that the inlet gas stream, at high pressure and slightly
elevated temperature (around 40 ˚C to 60 ˚C), passes up a contactor tower (also called an absorber) where it is contacted with the amine solution flowing down the tower. The amine reacts with the hydrogen sulphide and carbon dioxide present forming compounds (bisulphides and carbamates) which remain in the amine solution.
When this solution leaves the contactor, its pressure is reduced, it is heated by hot regenerated lean amine in the heat exchanger and by heat supplied from the reboiler in the regeneration still column. The steam rising through the still liberates H 2S and CO2 regenerating the amine.
Steam and acid gases separated from the rich amine are condensed and cooled, respectively, in the reflux condenser. Condensed steam is separated in the reflux accumulator and returned to the still. Acid gases are directed to a sulfur recovery system. Hot regenerated lean amine is cooled in a solvent aerial cooler and circulated to the contactor tower, completing the cycle.
Physical solvents Physical absorption processes make use of solvents that do not react chemically with the acid gases, but dissolve them at the high pressures used in the absorber (or contactor). The solution leaving the absorber is flashed to a lower pressure, and the dissolved gases then come out of solution, leaving a regenerated solvent for recycling. One disadvantage of physical absorption processes is that substantial amounts of hydrocarbons can be dissolved in the contactor by the solvent.
Adsorption Adsorption processes using molecular sieves can be useful in removing small amounts of acid gases (and water) from natural gas streams. Theses processes will only be cost effective when the concentration of the acid gas in the feed is less than about 1%.
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Sulphur Recovery When hydrogen sulphide removal is carried out, it is essential to have a further process step to deal with the hydrogen sulphide from the stripping step. The standard way of doing this is to convert hydrogen sulphide to elemental sulphur using the Claus process. The first step of this process is to feed the gas to a furnace in which it undergoes combustion with a limited supply of air so as to oxidize 1/3 of the hydrogen sulphide to sulphur dioxide at a temperature of around 1200 C. The hot gases leaving the furnace are cooled by using them to raise steam in a waste-heat boiler, and the sulphur dioxide produced, reacts with the remaining hydrogen sulphide in a series of convectors in the presence of a catalyst, producing sulphur, which condenses out and is removed. The resulting solid sulphur is a high-quality sealable product.
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Dehydration (Gas) Dehydration refers to the removal of water from natural gas. Natural gases are usually saturated with water vapor. The presence of hydrogen sulphide and carbon dioxide increases the amount of water in the saturated gas for given conditions of pressure and temperature.
The removal of water vapor from natural gas streams is carried out to prevent the formation of solid hydrates. Hydrates are ice–like solids, which can be formed by the lighter hydrocarbons gases (methane, ethane, propane, butanes) when in the presence of liquid water at hi gh pressures and sufficiently low temperatures.
Hydrates can form at temperatures well above the freezing point of water when the pressure is sufficiently high, and give rise to serious hazards in the production and transport of oil and gas. Hydrate formation has a tendency to occur in flowing streams just downstream of some partial obstruction such as a valve or choke, and once formation begins the quantity of hydrate can build up rapidly until the pipeline becomes completely blocked.
Precautions must be taken to eliminate the risk of hydrates forming. These precautions consist of ensuring that no liquid water can be present (in which case hydrates cannot form).
The following processes are available for gas dehydration:
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Refrigeration of the gas stream. As the temperature of the steam is reduced, liquid water will condense out and can be separated from the gas. Some liquid hydrocarbons will condense out at the same time and can also be separated. Refrigeration will therefore reduce both the water dew point and the hydrocarbon dew point of the gas stream;
•
Adsorption: contacting the gas with a suitable molecular sieve. The gas is packed through a tower packed with a suitable molecular sieve which adsorbs the water vapor. When the molecular sieve begins to lose its effectiveness, the tower is taken off stream and the sieve is regenerated by passing high temperature gas through it.
•
Glycol dehydration in which the gas is contacted with one of the glycols; these are liquid chemicals having a strong affinity for water. This is the most widely used method of dehydration in both onshore and offshore applications; an important advantage of this process is that the plant has a smaller footprint than the other alternatives. It is, however, not capable of achieving very low water contents; if these are required, adsorption must be used.
Glycol dehydration plant design and operation The rich glycol leaving the contactor is regenerated in the stripping column where the water boils off. A small amount of dehydrated gas product may be bled off to provide the stripping gas. Alternatively some of the plant fuel gas may be used for stripping.
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Condensate removal In addition to sweetening and dehydration, gas conditioning also include the removal of some of the heavier hydrocarbons from the gas stream to ensure that these do not condense out in the line and form liquid slugs.
The hydrocarbon dew point of natural gas (the temperature at which a liquid hydrocarbon phase will begin to separate out ) depends on the amounts of higher hydrocarbons present. To lower the dew point, it may be necessary to remove some of the higher hydrocarbons; this process is referred to as NGL extraction or condensate removal.
In modern practice, this extraction is done by the use of refrigeration to condense out the natural gas liquids at low temperature, and so reduce the hydrocarbon dew point. The refrigeration also condenses out some of the water present, and so contributes to dehydration of the gas.
When producing LNG, carbon dioxide content must also be reduced to a low level (less than about 100 ppm) for gas liquefaction, to avoid the risk of solid carbon dioxide forming in the plant heat exchangers at low temperatures and causing obstruction to the flow.
