SEPARATION OF OIL-WATER EMULSION Removing water from crude oil often requires additional processing beyond the normal gravity separation. Crude oil treating equipment is designed to break emulsions by coalescing the water droplets and then using gravity separation to separate the oil and water. In addition, the water droplets must have sufficient time to contact each other and coalesce. It is important when designing a crude oil treating system to take into account temperature, time, viscosity of the oil, which may inhibit settling, and the physical dimensions of the treating vessel, which determines the velocity at which settling must occur. A common method for separating “water-in-oil” emulsion is to heat the stream. Increasing the temperature of the two immiscible liquids deactivates the emulsifying agent, allowing the dispersed water droplets to collide. As the droplets collide they grow in size and begin to settle. If designed properly, the water will settle to the bottom of the treating vessel due to differences in specific gravity. The greater the difference in density between the oil and water phases, the easier the water droplets will settle.
Techniques
Gravity
Electrical
Chemical
Adding heat to the incoming oil –water stream is the traditional method of separating the phases. The addition of heat reduces the viscosity of the oil phase, allowing more rapid
settling velocities in accordance with Stokes’ law of settling. For some emulsifying agents, such as paraffins and asphaltenes, the addition of heat deactivates, or dissolves, the emulsifier and thus increases its solubility in the oil phase. Treating temperatures normally range from 100 to 160˚F (38– 70˚C). In treating of heavy crudes the temperature may be as high as 300 ˚F (150˚C).
Advantages of heating: 1. It reduces the viscosity of continuous oil phase, thus increasing settling rates. 2. It increases the Brownian motion and natural convection currents within the emulsion, thus increasing and intensifying drop collision. 3. It generates thermal currents, which promote uniform distribution of demulsifiers etc.
Disadvantages: 1. It drives some of the more volatile hydrocarbons out of the crude oil into the gas phase. 2. Costly due to flue price rise. 3. It is prone to hazard. 4. Coke deposition on fire tube may cause problems.
THE HEATER-TREATER
Heater-treaters are used for removing water from the oil and emulsion being treated. They are less expensive initially, offer lower installation costs, provide greater heat efficiency, provide greater flexibility, and experience greater overall efficiency as compared to other treaters. On the other hand, they are more complicated, provide less storage space for basic sediment, and are more sensitive to chemicals. Since heater-treaters are smaller than other treating vessels, their retention times are minimal (10 to 30 min) when compared to gun barrels and horizontal flow treaters. Internal corrosion of the down-comer pipe is a common problem.
How it works? Oil with emulsified water, solids and gas from the upstream separation process enters the crude oil treater near the top of the vessel, in the gas separation section. This section is isolated from the oil treating section with a full-diameter baffle. An inlet flow diverter causes a rapid separation of gas and liquid. Gas exits through the gas outlet at the top of the vessel, and liquids flow through a down comer into the treating section of the vessel. The treating section of the vessel is equipped with a fire tube to heat the oil/water/solids mixture. A gas flame heats the fire tube, which transfers heat to the surrounding liquid. Heat reduces the viscosity of the oil and accelerates gravity separation of water droplets and solid particles from the oil. Under the force of gravity, water and solids settle to the bottom of the treating section, while oil and liberated gas rise to the top. Gas, liberated by heating the oil, passes into the gas separation section via an equalizer tube, and then exits through the gas outlet. Dehydrated, degassed oil rises to the oil outlet and exits the treater through the oil outlet piping and a mechanical level control. Water falls into the bottom of the vessel, then exits through the water outlet and an external water siphon.
Vertical Heater Treaters: It is the most commonly used single well heater treater. The vertical heater-treater consists of four major sections: gas separation, free-water knockout, heating and water wash, and coalescing-settling sections. Incoming fluid enters the top of the treater into a gas separation section, where gas separates from the liquid and leaves through the gas line. The liquids flow through a down-comer to the base of the treater, which serves as a free-water knockout section. The end of the down-comer should be slightly below the oil–water interface so as to “water-wash” the oil being treated. This will assist in the coalescence of water droplets in the oil. The oil and emulsion rise through the heating and water-wash section, where the fluid is heated. A fire tube is commonly used to heat the emulsion in the heating and waterwash section. After the oil and emulsion are heated, the heated oil and emulsion enter the coalescing section, where sufficient retention time is provided to allow the small water droplets in the oil continuous phase to coalesce and settle to the bottom.
Treated oil flows out the oil outlet, at the top of the coalescing section, and through the oil leg heat exchanger, where a valve controls the flow. Heated clean oil preheats incoming cooler emulsion in the oil leg heat exchanger. Separated water flows out through the water leg, where a control valve controls the flow to the water treating system. The gas liberated when crude oil is heated may create a problem in the treater if it is not adequately designed. In vertical heater-treaters the gas rises through the coalescing
section. If a great deal of gas is liberated, it can create enough turbulence and disturbance to inhibit coalescence.
Horizontal Heater Treaters: The horizontal heater-treater consists of three major sections: front, oil surge chamber, and coalescing sections. Incoming fluids enter the front section through the fluid inlet and down over the deflector hood where gas is flashed and removed. Heavier materials flow to the bottom while lighter materials flow to the top. Free gas breaks out and passes through the gas equalizer loop to the gas outlet. The oil, emulsion, and free water pass around the deflector hood to the spreader located slightly below the oil –water interface, where the liquid is “water-washed” and the free water is separated. The oil and emulsion are heated as they rise past the fire tubes and are skimmed into the oil surge chamber.
A level safety low shutdown sensor is required in the upper portion of the front section. This sensor assures liquid is always above the fire tube. If the water dump valve malfunctions or fails open, the liquid surrounding the fire tube will drop, thus not absorbing the heat generated from the fire tube and possibly damaging the fire tube by overheating.
The oil and emulsion flow through a spreader into the back or coalescing section of the vessel, which is fluid packed. The spreader distributes the flow evenly throughout the length of this section. Because it is lighter than the emulsion and water, treated oil rises to the clean oil collector, where it is collected and flows to the clean oil outlet. The coalescing section must be sized to provide adequate retention time for coalescing to occur and to allow the coalescing water droplets to settle downward counter current to the upward flow of the oil.
PROCESS DESCRIPTION
Gathering system:
It consists primarily of pipes, valves and fittings necessary to connect the wellhead to the separations equipment. Accessory items include: Gross production meters o Automatic well test units o o Corrosion inhibitors o Chemical injection equipment Oil well steam injection facilities have been installed in a no. of low gravity oilfields to simulate oil production.
Development of oil well steam injection procedures has added to the complexity of some field gathering systems; however, new development facilities, although more complex, often tend to simplify the overall design for good continuity and operation. Oil well stem injection facilities have been installed in a number of low-gravity oilfields to stimulate oil production. Steam simulation in several installations, increased the net oil production of an existing well up to ten times the production prior to steaming operations and created new well drilling activity in many existing fields. The line to each well from oil production-steam injection manifold is often a dual purpose line used for steaming the well for a certain period of time. In this case, the oil production returns through the same line to the manifold, where the production is then routed to the group header. The manifold may contain twenty or more wells, each of which can be designed with automatic diverter valves in order to:
Direct the flow of an unit Return the flow to an automatic well test unit Return the flow to the main group header After a purge period, program the next well for testing, etc.
Separation Section: Heating water requires about twice as much energy as it does to heat oil. For this reason, it is beneficial to separate any free water from the emulsion to be treated with either a free-water knockout located upstream of the treater or an inlet free-water knockout system in the treater itself. The major difference between a conventional three-phase separator and an FWKO is that in the latter there are only two fluid outlets; one for oil and very small amounts of gas and the second for the water. FWKOs are usually operated as packed vessels. Water outflow is usually controlled with an interface level control.
Treating section: The treating section consists of some method of dehydration, such as using wash tanks, heater treaters, or electric dehydrators. The principal purpose of the treating section is to remove water, sand and other contaminants from the oil. In most cases, the waste water must be cleaned to meet the requirements of the local water quality board. Often the water is processed for water flood applications or for reuse as steam generator feed water in some locations where the water has proper chemical composition and properties. Oil enters the treating section from the separators, where it has been essentially degassed, and flows to the dehydration equipment. Dehydration may be accomplished by one or a combination of several methods ranging from simple tank settling to complex methods. In general, dehydration equipment can be divided into three classes: gravity, electrical and chemical or combination thereof.
Storage Shipping Section: After heat and chemical treating, pure crude oil is sent to the storage tanks where it is kept for inventory and then further to pipelines and LACT units. A Lease Automatic Custody Transfer unit or LACT unit measures the net volume and quality of liquid hydrocarbons. A LACT unit measures volumes in the range of 1001000 BOPD. This system provides for the automatic measurement, sampling, and transfer of oil from the lease location into a pipeline. A system of this type is applicable where larger volumes of oil are being produced and must have a pipeline available in which to connect
DESIGN PROCEDURE
In specifying the size of a treater, it is necessary to determine the diameter (d), length or height of the coalescing section (L_eff or h), and treating temperature or fire-tube rating. These variables are interdependent, and it is not possible to arrive at a unique solution for each. The design engineer must trade the cost of increased geometry against the savings from reducing the treating temperature. Because of the empirical nature of some of the underlying assumptions, engineering judgment must be utilized in selecting the size of treater to use.
General Design Procedure: 1. Choose a treating temperature. 2. Determine the heat input required from the following:
Where, q = heat input, BTU/hr (kW), Qo= oil flow rate, BOPD (m 3 /hr), ∆T = increase in temperature, ˚F(˚C), SGo= specific gravity of oil relative to water Derivation: The general heat transfer equation is expressed by: q=WC∆T
Where, q = heat (kW), W = flow rate (kg/hr) C = specific heat (approximately 0.5 for oil and 1.0 for water) (J/kg _ C), ∆T = temperature increase, ˚C
Water weighs 1000 kg/m 3 W = 1000(SG) lQ,
where SGl= specific gravity of the liquid, Ql= liquid flow rate, m3/hr.
The total energy required is determined from
q = qo+qw+qlost _
where q = total energy required to heat the stream, qo= energy required to heat the oil = [(1000) (SG)oQo] (0.5) ∆T, qw= energy required to heat the water = [(1000) (SG)wQw] (1.0)∆T, qlost= energy lost to surroundings, assume 10% of total heat input (q).
Substituting gives us q =(1000)[(SG)oQo](0.5)+(SG)wQw]∆T +(0.1)q Assume 10% water and specific gravity water = 1: q = 1100Qo∆T[0.5(SG)o+ (0.1)]
3. Determine oil viscosity at treating temperature. In the absence of laboratory data, following figure provides correlations that can be used to estimate crude viscosity given its gravity and temperature.
4. Select a type of treater, and size the treater using the appropriate design procedure below. 5. Choose the design minimum droplet size that must be separated from experimental data, analogy to other treaters in service from the following equations: dmi% = 200µ0.25,
µo < 80 cp_
where dmi% = diameter of water droplet to be settled from the oil to achieve 1% water cut, microns, µ = viscosity of the oil phase, cp.
6. Repeat the above procedure for different treating temperatures.
