Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information
PEH:Water-Treating Facilities in Oil and Gas Operations
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume III – Facilities and Construction Engineering
Kenneth E. Arnold, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 4 – Water-Treating Facilities in Oil and Gas Operations
Multiple types and sources of water streams are encountered in oil and gas operations; the two primary ones are produced and surface water. Produced water is the brine that comes from the oil reservoir with the produced fluids; surface water encompasses fresh (river or lake) and saline (seawater) sources.
Water sources are treated for disposal, injection as a liquid, or injection as steam with three types of facilities. Produced water is treated in offshore operations for overboard disposal or injection into a disposal well, but when onshore, it is treated for surface disposal, liquid injection, or steam injection. In all instances, the produced water must be cleaned of dispersed and dissolved oil and solids to a level suitable for environmental, reservoir, or steam-generation purposes. Surface water is treated offshore for liquid injection and onshore for liquid- or steam-injection purposes. In all instances, the surface water must be cleaned of dispersed and dissolved solids to a level suitable for reservoir or steam-generation purposes.
In oil-producing operations, it is often desirable to inject water or steam into the formation to improve oil recovery. Water injection for this purpose is called a waterflood; when properly implemented, it will maintain reservoir pressure and significantly improve the oil recovery vs. primary production. Steam injection, known as a steamflood, will reduce the viscosity of oil and further enhance the oil recovery. See the chapter on Steam Injection in the Reservoir Engineering and Petrophysics volume of this Handbook.
In offshore areas, governing regulations specify the maximum hydrocarbon and solids content in the water allowed in overboard discharges. Some studies have estimated that during the life of a well, 4 to 5 bbl of water are produced for every barrel of oil, making this fluid the largest volume of produced product in the oil and gas industry.
This chapter discusses the equipment and design criteria used in common water-treatment systems for disposal or injection. In addition to the removal of dispersed or dissolved hydrocarbons and solids, the water-treatment engineer may be concerned with chemical treatment, material selection, and solids disposal, which are also covered.
Produced-Water Discharge or (Steam) Injection
Separating Free Hydrocarbons From Water
Produced water typically enters the water-treatment system from a two- or three-phase separator, free-water knockout, gun barrel, heater treater, or other primary-separation-unit process. This water contains small concentrations (100 to 2000 mg/L) of dispersed hydrocarbons in the form of oil droplets. Because the water flows from this equipment through dump valves, control valves, chokes, or pumps, the oil-particle diameters will be very small (< 100 μm).
Theory. Treatment equipment to remove dispersed oil from water relies on one or more of the following principles: gravity separation (often with the addition of coalescing devices), gas flotation, cyclonic separation, filtration, and centrifuge separation. In applying these concepts, one must keep in mind the dispersion of large oil droplets to smaller ones and the coalescence of small droplets into larger ones, which takes place if energy is added to the system. The amount of energy added per unit time and the way in which it is added will determine whether dispersion or coalescence will take place.
Gravity Separation. Stokes’ law, shown in Eq. 4.1, is valid for the buoyant rise velocity of an oil droplet in a water-continuous phase.
where v = velocity of the droplet or particle rising or settling in a continuous phase, cm/s; Δρ = difference in density of the dispersed particle and the continuous phase, g/cm3; gc = gravity acceleration constant, cm/s2; dp = dispersed particle diameter, cm; and μL = viscosity of the continuous phase (liquid), g/cm•s.
Several immediate conclusions can be drawn from this equation.
- The larger the diameter of an oil droplet, the greater its vertical velocity; that is, the bigger the droplet size, the less time it takes to rise to a collection surface and, thus, the easier it is to treat the water.
- The greater the difference in density between the oil droplet and the water phase, the greater the vertical velocity; that is, the lighter the crude, the easier it is to treat the water.
- The higher the temperature, the lower the viscosity of the water and, thus, the greater the vertical velocity; that is, it is easier to treat the water at high temperatures than at low temperatures.
- Increasing the g-force imposed on the fluid (i.e., by centrifugal motion) will greatly increase the separation velocity.
The third conclusion requires further elaboration. Heat is the primary mechanism in oil-treating equipment to remove small water droplets from oil. The addition of heat significantly reduces oil viscosity, which prompts more rapid settling, and heat destabilizes water-in-oil emulsions. Heat is not commonly used in water treating because the percentage change in viscosity per degree of temperature change is much less in water than in oil. Water-in-oil emulsions tend to have a higher percentage of the dispersed phase than the oil-in-water emulsions; the dispersed phase tends to have larger-diameter droplets stabilized by heat-sensitive emulsifiers, and it takes twice as much heat input to raise a barrel of water as it takes to raise a barrel of oil to the same temperature.
Dispersion. Small oil droplets contained in the water-continuous phase are subject to the competing forces of dispersion and coalescence. An oil droplet will break apart when kinetic-energy input is sufficient to overcome the surface energy between the single droplet and the two smaller droplets formed from it. At the same time that this process occurs, the motion and collision of oil particles cause coalescence to take place. Therefore, it should be possible to define statistically a maximum droplet size for a given energy input per unit mass and the time at which the rate of coalescence equals the rate of dispersion.
Eq. 4.2 provides one relationship for the maximum particle size that can exist at equilibrium.
where dmax = diameter of the droplet above which only 5% of the oil volume is contained, σ = surface tension, ρw = density, Δp = pressure drop, and tr = retention time.
The greater the pressure drop (and, thus, the shear forces that the fluid experiences in a given time period), the smaller the oil droplets will be. Large pressure drops, which occur in small distances through chokes, control valves, and instruments, result in small oil droplets and water that is harder to treat. A pressure drop of 50 to 75 psi will result in a maximum particle size of 10 to 50 μm.
Theoretically, the dispersion process is not instantaneous; however, from field experience, it appears to take place very rapidly. For conservative design purposes, it could be assumed that whenever large pressure drops occur, all droplets will disperse instantaneously.
Coalescence. Within water-treatment equipment, in which the energy input to the fluid is very small, the process of coalescence takes place; that is, small oil droplets collide and form bigger droplets. Because of the low energy input, these are not dispersed.
Coalescence can also occur in the pipe downstream of pumps and control valves. However, in such instances, the process of dispersion will govern the maximum size of stable oil droplets that can exist. For normal pipe diameters and flow velocities, particles of 500 to 5000 μm are possible.
The process of coalescence in water-treatment systems appears to be more time-dependent than the process of dispersion. When two oil droplets collide, contact can be broken before coalescence is completed because of turbulent pressure fluctuations and the kinetic energy of the oscillating droplets.
The time required to "grow" a large droplet from a relatively small droplet in a "quiet" gravity-settling tank is approximated by Eq. 4.3.
where dd = droplet diameter, fV = volume fraction of the dispersed phase, and Ks = empirical settling constant. While it is very difficult to determine Ks for an actual installation, the following qualitative conclusions can be drawn:
- A doubling of the residence time will cause an increase in droplet diameter of only 19%.
- The more dilute the dispersed phase, the greater the residence time needed to grow a given particle size (that is, coalescence occurs more rapidly in concentrated dispersions).
The addition of surfactant chemicals to the water stream can modify the surface tension of the oil droplets to aid in coalescence.
Gravity-Separation DevicesWater-treating equipment that makes use of gravity separation includes skim tanks, API separators, plate coalescers, and skim piles. These devices are very simple and inexpensive; however, because of the large residence times necessary for separation, they are heavy and require large footprints. These devices are commonly used on both land-based and offshore fixed-structure facilities; however, they are motion-sensitive and find limited use on floating facilities.
It is necessary to know both the oil concentration in the influent water and the particle-size distribution to properly design a gravity separator to meet a certain effluent quality. This information can be determined accurately only by sampling the treated water stream. Laboratory testing can provide indicative data for scaleup and correlation, while curves, such as those shown in Fig. 4.1, can provide an initial estimate from which to work. These data will vary with the oil and water properties and process conditions.
Skim Tanks and Vessels. The simplest form of treatment equipment is a skim tank or pressure vessel. These are normally designed to provide large residence times during which coalescence and gravity separation can occur. They can be either pressure vessels or atmospheric tanks.
Skim tanks can be either vertical or horizontal in configuration. They may be set up for vertical downward flow of water with or without inlet spreaders or outlet collectors. They may also be designed as horizontal vessels in which the water enters on one side and flows over a weir on the far end.
In vertical vessels, the oil droplets must flow upward against the downward velocity of the water. For this reason, horizontal vessels are more efficient in gravity separation of the two liquid phases. In spite of this, vertical vessels and tanks are sometimes used for the following two reasons:
- Sand and other solids particles can be handled more easily in vertical vessels with either a water outlet or a sand drain off the bottom.
- Vertical vessels are less susceptible to high-level shutdowns caused by liquid surges. Internal waves resulting from surging in horizontal vessels can trigger a level float even though the volume of liquid between the normal operating level and the high-level shutdown is equal to or larger than that in a vertical vessel.
Tracer studies have shown that large skim tanks, even those with carefully designed spreaders and baffles, exhibit poor flow behavior and short circuiting. This is probably caused by such factors as density and temperature differences, deposition of solids, corrosion of spreaders, and flow dynamics. In one case, a tank with a design mean residence time of 33 hours had a breakthrough of the tracer with a peak within minutes of tracer injection.
As discussed previously, providing residence time to allow for coalescence does not appear to be cost-efficient. However, a minimum residence time of 10 minutes to 1 hour should be provided to ensure that surges do not upset the system and to provide for some coalescence.
Horizontal Pressure Vessel Sizing. The required diameter and length of a horizontal cylinder operating half full of water can be determined by the following equation:
where di = vessel internal diameter (ID), qw = water flow rate, μw = water viscosity, dd =oil-droplet diameter, Le = effective length in which separation occurs (for design use of 75% seam-to-seam length), and Δγow = difference in specific gravity between oil and water.
While Eq. 4.4 will govern the design, it is also necessary to check for adequate retention time.
where tr = retention time.
Vertical Cylindrical Vessel. The required diameter of a vertical cylindrical pressure vessel or tank can be determined from
where F = a factor to account for turbulence and short circuiting. For small-diameter vessels (48 in. or less), F = 1.0. For larger diameters, F depends on the type of inlet and outlet spreaders, collectors, and baffles that are provided. Large tanks (10 ft or more in diameter) should be considered to have an F > 2.0, depending on the inlet and outlet conditions.
The height of the water column can be determined from retention-time requirements as follows:
where Zw = the height of the water column.
API Separators. An API separator is the name given to a horizontal, rectangular cross-section, atmospheric oil skimmer that follows the sizing equations and guidelines included in the API Manual on Disposal of Refinery Wastes. Fig. 4.2 shows a typical API separator [available in printed volume; not included here because API did not grant permission for its use in PetroWiki]. The equations for sizing and their derivations are discussed in the Solids-Settling section of this chapter. API separators find limited use in offshore facilities because of their large size.
Plate Coalescers. Various configurations of plate coalescers, commonly called parallel plate interceptors (PPI), corrugated plate interceptors (CPI), or crossflow separators, have been devised. These coalescers depend on gravity separation to allow the oil droplets to rise to a plate surface, where coalescence and capture occur. Flow is split among a number of parallel plates spaced a short distance apart. To facilitate capture of the oil particles, the plates are inclined horizontally.
As shown in Fig. 4.3, an oil droplet entering the space between the plates will rise in accordance with Stokes’ law; at the same time, it will have a forward velocity equal to the bulk water velocity. By solving for the vertical velocity that a particle entering at the base of the flow needs to reach the coalescing plate at the top of the flow, the resulting droplet diameter can be determined. A restriction is placed on the Reynolds number for the water to ensure that turbulence in this flow does not affect the oil layer on the coalescing plate.
General Sizing Equation. For a plate coalescer with flow either parallel or perpendicular to the direction of flow, the general sizing equation for the droplet-size removal is
where dd = design oil-droplet diameter, qw = bulk water flow rate, Lp = perpendicular distance between plates, μw = water viscosity, θ = angle of the plate with the horizontal, Zp = height of the plate section perpendicular to the axis of water flow, Bp = width of the plate section perpendicular to the axis of water flow, L = length of plate section parallel to the axis of water flow, and Δγow = difference in specific gravity between oil and water. Experiments have indicated that on the basis of the hydraulic radius as the characteristic dimension, the Reynolds number for the flow regime cannot exceed 400. Thus, the maximum flow rate is given by
PPI. The first form of plate coalescers was the PPI. This involved installing a series of plates parallel to the longitudinal axis of an API separator (a horizontal, rectangular cross-sectioned skimmer). The plates form a V when viewed perpendicular to the flow axis so that the oil sheet migrates up the underside of the coalescing plate and to the sides. Sediments migrate toward the middle and down to the bottom of the separator, where they are removed.
CPI. The most common PPI form used in production facilities is the CPI. This is a refinement of the PPI in that it takes up less platform space (length) for the same particle-size removal and has the added benefit of making sediment handling easier. Fig. 4.4 is a typical design with a corrugated plate.
In CPIs, the parallel plates are corrugated (like roofing material), with the axis of the corrugations inclined to an angle of 45°. The bulk water flow is forced downward; the oil sheet raises upward counter to the water flow and is concentrated in the top of each corrugation. When the oil reaches the end of the plate pack, it is collected in a vertical channel and brought to the oil/water interface. CPIs require frequent cleaning of the plate packs in which large amounts of sediment are handled.
Crossflow Devices. CPI configurations are available for horizontal water flow perpendicular to the axis of the corrugations in the plates. This allows the plates to be put on a steeper angle to facilitate sediment removal and to enable the plate pack to be packaged more conveniently in a pressure vessel. The latter benefit may be required if gas blowby through an upstream dump valve could cause relief problems with an atmospheric tank (see the discussion on gas blowby in the Safety Systems chapter in this section of the Handbook).
Crossflow devices can be constructed in either horizontal or vertical pressure vessels. The horizontal vessels require less internal baffling because the ends of nearly every plate conduct the oil directly to the oil/water interface and the sediments to the sediment area below the water flow. The vertical units, although requiring collection channels on one end to enable the oil to rise to the oil/water interface and on the other end to allow the sand to settle to the bottom, can be designed for more efficient sand removal. Crossflow separators are used where sand is a considerable problem and are not removed in the process upstream of the CPI.
Practical Limitations. Stokes’ law theory should apply to oil droplets as small in diameter as 1 to 10 μm. However, field experience indicates that 30 μm sets a reasonable lower limit on the droplet sizes that can be removed. At less than this size, small pressure fluctuations and platform vibrations tend to impede the rise of droplets to the coalescing surface; thus, the practical limit for sizing-plate coalescers is 30-μm removal.
Skim Pile. Skim piles are gravity water-treating devices used offshore. As shown in Fig. 4.5, flow through the multiple series of baffle plates creates quiescent zones that reduce the distance a given oil droplet must rise to be separated from the main flow.
Once in the quiescent zone, there is plenty of time for coalescence and gravity separation. The larger droplets then migrate up the underside of the baffle to an oil-collection system. Skim piles are used extensively to treat deck drainage of washdown or rainwater that has been contaminated with oil. They have the added benefit of providing some degree of sand cleaning. Sand traversing the length of a skim pile will abrade on the baffles and be water washed. This removes the free oil, which is then captured in the quiescent zone.
Skim Pile Sizing-Deck Drainage. Field experience has indicated that acceptable effluent is obtained with 20 minutes of retention time in the baffled section of the pile. Using this and assuming that 25% of the volume is taken up by the coalescing zones, 
where di = pile internal diameter; Lbs = length of baffle section; qw = produced-water rate if it is disposed in pile, B/D; Ad = deck area; qr = rainfall rate; and qWD = washdown rate.
Intermittent Flow. During periods of no flow, oil droplets rise to the area of the quiescent zone and become trapped and protected from being swept back into the flow stream when flow is resumed. The net effect of the baffles is to reduce this rise distance. Each time that flow is stopped as the water traverses the baffled section, more oil particles are trapped in the quiescent zone.
This phenomenon can be used when a skim pile is used downstream of a skim tank or CPI for further treating. With a snap-acting water dump on the influent, intermittent flow is established in the pile.
If t = the time in seconds for the dump cycle,
where Nc = the number of nonflow cycles that a particle sees as it traverses the baffle section.
If tc = the time the valves are closed, the removal efficiency on any cycle of a particular drop size is
The overall removal efficiency of that particle size can then be determined by
Gas Flotation UnitsFlotation units do not rely on gravity forces for separating the oil droplets; in fact, the action of these units is independent of the oil-droplet size. In gas flotation units, large quantities of small-diameter gas bubbles are injected into the water stream. The bubbles attach to the oil droplets suspended in the stream, causing them to rise to the water surface and form a froth layer. Experimental results have shown that very-small-diameter oil droplets in dilute suspensions can be removed easily by flotation. High percentages of oil removal are achieved.
Two distinct types of flotation units have been used, distinguished by the method employed in distributing small gas bubbles throughout the water. These are dissolved- and dispersed-gas units.
Dissolved-Gas Units. Dissolved-gas designs take a portion of the treated water effluent and saturate the water with natural gas or air in a contactor. The higher the pressure, the more gas that can be dissolved in the water. However, most units are designed for a contact pressure of 20 to 40 psig. Normally, 20 to 50% of the treated water is recirculated for contact with the gas.
The gas-saturated water is then injected into the flotation chamber, as shown in Fig. 4.6. [Figure available in printed volume; removed here because API did not grant permission for its use in PetroWiki.] The dissolved gas breaks out of solution in small-diameter bubbles when the flow enters the chamber, which is operated at near-atmospheric pressure.
Design parameters are recommended by the individual manufacturers but normally range from 0.2 to 0.5 scf/bbl of water to be treated and flow rates of treated plus recycled water of between 2 and 4 gal/min-ft2. Retention times of 10 to 40 minutes and depths of between 6 and 9 ft are specified.
Dissolved-gas units have been used successfully in refinery operations in which air can be used as the gas and where large areas are available. In treating produced water for injection, it is desirable to use natural gas to exclude oxygen. This requires venting the gas or installing a vapor-recovery unit. Field experience with dissolved-natural-gas units has not been as successful as experience with dispersed-gas units.
Dispersed-Gas Units. In dispersed-gas units, gas bubbles are dispersed in the total stream either by use of an inductor device or by a vortex set up by mechanical rotors. Fig. 4.7 shows a schematic cross section of such a unit.
Most dispersed-gas units contain three or four cells. Bulk water flow moves in series from one cell to the other by underflow baffles. Field tests have indicated that the high intensity of mixing in each cell creates the effect of plug flow of the bulk water from one cell to the next; that is, there is virtually no short circuiting or breakthrough of a part of the inlet flow to the outlet weir box.
Efficient design of a dispersed-gas unit requires a high gas-induction rate, a small-diameter induced-gas bubble, and a relatively large mixing zone. Thus, the design of the rotor and internal baffles is critical to the unit efficiency. Field tests and theory both indicate that these units operate on a constant percent-removal basis. Within normal ranges, their oil-removal efficiency is independent of inlet concentration or oil-droplet diameter.
There are many different proprietary designs on the market. The most common designs have three to five separate cells in which gas is induced into the water stream. Each cell is designed for an approximately 1-minute retention time to allow the gas bubbles to break free of the liquid and form the froth at the surface. Field experiments show that the designs can remove 50% of the oil in each cell. From Eq. 4.13, a three-cell unit is expected to have an overall efficiency of 87%, and a four-cell unit should have an efficiency of 94%. In practice, the typical efficiency of an installed four-cell unit is only approximately 90%.
Because the unit recycles the gas, a natural-gas blanket can be maintained easily with little or no venting. The low required retention times make this an ideal choice for offshore facilities, where space and weight are at a premium. However, in motion-sensitive installations, sloshing within each cell degrades the performance of the flotation cell.
Deoiling HydrocyclonesDeoiling hydrocyclones, or "deoilers," provide the highest throughput-to-size ratio of any water-treating technology and are insensitive to motion or orientation. For a given capacity of water to be treated, deoilers will provide the smallest footprint and size of any water-treating technology. Deoilers use fluid-pressure energy to create rotational fluid motion, as shown in Fig. 4.8. This rotational motion causes relative movement of materials suspended in the fluid, thus permitting separation of these materials, one from another or from the fluid. In the case of produced-water deoiling, this process can remove small oil droplets from the water stream.
To obtain maximum benefits from a hydrocyclone system, it must be understood that the system must be incorporated differently into the overall process. Because hydrocyclones are pressure driven, they ideally should be located as close as possible to the oily water outlet of the three-phase separator. This location results in the simplest and most cost-effective installation with minimum operating cost. At the highest-pressure location in the process, the hydrocyclone will have maximum capacity because there is maximum pressure available. Furthermore, installing the hydrocyclones in this manner will return the best separation performance because the oily water has not yet been exposed to droplet-shearing pressure drops across level control valves.
An added advantage of deoiling hydrocyclones is the simplicity of their control systems, which normally use the standard interface-level control system of the three-phase separator, as shown in Fig. 4.9. The hydrocyclones are simply installed on the water outlet of the three-phase separator with the interface-level control valve downstream of the hydrocyclones on their water outlet. This control valve normally will control the flow rate through the deoiler in a proportional control mode. On/off control can be used for very low flow rates but is generally not recommended. In on/off control, there will be a surge of untreated water when the valve is first opened, until the flow stabilizes and there is adequate pressure drop through the hydrocyclone.
The overflow can be controlled by installing a valve on the overflow line that operates in parallel with the interface-level control valve or by using a simple pressure-control system that ensures a constant overflow rate, as shown in Fig. 4.9. This latter control system is referred to as the pressure-ratio control because it keeps a constant ratio between the two pressure drops in the deoiler: the inlet-to-overflow pressure drop and the inlet-to-underflow pressure drop.
If the existing process pressure is less than 25 psig, it is recommended to boost the pressure by pumping the water to the hydrocyclone system. It is imperative that strict guidelines are followed when designing a pumped hydrocyclone system. Pump selection and operation are critical because the wrong pump type, or even the correct pump type operated incorrectly, can introduce considerable droplet shear.
Low-shear pumps provide the best performance in this application. Positive-displacement pumps can be low shear if they are equipped with low-shear check valves, as in the case of reciprocating pumps. Progressing cavity pumps can be excellent low-shear pumps, but they may require more maintenance than is acceptable. Centrifugal pumps are not typically low-shear ones, but some standard centrifugal pumps can be used very effectively for low-shear service. Because of their simplicity, reliability, and relatively low cost, centrifugal pumps are the recommended pumps to feed hydrocyclone systems.
When selecting a centrifugal pump for a deoiler system, almost any brand can be used as long as the following are observed.
- The pump is of closed impeller design.
- Pump operation is near the maximum on the efficiency curve (at least 70%).
- Maximum speed is 1,750 rpm.
- Maximum pressure boost per stage is 75 psi.
Pumps should be controlled by either a recycle loop or a variable-speed control, with the latter typically being more costly. Recycle control is the simplest way of preventing deadhead. The easiest method is for the pump to feed the hydrocyclones directly with the level-control valve from the source vessel located at the water discharge from the hydrocyclone.
CentrifugesDisc-stack centrifuges for produced-water cleanup have been in use for the past 10 years. They are used primarily for difficult applications to remove very small droplets of oil and for cases in which the fine-oil droplets do not coalesce easily. The disk-stack centrifuge consists of a frame, drive motor, transmission, separator bowl, and inlet/outlet arrangements, as shown in Fig. 4.10. The separation process takes place inside the rotating bowl at up to 6,000 g-forces. Produced water is introduced in the center of the bowl through the feed pipe and is accelerated to full rotational speed. The bowl is fitted with special inserts, which shorten the settling distance for oil droplets to 0.5 mm. The annular channels can be regarded as parallel separation vessels. The oil flows toward the center of the bowl against the upper side of the disc. Water and sediment flow outward against the underside of the disc. Disc-stack centrifuges can effectively remove oil droplets as small as 1 to 2 μm, and units are available at 15,000 B/D capacity each.
Walnut-Shell FiltersMedia-type filters, covered later in this chapter, are used for removal of fine solids from water. A specific type of media filter that uses walnut shells is used specifically for removing residual dispersed hydrocarbons from produced water. This type of filter is shown in Fig. 4.11.
Besides the media type, walnut-shell filters differ from sand filters in the method of backwashing. Recent improvements include the use of mechanical agitation or walnut-shell recirculation in the backwash cycles. The induced shearing or rubbing action removes most of the oil and solids from the walnut shells. Because of the effective oil- and solid-removal procedure, the use of surfactant chemicals generally has been eliminated. Another important improvement is that the walnut-shell filters have significantly reduced the waste volume to approximately 1% of the total throughput. This relatively small amount of backwash waste has made it possible for offshore application, where space for a waste-handling system is limited.
In low-temperature applications, heavy crude may be difficult to remove during the backwash cycle. Chemicals or heat are often required to clean the walnut shells before their reuse. In a steamflood field, the produced water is generally warm or hot, and a chemical or warm-water wash may not be required. For the previous reasons, walnut-shell filters have grown in acceptance with steamflood fields.
Removing Dissolved Hydrocarbons From WaterAs mentioned previously, when oil is produced from underground formations, water is also produced. In fact, the amount of water that comes to the surface will, with time, exceed the amount of oil. Because the produced water stream is considered a waste product, it is more economical for offshore operators to dispose of produced water near the producing platform in the ocean. It should be noted that dissolved or water-soluble hydrocarbons are present in all produced-water streams. The amount of water-soluble hydrocarbons varies depending on the properties of the hydrocarbon, the operating conditions (particularly temperature and pressure), the reservoir characteristics, and other factors. It also should be noted that other kinds of dissolved organic matter are present in produced water. In general, water-soluble organic matter falls into one of the following classes: aliphatic hydrocarbons; phenols; organic acids; and aromatic compounds, such as benzene and toluene.
Hydrocarbon discharges are, in most cases, regulated by a government agency such as the U.S. Environmental Protection Agency (EPA). The goal of these regulatory bodies is to minimize the impact that produced-water discharges have on the local environment. Therefore, the EPA and other regulatory bodies around the world set limits for the amount of total hydrocarbons, or "oil and grease," contained in the produced water discharged from offshore platforms. These limits usually are expressed in terms of milligrams per liter (mg/L) of the contaminant in the disposal stream. The EPA currently sets the limit of oil and grease in water discharged into federally regulated areas of the Gulf of Mexico at 42 mg/L daily maximum and 29 mg/L monthly average, per Natl. Discharge Pollution Elimination System (NPDES) General Permit #28000. Research into the environmental impact (toxicity) of dissolved hydrocarbons concludes that discharges into a body of water from responsibly operated facilities will have a negligible environmental impact. This conclusion is based on research showing that low levels of dissolved hydrocarbons are assimilated quickly into the ecosystem of the receiving body. Furthermore, responsibly operated facilities provide means for the contaminants in produced water to be diluted quickly to levels well within toxicity limits. As an example, discharged water from a North Sea platform is diluted between 50 and 400 times within 40 to 70 seconds after discharge.
The measurement of oil and grease must be considered to understand the criteria for determining whether removal of dissolved hydrocarbon material is necessary. Using the EPA as an example, the current EPA-approved measurement techniques are EPA Method 413.1 or 1664. Both methods are gravimetric—Method 413.1 uses freon as a solvent, and Method 1664 uses n -hexane. These methods involve pH reduction to less than 2 (to precipitate the dissolved hydrocarbons), extraction of the dispersed and dissolved components from the produced water with the solvent, extract separation, and solvent vaporization, leaving a residue considered to be the "oil and grease" component. However, there are two reasons that these methods do not accurately measure the total amount of hydrocarbons in the produced water. First, the solvent removes not only the dispersed and dissolved hydrocarbons but also the nonhydrocarbon organic matter, such as phenols, organic acids, alcohols, and ketones. Second, during the evaporation step of the measurement technique, low-molecular-weight volatile hydrocarbons [alkanes and aromatic hydrocarbons, such as benzene, toluene, ethylbenzene and xylenes (BTEX)] flash off. Hence, "oil and grease," as defined by the EPA measurement techniques, excludes some hydrocarbon components from vaporization and includes some nonhydrocarbon components from extraction by a nonselective solvent.
It is apparent that for an offshore oilfield operator to meet the federally imposed discharge limits, most of the dispersed oil will have to be removed before the discharge point. The foregoing discussion in "Separating Free Hydrocarbons From Water" contains a review of the types of equipment and processes commonly used to remove the dispersed-oil constituents. Furthermore, if the amount of dissolved organic matter is sufficiently high, it also may be necessary to remove the dissolved organic material to comply with the total oil and grease discharge limit. At present, most of the operating facilities worldwide are meeting compliance standards by removing only the dispersed hydrocarbons. However, there are operators that must also remove the dissolved organic material to be compliant. In these instances, some of the more common methods used for offshore applications are pH adjustment with stock mineral acids or patented mineral/acid blends and the use of adsorption/absorption materials (activated carbon). Each method has inherent advantages and disadvantages, as shown in Table 4.1.
Separating Suspended Solids From Produced WaterThe water being treated may have suspended solids, such as formation sand, rust from piping and vessels, and scale particles. It may be necessary to remove these solids to prevent wear in high-velocity areas, solids from filling up vessels and piping and interfering with instruments, and oil-coated solids from being discharged overboard. These solids can be separated from the water stream by gravity settling, hydrocyclone desanders, filters, or centrifuges. Furthermore, once the solids are removed, they must be handled in a manner sufficient to comply with spatial, operational, and environmental constraints. Handling steps may include separation, accumulation, cleaning, dewatering, and haulage.
Gravity Settling. Solid particles, because of their heavier density (compared to water) and net negative buoyant force, will settle to the bottom with a terminal velocity that can be derived from Stokes’ law, as shown in Eq. 4.1. This equation applies strictly to creeping flow regimes in which the Reynolds number is less than unity; this is mainly concerned with spheres of very small diameter surrounded by a liquid. For very small particles, the inertial forces are much less than the viscous forces because of the low particle mass, and the particle does not enter into a turbulent settling regime. This equation can be used to size a tank, vertical or horizontal pressure vessel, rectangular sedimentation chamber, or device of any other configuration to allow a particle of a certain diameter and specific gravity to settle under natural gravity conditions.
Most sedimentation basins are rectangular flumes with length-to-width ratios of 4:1 or greater to limit crossflow. The width of the flow channel can be determined by setting the time required for a particle to settle from the top of the flume to the bottom equal to that required for the water to traverse from the inlet of the flume to the outlet, as shown in Fig. 4.12. This can be expressed as
where b = width (breadth) of the flow channel (ft), qw = water flow rate, and Le = effective length.
Note that the width and length of the settling chamber are independent of its depth. The API Manual on Disposal of Refinery Wastes recommends a turbulence and short-circuiting factor of between 1.3 and 1.8, depending on the ratio of water velocity to solids-settling velocity. Using a factor of 1.8, Eq. 4.14 can be rewritten as
API also recommends that the water velocity be limited to 15 times the settling velocity or 3 ft/min, whichever is less. The settling velocity can be calculated from Eq. 4.1, and the water velocity can be calculated from
where vw = velocity of water, and hf = height of the flume. For practical considerations, b should be between 6 and 20 ft, and the ratio of hf to b should be between 0.3 and 0.5.
The flume can be concrete-lined or constructed as a soil pit; solids that settle in the bottom of the flume can be cleaned out with a bucket. A mechanical sludge scraper run on chain could be installed to concentrate the solids in one location for easy removal.
Desanding Hydroclones. Desanding hydrocyclones, called desanders, offer the highest throughput-to-size ratio of any solids-removal equipment. Fig. 4.13 shows the basic operation of a desander. By definition, all hydrocyclones operate by pressure drop. The feed, a mixture of liquids and solids, enters the cyclone through the volute inlet at the operating feed pressure. The change in flow direction forces the mixture to spin in a radial vortex pattern. Because of the angular acceleration of the flow pattern, centrifugal forces are imparted on the solid particles, forcing them toward the internal wall of the cone. The solids continue to spin in a radial vortex pattern, down the length of the cone, and discharge through the apex, creating the underflow stream. Because of cone convergence, the liquid flow is reversed and sent upward through the vortex finder to create the overflow stream. The solids that exit through the apex collect into an accumulation chamber and are periodically purged, while the overflow discharges continually.
The particle size that is separated depends on the pressure drop through the desander, and the pressure drop, in turn, is dependent on the flow rate. Thus, there is a minimum flow and pressure drop that must be provided for each desander to settle a certain particle size. For general comparison information, in a produced-water-treatment application, a 0.5-in. (10-mm) desander will have a separation size of 5 μm, while a 30-in. (750-mm) desander will have a separation size of 100 μm. The practical limit for sand separation from water by a hydrocyclone is 10 μm. An estimation of particle separation size by a desander can be calculated from the following equation: 
where x98 = particle size at 98% efficiency, D = internal diameter of the cyclone, c = solids concentration, Qf = feed volumetric flow rate, ρs = solid density, and ρl = liquid density.
The previous equation is based on a fixed hydrocyclone geometry relationship, and the desander geometry is unique to each manufacturer. The design is typically scalable in that the inlet area, vortex-finder diameter, length, and apex diameter are proportional to the internal diameter (D). A desander acts as a fixed orifice in the flow stream, with the pressure drop proportional to the flow rate. Each manufacturer can provide a pressure-drop curve, so that the pressure drop is known for a given flow rate. As such, the pressure drop and flow rate are used interchangeably.
The desander pressure drop is the main operating parameter that practically can be changed on line to influence separation efficiency. The desander can operate in a wide pressure-drop range and, thus, inherently has a high turndown ratio. The minimum operating pressure drop for a desander is 5 psig. At less than this value, the fluid does not contain enough energy to form the proper vortex flow pattern. No theoretical maximum pressure drop exists, but 100 psi is recommended as a practical maximum to balance wear and recovery.
Fig. 4.14 shows the two types of desanders that are commonly used in water systems—the vessel style and the liner style. The criteria in Table 4.2 are used to select the proper style.
Because of the simpler design (i.e., without ceramic liners or tube sheets), the vessel desander has a lower capital cost when compared to the liner design. In most applications, though, the deciding factor is the required separation size, which is why most conventional desanders in oil and gas production are of the liner design.
Filtration. To avoid plugging the injection formation, it may be necessary to separate small-diameter suspended particles by filtration. Filters cannot handle the volume of solids that can be handled by sedimentation and desanders, but they are the only practical method for separating very fine particles (< 10 μm). By properly choosing the filter element, filters can remove fine solids in the 0.5- to 50-μm range and are used as a form of secondary treatment. The three types of filters commonly used are cartridge, media, or diatomaceous-earth filters. Because filtration is more commonly used with injection of surface water, this technology is covered in further detail here.
Centrifuges. Centrifuges are used on drilling rigs to separate low-gravity drill solids and to reclaim high percentages of heavy solids. They have not found wide use in producing operations because of the high maintenance associated with their use. Normally, if it is desirable to separate solid particles with a diameter less than that resulting from sedimentation or desanders, filters are used.
Once solids separation is identified as a need in a produced-water system, facilitating the solids handling becomes an important need in overall system design. Systems are based on modular designs that can be built to handle a very wide range of process needs for either land-based or offshore systems. These systems should be manufactured to require minimal operator intervention and, in case of hazardous disposal, minimal contact.
Solids handling can be broken down into five areas:
- Separate. Separation is defined as diverting the solids and liquids contained in a mixed slurry stream to different locations. The solids are removed from the produced-water stream by a gravity vessel (tank bottoms or vessel drain), desander, sand-jet system, or filter dump.
- Collect. Collection is defined as gathering all separated solids into a central location and physically isolating them from the production process. By collecting the solids in one location, a simpler system can be designed to isolate the solids from the process. Collection can be as simple as a desander accumulator vessel or a dedicated sump tank.
- Clean. In many cases, the sand may require cleaning of adsorbed oil or chemicals before further handling. Sand-cleaning systems are offered as modular add-on packages or integrated into the separation system.
- Dewater. The total volume of sand slurry to be transported and disposed of can be greatly reduced by a dewatering step, which involves removing the liquids from the collected (cleaned) solids slurry. A range of systems is available to provide dewatering from a sand-drainage bag to a filter press or screw classifier. The goal is to reduce the liquid to less than 10% by volume.
- Haulage. Haulage is a simple term used to define removing, hauling, and disposing of the solids. The design of the haulage system will be dependent upon location (land-based or offshore) and disposal requirements (i.e., disposal well, overboard, landfill, road surfacing, etc.). Offshore systems typically involve crane-to-boat-to-truck transport, while land-based systems may use a truck to a landfill.
Every solids-handling and -disposal system will be different because of economics, environmental and hazardous regulations, location, and total solids to be handled.
Removing Dissolved Solids From WaterVarious chemical compounds are dissolved in water as ions to form an aqueous solution. The term "dissolved solids" is used to describe these ions in water; some of the more common are silica, calcium, and magnesium. When water is thermally evaporated or treated with membranes, these ions become saturated and exceed their solubility in water. They will then precipitate or crystallize to form scale. Scale formation plugs piping and fouls the water-handling system, steam-generator tubes, and membranes. Scaling sometimes can be controlled with an inhibitor chemical; however, when this does not work, these ions should be removed from the system. The dissolved ions can be removed from water with membranes, ion exchange, and hot or warm softening.
Membranes. Membranes are predominantly used to remove species of salts and organics from water. Reverse osmosis (RO) can remove 95 to 99% of the metallic ions, such as sodium and potassium salts, as well as a relatively high percentage of organic material. Nanofiltration (NF) can remove most divalent ions, such as sulfate and nitrate, from water. An RO membrane can remove most of the dissolved solids or ions from the water, as shown in Fig. 4.15. Comparatively, NF membranes can remove divalent ions but allow monovalent ions to pass through. Ultrafiltration and microfiltration can remove only the submicron-size suspended particles and are not effective for removing soluble ions.
The performance of a membrane unit can be expressed by the following equation.
where Qpf = permeate flow, Kf = fouling factor, KT = membrane temperature-correction factor, K = permeate flow coefficient at standard temperature, A = membrane area, and Δpavg = average transmembrane pressure drop. Because of the presence of various impurities in water, the membrane gradually will become fouled, and the permeate flow will decrease, measured by the fouling factor, Kf. For a clean, new membrane, the fouling factor is 1.0. This value will decrease gradually, and the membrane element will need to be cleaned. Generally speaking, the membrane element requires cleaning when the fouling factor is decreased approximately 10 to 15%, or when it reaches a value of less than 0.85.
The water flow coefficient, K, is a function of the water/membrane chemistry interaction, especially pH. Normalized permeate rates are higher at a pH of 11 than at 7. Although in general, the water flow coefficient cannot be predetermined, the variation of KT with temperature is known for each membrane and can be used to normalize permeate-flow data at different temperatures. At any point in the RO system, the transmembrane pressure drop is the difference between the brine hydraulic pressure and the system osmotic pressure plus the permeate pressure. As the brine concentration increases from the feed to reject ends of the membrane system, the transient pressure decreases.
Various types of membrane configurations are available. The most common types are plate and frame, hollow-fiber, monolithic-tubular, tubular, and thin-film-composite spiral-wound, as shown in Figs. 4.16 through 4.20. The thin-film-composite spiral-wound membranes have been used successfully to treat brackish oilfield produced waters.
It is desirable to produce a high fraction of good-quality permeate water to reduce the amount of concentrate water for disposal. For practical purposes, a 75% recovery of the permeate water can be achieved without seriously fouling the membranes. This level of removal efficiency is relatively high for most of the inorganic and organic materials, as shown in Table 4.3. Trace metal removal is also relatively high, as shown in Table 4.4.
Ion Exchange. The ion-exchange process is used to remove specific ions from solution. Its primary application in produced-water treatment is the removal of calcium and magnesium ions, which make up the "hardness" in water. Ion exchange used for this purpose is called "water softening." It also can be used to remove residual minerals and, in this instance, is called demineralization.
Water Softening. The water-softening process is used in the oil industry for steamflood operations. To operate reliably at high temperatures and pressures, steam generators require a very low hardness content in the feed water. Scale precipitation can coat the heating tubes, causing localized overheating and tube failure. Fig. 4.21 shows a typical water-softener bank used in steamflood operations. For this case, the divalent ions, calcium and magnesium, are exchanged with the sodium ions from an ion-exchange resin. After the exchange, the ion-exchange resin is saturated with the divalent ions. It is regenerated with a higher-concentration brine solution, which is rich in sodium ions. This brine solution is generally a 10 to 20% salt (sodium chloride) solution.
There are two types of water-softening resins commonly used in the oilfield for steam generation: strong and weak acid resins. A typical strong acid resin is the sodium zeolite cation-exchange resin, consisting of a synthetic zeolite material that contains numerous cation-exchange sites. These sites primarily contain sodium (Na) ions. The zeolite resin is commonly expressed as "Z," and its ion-exchange reaction with the hardness material, either calcium or magnesium, is shown in the following reactions:
The strong acid resin generally is used for removing the hardness materials from water with relatively low sodium contents or total dissolved solids (TDS). This type of resin attracts the calcium and magnesium ions and exchanges them with a sodium ion upon regeneration. However, as the sodium content in the feed water increases (on the basis of the previous formula), the reaction will go in reverse and start to regenerate during the softening process. This partial regeneration is called the "hardness leak." The hardness leak is pronounced for the strong acid resins when the TDS of the feed water is greater than approximately 5,000 to 7,000 ppm. Hence, when the concentration of TDS exceeds this limit, strong acid resins are no longer effective.
The sodium ion used for regeneration is common salt (NaCl). During regeneration, the high concentration of salt in the brine exchanges the hardness material, such as calcium ion, with sodium, as shown in the following reaction.
The source for regeneration is generally sea salt, produced by the evaporation of seawater; however, rock salt from the land-mining process is sometimes used. The quality of salt is important, and its impurities should be studied before use to minimize operational problems.
The weak acid resins are generally used for removing hardness materials from water with higher sodium content or TDS. The weak acid resin can handle produced water with TDS up to 30,000 to 40,000 mg/L. Its regeneration program uses an acid, such as hydrochloric acid, followed by a base, such as sodium hydroxide. The capital cost of a process of weak acid resins increases in comparison with processes using strong acid resins because of the use of an acid and a base during regeneration, which requires using linings in the vessels and corrosion-resistant piping. Similarly, the operating cost of processes that use weak acid resins increases in comparison with processes using strong acid resins because of the higher cost of the regenerating materials (acids and bases for the weak acid resins vs. a salt solution for the strong acid resins).
Softening the economic breaking point between weak acid resins and strong acid resins is approximately 7,000 mg/L of TDS. When the TDS measures between 5,000 and 7,000 mg/L, there is slight hardness leakage, but the water with a small amount of hardness materials could be treated with a chelant, such as EDTA or NTA, or a combination of chelant and polymeric scale-suppressant chemicals. However, when the TDS is greater than 7,000 mg/L, the hardness leakage would be too much, and a chelant program might become uneconomical.
Demineralization. Using ion-exchange resins to remove residual minerals from water is called demineralization. This process is generally used for polishing water after membranes, softening, or warm-lime treating. When the minerals are removed, this water can be used in boilers for steamflooding or in steam turbines for electrical generation. The demineralization process uses various types of ion-exchange resins to achieve different results, as summarized in Table 4.5.
Treating produced water with a demineralization system as the final stage for polishing allows it to be used in cogeneration plants for electrical production. Additionally, the produced steam can be used for steamflooding. Because of the use of acid and base chemicals for regeneration, the cost of a demineralization system is relatively high. It can be used only for polishing good-quality water from other pretreatment processes and is generally uneconomical to apply to raw water treatment.
Hot- and Warm-Lime Softening. Hot- and warm-lime-softening processes are other technologies used to remove the hardness and silica ions from produced water for steam generation. The advantages of these systems are that they can process a large amount of water in a relatively small unit, and their applicability, unlike zeolite softeners, is not limited by the water’s TDS.
The design of one type of the hot-lime process is shown in Fig. 4.22. Normally, a residence time of 1 hour is specified. Produced water is heated up to or greater than 212°F by spraying at the top of the unit. The lime (calcium oxide) is premixed in water as slurry and fed immediately below the spray. It reacts quickly with the hardness materials in water to form precipitates; this mixture flows to the bottom part of the vessel through a downcomer pipe to contact with the remaining sludge. At the bottom, the flow is reversed, and the water rises slowly through a blanket of previously formed sludge. The intimate contact increases the efficiency of the softening process. The basic reaction is shown as follows.
The reaction products, calcium carbonate (CaCO3) and magnesium hydroxide [Mg(OH)2], are precipitated and removed as sludge. This reduces both the total hardness and TDS. When the carbonate is short in the feed water or the system contains noncarbonate hardness ions, soda ash should be used. Its reaction is shown as follows:
When soda ash is used, the final product still contains the soluble noncarbonate ions; hence, it does not reduce the TDS. The sludge or the precipitated solids from the lime process are periodically blown down from the unit. The treated water is processed with a filter before sending it to the steam generators. The backwash water from the filters is returned to the unit. When the unit is operated at a temperature of less than 212°F, it is classified as a warm-lime softener.
One type of warm-lime softener is shown in Fig. 4.23. This warm-lime unit has two compartments. In the reaction zone, or the first compartment, the lime and magnesium oxide slurry is fed together with the produced water. A mixer moves very slowly to keep the influent mixture in contact with the slurry in this compartment. This contact promotes precipitation of both hardness materials and silica. The treated water flows upward and overflows into the clarification zone, or the second compartment. The sludge separates from the water and sinks to the bottom of the clarification zone. The treated water flows upward through a set of clarification weirs to prevent any sludge flowing out of the system. The bottom sludge is recycled with an external pump back to the reaction zone. This unit can be used for removing both silica and hardness ions from produced water.
Silica Removal. Silica fouls steam generators and RO membranes when its concentration exceeds the solubility limit. Its solubility data are plotted in Fig. 4.24. The silica solubility also depends upon the pH of the water. The silica solubility increases significantly at higher pH values. Silica scale is generally deposited on the inside of the radiation section tubes. This deposit acts as an insulator for the tube and reduces its heat transfer. More seriously, the tube can overheat from the flame and cause tube failures. Based on the previous analysis, it is necessary to remove silica and control its concentration in the feed water for the RO-membrane and steam-generation systems.
Silica can be removed with the warm- or hot-lime softeners described previously. In a steamflood operation, the produced water generally is at greater than 170 to 180°F; hence, the warm-lime-softening unit is adequate for handling it. However, the option of using the hot-lime process exists. The chemical reaction for silica removal is still unknown, and the key is to use an adequate amount of lime and magnesium oxide and recycle the slurry to promote an intimate contact with the incoming water for a better reaction and better use of the chemicals. Silica also can be removed at lower temperatures (60 to 80°F), generally referred to as the cold-lime process.
Steam ProductionA steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells. As the heat is absorbed by the crude and formation, the steam condenses, mixes with the crude and formation water, and is produced with the crude. This hot produced water is then separated from the crude, treated, and injected as steam to complete an entire steamflood cycle. This section discusses the process and equipment for water treatment for steam production.
Water-Treating Processes for Steam Production. A typical water-treatment process for steam production is shown in Fig. 4.25. Separators or tanks remove the bulk water from oil. The oily water is then treated with flotation cells to remove most of the dispersed oil (95%). The treated water contains < 10 mg/L of oil and suspended solids. Final water polishing is done by filtration, such as sand, multimedia, or walnut-shell filters, to reduce the oil and suspended solids to < 1 mg/L. The clean water is treated by water softeners to reduce the total hardness to < 0.5 mg/L so that it can be fed into the steam generators.
If the produced water has high silica content, a warm-lime or hot-lime process should be used to remove silica to the desirable level. If the produced water has high TDS, either RO or weak acid softeners should be used to soften it for steam generation. Recently, an RO process was used to treat produced water to meet drinking and irrigation quality. A similar process has been used for generating electricity after polishing with a demineralization treatment.
Chemical treatment is generally required to maintain the integrity of equipment and improve the quality of water for steam generation. Depending upon the needs, this treatment could include corrosion and scale inhibitor, oxygen scavenger, water clarifier, coagulant, and biocide treatment.
Quality of Water for Steam Production. High-quality water is necessary for maintaining a reliable, continuous steam-injection program. Although there is no specification for heavy metal ions, these materials should be kept low to minimize poisoning of ion-exchange resins. The quality of water required for steam generators operating at a steam quality of 70 to 80% is shown here:
- Total hardness: < 0.01 mg/L.
- Oil content: < 0.5 mg/L.
- Total suspended solids: < 0.5 mg/L.
- Total iron: < 0.5 mg/L.
- Oxygen content: < 0.02 mg/L.
- Silica concentration: < 200 mg/L.
Steam Generators. Steam generators are used to produce steam for the steamflood. The most popular steam generators are the 25- and 50-MMBtu/hr units. The 25-MMBtu/hr units are used as mobile units and provide steam for cyclic-steaming or remote-injection wells. The 50-MMBtu/hr units provide steam from a central banked location, which simplifies the water- and fuel-treatment plants and the steam-distribution system. Moreover, if exhaust-gas scrubbing is required, the scrubber system can also be centralized. Significant savings can be realized by centralizing these units.
A typical steam-generator and system flow schematic is shown in Figs. 4.26 and 4.27. It consists of a convection section and a radiant section. The convection section is designed to preheat the softened feed water, and the radiant section further heats the steam pipe for generating steam. A steam generator produces 60 to 80% quality steam, depending on the reservoir requirements. Higher-quality steam can be generated if good-quality water and fuel gas are used. When the required steam quality reaches 90%, control becomes difficult, and the chance of overheated pipe increases because of the relatively low liquid phase near the pipe effluent.
Depending on the reservoir requirement, steam-injection rate, and tightness of the formation, steam-injection pressures vary from field to field. A steam generator can be operated at a pressure of approximately 2,700 to 3,000 psig and can be designed specially for a higher operating pressure if required. The operating temperature changes with the corresponding pressure. The correlation can be seen in a typical steam chart found in many mechanical engineering textbooks. This chart contains thermodynamic information about the steam. At a certain steam quality, pressure, and temperature, the steam delivers a specific amount of heat to the reservoir, according to the steam chart. Poor-quality feed water will scale the steam generators, causing poor heat transfer or plug-up. High-hardness feed water will cause calcium carbonate, magnesium carbonate, or sulfate scales. A high iron concentration in the feed water will cause iron carbonate or oxide scales in either the convection or radiant section. A high silica concentration will cause silica scale in the radiant section. Other types of scale are also present, such as complex compounds or scales induced by produced fines, silt, or injected chemicals.
Because of various operating and maintenance conditions, a steam-generator bank usually has a finite percentage of downtime, which is generally factored into the design so that a constant steam flow can be assured. A well-operated field can have steam-generator downtime as low as 5%.
Steam Distribution. After steam leaves the generators, it is transported and distributed by pipelines to steam injectors. This pipeline network is generally insulated to reduce heat loss and to provide safety for the people working in the area. Because the steam generators are not generating 100% steam, the pipeline flow consists of a vapor phase and a liquid phase. Depending on the steam-flow rate, pipe size, temperature, and pressure, the steam may flow with different flow patterns. A phenomenon known as phase splitting is known to occur at piping junctions, branches, and tees, resulting in widely varying steam qualities at the steam injectors in any large steamflood project. Inconsistent steam delivery results in inconsistent heat delivery to the reservoir, interfering with the optimization of steam-injection rates, oil recovery, and project economics.
Various designs exist in the literature for handling the phase-splitting problems. One company has developed a patented steam-splitting device to control steam distribution, as shown in Fig. 4.28. This device controls the steam quality delivered to the "branch" (side flow) of a junction, while the "run" quality (straight-through flow) is uncontrolled. As a result, this device’s control of the branch steam quality is almost independent of changes in the flow rate through the branch. Although the device itself is not used to control either the branch or run flow rate (chokes or control valves at the injection wells are necessary for rate control), the uniformity of steam quality provided by this device makes rate control more reliable.
Steam Injectors. Steam injectors are used to inject steam into the formation. There is a concentric pipe design, made of an inner pipe for transporting steam down to the reservoir, which uses the casing as the outer pipe. The casing is cemented to the injection well with a special blend of cement, including silica flour. This cement can withstand large amounts of heat with minimal expansion. The well casing design prevents heat loss to the surroundings. The inner injection tubing holds heat from steam, and the air/steam gap between the inner pipe and casing acts as an insulator to reduce heat loss. Deep injection wells are equipped with insulation tubing around the outside of the steam pipe. This insulation tubing is specially designed with a vacuum in the jacket to provide additional heat insulation.
Surface-Water Treatment for Injection
In many operations worldwide, surface waters are injected into producing formations to enhance oil recovery. The types of surface waters used range from seawater (salt water) to lake water (brackish) to river water (fresh water). Surface-water injection is an attractive option for the following reasons:
- In many cases, surface water is easily accessible and readily available without high-cost well-drilling and well-completion activities.
- Surface-water supplies are considered inexhaustible.
- Most surface-water supplies can be used without having to pay fees or taxes.
- The use of surface water creates very little environmental impact or concern.
Surface water, however, must be treated to remove undesirable components before injection. The most common types of contaminants are solids (sand), dissolved gas (oxygen), biological material (plankton and bacteria), and dissolved solids (sulfate). Treatment of surface water for injection requires a specially designed system made up of various components to remove or control any contaminants in the water. The system is engineered to perform the required treatment in the most cost-effective and environmentally sensitive manner. A typical system is shown in Fig. 4.29. Commonly used methods for removal or control of these contaminants are discussed in this section.
Separating Suspended Solids From Injection WaterSurface waters normally contain suspended solids particles that, if injected into the producing formation, will plug the injection well. The type, concentration, and particle-size distribution of suspended solids in water will vary depending on the source of the surface water. For example, river-water sources tend to have higher concentrations of suspended solids (100 to 1,000 mg/L), whereas deep offshore water sources tend to contain rather small amounts (5 to 50 mg/L). Furthermore, the suspended solids found in river water tend to be inorganic (silica-based), whereas the suspended solids found in the oceans tend to be organic (primarily bacteria). Hence, the treatment methods also vary depending on the source. Solids-removal equipment generally may be classified as primary (coarse) or secondary (polishing) removal devices. Table 4.6 lists the solids-removal devices commonly used to treat surface water for injection.
The terms "primary" and "secondary" refer to both the amount and the size range of suspended solids to be removed. Primary removal considers solids concentrations greater than approximately 100 mg/L and solids particle sizes greater than 50 μm. Secondary removal refers to suspended solids concentrations of less than 100 mg/L and solids particle sizes less than 50 μm.
Primary (Coarse) Solids Removal. Solid/Liquid Hydroclones. As mentioned previously, solid/liquid hydrocyclones, or desanders, can be classified as primary or bulk-removal devices designed to handle larger particle sizes and higher solids concentrations. These units provide an inexpensive first pass at removing 50- to 100-μm solids. They are more commonly used with river waters to remove silt and sand; please refer to Sec. 4.2.8 for more details.
Coarse Strainers. Coarse strainers are devices designed for applications that require the removal of large solids (> 250 μm). Strainers mechanically remove or screen out solids particles based on size alone. Many of the strainers commonly used in water-injection systems employ either a basket-style straining device or a wire-wound cylindrical element. During filtration, the strainer screen fills up with material, which leads to a gradual increase in pressure drop. This increase in differential pressure means that each strainer must be backwashed periodically to remove accumulated solids. This period can be varied, and the program time will be established during commissioning. Backwashing occurs while the strainer remains on line without interruption in the forward flow. Either the basket or wire-wound design can be automated for online self-cleaning of the solids that build up. This is a useful feature because it affords continuous operation of the plant, even during the cleaning cycle.
Secondary (Polishing) Solids Removal. Solid/Liquid Hydroclones. As discussed previously, solid/liquid hydrocyclones also can be used for polishing. Desanders in this application can practically remove solids up to 10 μm in diameter, the lower limit for hydrocyclone technology.
Granular-Media Filters. The majority of large-flow-rate polishing filter applications involve the use of granular-media filtration. Granular-media filters, also called sand filters, contain a bed of graded sand, gravel, anthracite, or graphite. The beds may be of a single medium or may be graded from coarse to fine media to allow for greater solids loading. Sand filters are good for separating 25-μm particles, but some manufacturers claim that their filters are good for 5- to 10-μm separation.
During filtration, the particulate matter carried by the water is trapped within the filter media. Because of the carefully selected grades of media, this entrapment occurs right through the top two layers. The increase in pressure drop across the filter is gradual because the solids collection occurs through the filter bed. It also means that the filters can easily cope with sudden increases in the solids content of the seawater without blinding. This increase in differential pressure, however, means that each filter must be washed to remove the accumulated solids, normally achieved by washing each filter in rotation (e.g., in a 24-hour period, one filter backwash would start every 8 hours).
The media are arranged in a pressure vessel for either downflow filtration and upflow backwash, as shown in Fig. 4.30, or for upflow filtration and upflow backwash. Conventional downflow filters are limited to flow rates of 2 to 5 gal/min-ft 2 and total solids loads (before backwashing) of 1/2 to 1 1/2 lbm/ft2. With appropriately designed distribution systems, high-rate filters can be operated at 7 to 15 gal/min-ft2. This higher loading forces the solids farther into the bed, allowing for solids loadings of between 1 and 4 lbm/ft2. Upflow filters have a greater capacity for solids loading; flow tends to loosen the bed, allowing for greater penetration of the solids (up to 6 lbm/ft2 of solid loading). However, because of the danger of losing the bed, upflow filters are limited to flow rates of 6 to 8 gal/min-ft2 and require longer backwashing time and more backwash fluid.
Two modes of filter-backwash control are available: manual (used during commissioning or troubleshooting) and automatic (normal operating selection). When a filter is selected to manual, the operator can select any stage in the backwash sequence (i.e., a drain-down stage), initiate that stage, and run it for the required amount of time. When a filter is set to automatic, the filter will be backwashed automatically when the backwash interval time starts it, when a high differential pressure occurs, or when the operator starts an autobackwash.
Cartridge Filters. Cartridge filters are simple to install, require no backwash, and are capable of removing solids particles 2 μm or larger in diameter. Their drawback is that they can take only very low solid loadings, and the cartridges must be disposed of after use. The filter vessel must be taken out of service and depressurized, and the cartridges must be replaced whenever the volume of solids trapped causes the differential pressure to exceed a predetermined maximum (usually 25 psi). Some modern cartridge filters can be backwashed.
Fig. 4.31 shows a typical cartridge filter. The cylindrical filters are encased in a pressure vessel. Flow enters the vessel and flows from the outside of the cartridge to the center, where it enters a perforated pipe that is open on the bottom. A bypass mechanism is included that will automatically allow flow to pass from the inlet to the outlet chambers if the differential pressure exceeds the capacity of the cartridges.
Table 4.7 indicates the particle size that can be separated and the recommended flow rate through various standard-size cartridges. Molded fiberglass has the least solid-storage area, and pleated wire screen or paper has the most.
Dissolved-Gas Removal (Oxygen)
Surface water (fresh or saline) will contain dissolved oxygen that must be removed by the water-treating facility. Oxygen in concentrations of 0.5 ppm in hydrogen-sulfide-free water and 0.01 ppm in water containing hydrogen sulfide is generally considered to be sufficient to cause corrosion problems in the facilities and bacteria-plugging problems in an injection reservoir. For this reason, attempts are made to exclude oxygen from produced-water systems by maintaining gas blankets on all tanks. However, these systems sometimes must be designed to handle rainwater, which may introduce dissolved oxygen in sufficient quantities to require removal. All seawater contains oxygen, and while the location of surface-water intakes can be arranged to minimize the oxygen content, oxygen will have to be removed in almost all cases.
Some water sources contain ammonia, H2S, or CO2, which must be removed. Chemical scavengers, gas stripping, or liquid extraction are capable of removing these dissolved gases. It is beyond the scope of this chapter to deal with the design of the complex processes and equipment that can be used in removing all dissolved gases. Because oxygen is the most common contaminant, we will briefly describe the treatment process commonly used to remove dissolved oxygen.
Oxygen Scavengers. The use of chemical scavengers for dissolved-oxygen removal from water is covered in the Water-Treating Chemicals section of this chapter (Sec. 4.4).
Gas Stripping. The basic principle used in gas stripping is that the quantity of oxygen dissolved in the water is directly proportional to the partial pressure of the gas that is in contact with the water (Henry’s law). Because partial pressure of the gas is a function of the mole fraction of that gas, the addition of other gases to the solution will decrease the partial pressure of oxygen and, thus, the concentration of oxygen in the water.
In a typical gas-stripping column, natural gas or steam is introduced in the base of a packed or trayed column (similar to a glycol contactor used in gas dehydration) and flows upward countercurrent to the water. The water is introduced in the top of the column and flows downward.
If natural gas is used, the oxygen-contaminated gas from the top of the tower can be used for fuel, compressed for inclusion in the sales gas stream, or vented, depending on the process design, environmental regulations, and gas sales contract. Stripping-gas usage of 2 to 5 scf/bbl is common.
It also is feasible to strip oxygen from water with a concurrent flow. This is common in cases in which lift gas is used as the artificial-lift mechanism for obtaining the water from a reservoir or subsea source. The gas is sometimes injected into the water with a static mixer in concurrent flow in a pipe. While this may require more stripping gas, it may be more economical from the standpoint of equipment cost, space, and weight when the value of the stripping gas is low. Stripping-gas usage in concurrent flow can be in excess of 10 scf/bbl.
Before entering the contactor column, water (from the media-filter package) is treated with an antifoam chemical. Seawater has a high foaming tendency, which can seriously affect the performance of the column. The seawater is then fed to the mass-transfer section (containing the packing or trays) of the column for oxygen removal. Water enters the column near the top through an inlet-distribution header, which ensures an even flow across the full-tower cross section. From the distributor, the water flows down through the packing or trays. The objective of the mass-transfer section is to create a large surface area over which the water forms a thin film, promoting intimate contact with the fuel gas and enhancing mass transfer. After passing through the mass-transfer section, the water falls into the column sump, where a chemical oxygen scavenger is added to reduce the oxygen content to acceptable levels. During normal operation, when the filters are not backwashing, the level in this sump is used to control the flow rate of the water entering the top of the contactor.
Vacuum Deaeration. Because the partial pressure of oxygen in water is a function of the total pressure of the system, applying a vacuum to the water/gas system can reduce the partial pressure of oxygen. Vacuum deaerators can be combined with either countercurrent or concurrent stripping gas to provide very low oxygen concentrations in the water. Stripping-gas usages of a fraction of a cubic foot per barrel are common. Vacuum stripping towers are used where no stripping gas is available; where the available stripping gas contains contaminants, such as CO2 and H2S; or where stripping gas has a high value. The disadvantages of vacuum-deaeration systems include high power costs (to operate the vacuum pumps) and high maintenance to the system to ensure that oxygen does not enter the system through seals, gaskets, or pipe joints.
Compact Deoxygenation. The weight and space allotted to production equipment are of major concern to operators, especially in offshore applications. In response to this sensitivity, oilfield equipment vendors have developed compact deoxygenation systems. At present, there are two systems in commercial use. * 
One system uses a wet combustion catalytic process to consume the dissolved oxygen in the water. The operating principle of this system is simple—hydrogen (produced and injected into the water stream) and oxygen (contained in the water) react in the presence of a palladium catalyst (contained in a pressure vessel) to produce water molecules. The major system components are:
- The palladium catalyst.
- The inline mixer.
- The hydrogen generator skid.
- The liquid-filled catalyst vessel.
Oxygenated water enters the inlet piping of the system and is measured with an accurate flowmeter. The measured-water flow-rate value is registered by the system controls, and a signal is sent to the hydrogen generator. Based on the inlet water flow rate, a proportional amount of hydrogen is produced and injected into the water upstream of the mixer. It should be noted that the hydrogen reacts with any free chlorine in the water (i.e., from the electrochlorinator); therefore, an additional amount of hydrogen is produced to make up for this loss. The static mixer ensures good dissolution of the hydrogen gas into the water. The water/hydrogen mixture is then routed to the catalyst vessel, where contact with the palladium catalyst is achieved. The oxygen in the water is reacted with the dissolved hydrogen gas in the presence of the palladium catalyst to produce water molecules.
Hydrogen is produced by the electrolysis of an ultrapure freshwater stream to produce H2 and O2 gases. The H2 gas is separated for injection into the water stream, while the O2 gas is vented to a safe location. A local programmable logic controller (PLC) controls the process for preparing the ultrapure water. The same PLC is used to regulate the production of hydrogen in proportion to the measured flow rate of the incoming oxygenated water.
An alternative compact deoxygenation system uses a high gas/water ratio stripping process in either a concurrent or countercurrent mode. The stripping gas used is nitrogen instead of natural gas. In either mode, the oxygen-laden stripping gas is regenerated in a catalytic purification vessel by means of a reaction of the oxygen with methanol in the presence of a palladium catalyst to produce CO2 and water. Compressed air is used as makeup gas to replace nitrogen losses from the system.
In the concurrent mode, deoxygenation occurs within two stages of mixers. Nitrogen gas is injected into the water stream in a concurrent manner upstream of the mixer. The mixer creates intimate contact between the oxygenated water and the stripping gas. As discussed previously, the oxygen will diffuse out of the water according to Henry’s law. Located downstream of each mixer is a partially liquid-filled disengagement vessel. Once inside the vessel, the oxygen-rich nitrogen gas is separated from the water and removed through the gas outlet at the top of the vessel. Stripping gas for the first-stage mixer is taken from the gas outlet of the second-stage disengagement vessel after compression. The oxygen-rich nitrogen gas from the first-stage disengagement vessel is routed to a catalytic deoxidizer to remove the oxygen. Regenerated nitrogen from the deoxidizer is then routed to the second-stage mixer.
In the countercurrent system, the oxygenated water is routed to the top of a partially liquid-filled deaerator column in the same manner as described previously. The column is equipped with water inlet distribution piping, mass-transfer packing, inlet distribution piping for the nitrogen stripping gas, and a sump section. A major difference between the compact system and the traditional gas-stripping system described earlier is that the oxygen-rich nitrogen is deoxygenated and recycled to the stripping-gas inlet of the column. As mentioned previously in the description of the concurrent system, the oxygen-rich gas from the top of the column is routed to a catalytic deoxidizer to remove the oxygen.
Either system allows a substantial reduction (20 to 50%) in the weight and space of the deoxygenation equipment. The reduced weight and space requirements translate into reduced structural and support steel on the deck. Because either system can be provided as skid-packaged units, the amount of site work is reduced, and the need for special cranes or other special lifting requirements is minimized.
Surface water contains biological constituents (primarily bacteria) that can contaminate the water-injection system. Because bacteria have the ability to multiply rapidly into colonies, they can cause plugging of surface and downhole equipment and injection-well formations, promote corrosion of surface piping and downhole tubulars, and generate H2S that can cause pitting corrosion. Therefore, it is essential to develop a means to control the growth of bacteria in surface-water-injection systems. Bacterial growth is controlled mainly by chemical biocides, the most common of which is chlorine, which may be added directly or produced in-situ from seawater. Direct-added chemicals are covered in Sec. 4.4.
Because of its high chloride content, seawater can be electrolyzed with a hypochlorite generator or an electrochlorinator to produce hypochlorite (OCl–). Chlorine production in this way makes for a very convenient, inexpensive, and reliable source of bactericide. Chlorine from the electrochlorinator is continuously dosed into the seawater lift-pump intake to prevent marine fouling within the system, making up the injection-water-treatment system.
The hypochlorite generator produces chlorine in the form of sodium hypochlorite at a rate equivalent to a concentration of approximately 5 ppm. The electrolyzer is fed with seawater from the coarse-filtration outlet. The chlorine is generated by electrolysis in a single electrolytic cell. The amount of sodium hypochlorite formed is proportional to the amount of direct current passed through the seawater. The byproduct, hydrogen gas, is released and diluted to less than 2% mixture (less than the explosive limit) and vented to atmosphere.
Seawater contains approximately 2,800 to 3,000 mg/L of sulfate ion. Using seawater for injection into a producing reservoir for pressure maintenance or for waterflooding can cause problems if the formation water contains significant levels of calcium, barium, or strontium. Depending on the pressure and temperature of the system, these ions react with sulfate to produce either calcium sulfate, barium sulfate, or strontium sulfate scale. Both barium sulfate and strontium sulfate scales are extremely hard to dissolve in acid and equally hard to remove by mechanical means. Hence, once these types of scale deposit in either the production tubulars or the surface process piping, the likely result is that the well or platform may have to be shut in while the affected piping is replaced. One solution to this problem is to remove or reduce the amount of sulfate ion in the seawater before it is injected.
The process for removing sulfate ions from seawater is based on NF membrane separation. NF is a membrane process that selectively removes sulfate ions to produce reduced-sulfate seawater. The process is similar to RO, used extensively worldwide for seawater desalination; however, the NF membrane has a larger pore size and possesses a slight negative charge and, thus, can reject divalent ions (e.g., sulfate). Furthermore, NF membrane has a better feed-to-permeate conversion at 75% of the inlet flow rate; that is, for every 100 bbl of seawater fed to the system, 75 bbl of low-sulfate water are produced, and 25 bbl of high-sulfate water are rejected. **
The concept has been proven technically by its successful application in a west Africa seawater injection plant with a capacity in excess of 330,000 B/D. The design point for a sulfate ion in the treated seawater is 40 mg/L at 20°C seawater temperature. At this level of sulfate removal, it is expected that the amount of barium sulfate scale would be reduced from 50 to 7 kg per 1,000 bbl of produced water.
A simplified process diagram is shown in Fig. 4.32. With a booster pump, pressurized saline feed water is continuously pumped to the module system. Within the module, consisting of a pressure vessel (housing) and a membrane element, the feed water will be split into a low-saline product, called permeate, and a high-saline brine, called concentrate or reject. A flow-regulating valve, called a reject valve, controls the percentage of feed water going to the concentrate stream and the permeate that will be obtained from the feed.
Normally, the plant is divided into two membrane arrays staged in a 2:1 configuration. Each array is operated at 50% conversion, with the reject from the first array being fed to the second array for further treatment. The product streams from both the first and second arrays are then combined for injection into the formation, while the concentrate stream from the second array is rejected. Because each array is operated at 50% conversion, the combined product streams constitute 75% of the inlet flow rate (75% total conversion to product).
The seawater temperature is the most significant parameter affecting the design of sulfate-removal membrane systems. Lower sulfate levels in the product stream result in lower seawater feed temperatures; however, lower seawater feed temperatures require higher pressure drops through the membrane to maintain the desired flux rate and vice versa. Therefore, a balance must be established between the desired sulfate level of the product stream and the energy available for use to raise the seawater temperature or to increase the seawater feed pressure.
Proper pretreatment of the feed water supplied to the NF membrane is required to maximize the efficiency and life of the membrane elements and to ensure trouble-free operation. Pretreatment requirements include the following:
- Removal of fine suspended solids that can plug or block the membrane surface.
- Prevention of biological growth on the membrane surface.
- Prevention of scale formation on the membrane surface during concentration of the feed water.
- Removal of any oxidizing biocides (e.g., chlorine) that can damage the membrane.
- Pressurization as required to achieve NF separation.
The sulfate-reduction package is part of a system that is designed to achieve all these objectives. For instance, both specially designed media-filter systems and cartridge filters are used to remove solids from the seawater upstream of the membrane elements. Furthermore, as sulfate is removed from the seawater along the length of each membrane element, the dissolved-solids content of the concentrate increases. As a result, the scaling tendency of the concentrate increases, as shown in Fig. 4.33. To avoid the deposition of scale on the membrane surface, antiscaling chemicals are injected into the seawater upstream of the membrane system. In addition, an organic biocide is dosed into the seawater to control the growth of bacteria in the membrane, and a dechlorination chemical (bisulfite) is injected into the seawater to neutralize any strong oxidizers (chlorine).
Despite these efforts to keep the membranes clean, the membranes will foul with time as the plant is operated. Therefore, membrane elements must be taken out of service on a routine basis for a deep clean with special cleaning chemicals. These chemicals are designed to remove deeply embedded scale and bacterial fouling with minimal damage to the membrane-element materials. It is possible to prepare a membrane-monitoring system to provide feedback to the operators that indicates the need for deep chemical cleaning of the membrane elements.
Weston, R.: "Engineering Design of a Sulphate Removal Package," Axsia Serck Baker Ltd., internal document (December 1995) 3.
* Place, M.C. Jr.: "Catalytic Oxygen Removal—A Light Compact Water Deoxygenating System," Shell Oil Co., unpublished internal document (1993).**
Chemicals play an important role in the oil-producing operation. They assist oil/water/gas separation, aid in fluid transport, protect treating equipment, and improve the quality of the gas, oil, and water. In water treating, they aid in producing suitable water for discharge or injection. A wide range of chemicals is available for water treating, and this section details the main classes. These include water clarification, scale inhibition, corrosion protection, bacterial control, oxygen scavengers, antifoam, and cleaning surfactants.
A chemical-injection package enables various types of chemicals to be dosed into the water stream to optimize the treatment process. In many operations, each chemical-injection stream is equipped with two dedicated pumps, a duty and a standby pump, both of which are rated for 100% capacity. Storage-tank capacity is designed to allow the plant to run for several days between refills. Tank-construction materials can be carbon steel, stainless steel, or other material appropriate to withstand the action of the stored chemicals.
General dosing rates and injection points for the main chemical classes are listed in Table 4.8. These rates provide guidelines for sizing injection pumps and chemical-storage tanks.
Water Clarification (Flocculants)
The purpose of water clarification is to improve the water quality to meet discharge or injection requirements. Water-clarification chemicals aid in coagulating and flocculating the oil and solid particles into larger ones to enhance their separation from water. Increasing the particle or droplet size significantly enhances the removal efficiency of skim tanks, hydrocyclones, filters, and centrifuges. The commonly used water-clarification chemicals may be classified as inorganic coagulants or polyelectrolites, but polyelectrolites are used normally as a secondary coagulant and filter aid.
Most of the inorganic coagulants and polyelectrolites can be dissolved and ionized in water. Their ion charges attract oil droplets and solid particles with opposite charges. Oil droplets grow by coalescence, and solid particles grow by forming flocs. The larger oil droplets or larger solid flocs are easier to separate. Particle separation from water follows from Stokes’ law in that larger particles separate more quickly from water.
Inorganic coagulants include aluminum, iron, and copper salts. Except in the case of sodium aluminate, most of the common aluminum and iron coagulants are acid salts and require pH adjustment to reach the best operating range. For instance, aluminum coagulants require a minimum pH of 6 to 7, while iron salts are effective in a pH range of 5 to 11. These chemicals are very effective in promoting coagulation of oil and solids particles; however, excessive use or improper application of these chemicals will form undesirable oily gel-type settlements and occasionally cause malfunction of the monitoring/controlling instrument. The inorganic or low-molecular-weight coagulant is effective in the range of 10 to 45 ppm.
Ferric sulfate may be used as a coagulant. The large size of the positively charged cation, Fe3+, upsets the stability of the colloid, and the finest solids become entrapped by the precipitated ferric hydroxide. In the overall reaction, ferric sulfate consumes bicarbonate ions (or alkalinity) and can cause a pH reduction at higher dosage levels.
Polyelectrolites refers to all water-soluble organic polymers. The polyelectrolites are long chain molecules, frequently polyamines or polyacrylamides. Their overall charge and size destabilize colloids and provide agglomeration of solids (flocculation). In water treating, the term "polyelectrolyte" is generally used in reference to two types of chemicals. The first type is the polymeric primary coagulant; these chemicals are cationic, with relatively low molecular weight (<500,000). The other type of polyelectrolite is the polymeric flocculant or coagulation aid, which may be anionic, cationic, or approaching a neutral charge. Typical molecular weight may be as high as 20,000,000. Polyelectrolites serve to bridge particles together. Only a small amount of this polymeric chemical is needed to produce a significant effect on the oil droplets and solids. The normal application concentration for this chemical is 1 to 5 ppm.
As the water stream flows through the treatment system, its pressure, temperature, and composition will change. Pressure and temperature changes affect the solubility of the chemical components in water and may form scale. Depending on the composition of the water, various types of scales can be formed in the pipelines, equipment, control system, and pumps. Scale formation leads to equipment failure, plugging, and contamination. The most common types of scales found in produced or seawater systems are carbonate, sulfate, phosphate, ammonium, sulfide, oxide, silica, and metallic-silicate complexes.
Several methods have been developed for determining the scale tendency of water systems. The current trend is to use several different approaches to calculate the water scale tendency and obtain a range of conditions in which scale could form in the system. Once the scale tendency is established, scale inhibitors are selected for treating the system.
Various chemicals have been developed to inhibit scale formation in water. Selection of scale inhibitors is dependent on the type of scale to be inhibited and the operating conditions, such as the temperature and pressure of the system. The commonly used scale inhibitors are classified into the following types.
Chelants. Chelant compounds form soluble complexes with divalent compounds, such as calcium and magnesium, or with trivalent metals. The most common chelants are EDTA and NTA. These compounds are used frequently in steam-generator treatment because they are thermally stable at elevated temperatures. Stoichiometric levels are necessary for the use of chelants in controlling scale formation.
Polyacrylates. The polyacrylates contain the carboxylic acid group. Depending upon its composition, it is thermally stable to a relatively high temperature and can be used to control scale as well as suspended material.
Phosphonates. These organic phosphorous compounds have been used for controlling iron or hardness salts and form inhibitive films along metal surfaces. It is normally thermally stable to 250°F but can go higher in the absence of oxygen.
Polyphosphates. Polyphosphates of various chain lengths are used for controlling hardness and iron scales. They are very effective chemicals; however, their thermal stabilities are lower than the phosphonates.
Depending upon the application, various methods are used for the selection of scale inhibitors. Factors such as thermal stability, absorption characteristics of the environment, and time of exposure are tested to determine a chemical’s effectiveness at in-situ conditions. Commonly used methods are the thermal-stability and dynamic scale-inhibition tests.
Thermal-Stability Test. This method evaluates the thermal stability and scale inhibition at the same time. NACE TM0374-2001 gives the general test procedure.
Dynamic Scale-Inhibition Test. The ability of an inhibitor to prevent scale is its primary function in an application. Dynamic tube-blocking tests permit ranking of inhibitors to prevent scale. Different temperatures can be used to mimic changing field conditions.
Chemical Effect Mechanisms
Scale inhibitors vary in type and mode of action. Individual chemicals operate with one or more of the following mechanisms.
Sequestering. These compounds bind to one of the species that would precipitate, making it unavailable for precipitation. A common example is EDTA, which forms a claw-like arrangement attached to calcium ions called a chelate, preventing it from being precipitated as calcium carbonate or sulfate.
Dispersion. These compounds can actually disperse scale already attached to surfaces. They can be used to clean up scaled systems but must be used with caution because they could result in releasing suspended solids that could block the formation.
Crystal Modifiers. These compounds, such as complex phosphates, interfere with the crystal growth of the scale, preventing further growth.
Threshold Effects. This refers to the ability of many inhibitors to hold considerable quantities of scale-forming compounds in solution when present only in very small concentrations themselves.
Corrosion ProtectionCorrosion is defined as the destruction of metal by either chemical or electrochemical reaction in the given environment. Because piping and processing equipment are normally made of metals that are in contact with produced water or seawater, chemical or electrochemical reactions will occur. The type of metal, water pH, dissolved oxygen, dissolved salts, and acid gases in water all have a significant effect on the corrosion rate, as do temperature, pressure, and fluid velocity.
Corrosion inhibitors reduce the corrosion rate by interrupting the electrochemical corrosion cell setup between the metal and the liquid or by stopping the deterioration of metal by a chemical reaction. One method of interrupting the electrochemical cell is to form a film on the metal surface, which stops the transfer of ions. One method of chemical protection uses an absorption inhibitor, such as a surface-active amine, which forms a chemisorption bond to the metal, rendering it incapable of dissolving into the fluid.
There are two types of film-forming inhibitors—aestivating and precipitating. The aestivating inhibitors promote the formation of a passive film to protect the metal surface. The precipitating inhibitors react with the corroded metal and deposit a barrier film on the metal surface. Phosphates and silicates are precipitating inhibitors.
In addition, various scavenger chemicals have been developed for removing corrosion-aiding components from the produced-water systems. Oxygen and hydrogen sulfide scavengers effectively remove these respective components from the water by combining them into the scavenger chemicals (see Sec. 4.4.9).
Corrosion inhibitors are selected by laboratory or field tests. Laboratory testing and evaluation have the advantage of being quicker and less expensive; however, inhibitor selection should always be verified by a field test. The most commonly used laboratory and field methods are the wheel, copper-ion displacement, and stirred autoclave tests, along with electrical probes and corrosion coupons.
Wheel Test. The laboratory wheel test is the mostly commonly used method in the oil industry. This aparatus consists of an enclosed rotating disc that holds bottles containing the test water, each with corrosion inhibitor in various concentrations, and a steel coupon in each bottle. The disc is spun at 25 to 30 rpm to cause agitation of the fluid and coupons; the temperature inside the enclosure can be varied to match the process conditions. The tested metal coupons are weighed before and after exposure to determine the weight loss.
Copper-Ion Displacement Test. Used to determine the effectiveness of a protective film created by a corrosion inhibitor, in this test, the minimum concentration of inhibitor needed to form a persistent and protective film is determined. The test procedure requires first dipping a shim stock iron metal sample (1/4 × 6 in.) into a 5% NaCl solution for 5 minutes. This metal is then dipped into an inhibitor solution of known concentration for 5 minutes with stirring and finally into a 10% CuSO4 solution for 30 seconds. The results are observed for copper plating with a magnifying glass. This method is subject to temperature limitation, and its results are semiquantitative.
Stirred Autoclave Test. For high-pressure and high-temperature applications, it is necessary to use a high-pressure method, such as the stirred autoclave test. A stirred autoclave can be tested to 500°F and 5,000 psia. In addition, it can be used to test various oil/water ratios and concentrations of H2S and CO2. The test may be performed under either static or dynamic conditions. A schematic diagram of the autoclave test unit is shown in Fig. 4.34.
Electrical Probes. These provide a direct reading of the corrosion rate. Both polarization resistance and electrical resistance-type probes can be used for these evaluations. An electrical probe is the most widely used device for field evaluation. These probes can be applied at any point in the produced-water system to evaluate inhibitor performance and compare it with the background corrosion before application. The probe application is very quick, but it provides a corrosion rate only at the point and time of measurement. In most cases, the probes are used in combination with the corrosion-coupon measurement.
Corrosion Coupons. Corrosion coupons can be put into the operating process to directly measure the corrosion rate. The advantage of the corrosion coupon is that it is exposed to the true condition of the water system and measures the accumulated results for a time. It is especially valuable when the system has multiphase- or transient-flow conditions. The coupons can be placed at various points of the produced-water system; they are made from the metal of interest and placed in the system for a time (usually 1 to 6 months) to measure the accumulated corrosion of the system. The coupons are weighed before and after the exposed period.
Both surface and produced water contain biological constituents (primarily bacteria) that can contaminate the water-treatment or -injection systems. Because bacteria have the ability to multiply rapidly into colonies, they can cause plugging of surface and downhole equipment and injection-well formations, promote corrosion of surface piping and downhole tubulars, and generate H2S that can cause pitting corrosion. Therefore, it is essential to develop means to control bacteria growth in surface-water-treatment systems.
Bacteria are unicellular, microscopic organisms that can be found in a wide variety of conditions, in both oxygen-containing systems (aerobes) and systems without oxygen (anaerobes). The one factor common to all bacteria is their requirement for water, which provides a means of carrying food to the bacterial cells and taking away waste products.
Seawater has predominantly aerobic bacteria, such as iron-oxidizing bacteria, some slime formers, and other bacteria, such as the hydrocarbon oxidizers. The growth of these species will be reduced by the dosing of chlorine (itself a biocide) to the intakes and by the deaeration process. However, anaerobic bacteria, such as sulfate reducers and other slime-forming bacteria, are present in seawater and, following the removal of oxygen and chlorine in the residence/deaeration tank, may proliferate rapidly, causing associated problems including corrosion and biofouling.
API Spec. RP-38 presents two culturing techniques for counting both aerobic and sulfate-reducing (anaerobic) bacteria, and both techniques count planktonic bacteria. "Planktonic" are the bacteria found swimming or floating in the water system. API Spec. RP-38 states that aerobic bacteria greater than 10,000 bacteria/mL and anaerobic bacteria levels greater than 1 bacteria/mL are considered significant if they are associated with physical changes in the system, such as increasing injection pressures, decreasing water quality, and plugging. Current studies indicate that a count of all bacteria types at key points in the system is necessary to determine the extent of the problem and to monitor the treatment progress.
The types of biocide available are varied and are selected on the basis of kill rate to anaerobic bacteria, kill rate to aerobic bacteria, and ability to penetrate surface films. Some of the typical compounds used as biocides include quaternary ammonium compounds, aldehydes, amines, chlorinated phenols, organometallic compounds, and sulfur organic compounds. In seawater systems, chlorine is the primary biocide used.
Chlorine. Many years of operational experience have shown that chlorine is very effective in controlling bacterial growth. Chlorine in water takes on various forms according to the pH of the water. The types of chlorine present in the water include Cl2, HOCL, and OCl–. In a seawater system, it is possible to generate hypochlorite (OCl–) in situ through electrolysis of the seawater, as discussed previously.
Sodium hypochlorite is dosed to the inlet of the lift pumps at such a level as to give a free chlorine residual of 0.5 to 1 ppm Cl2 upon exiting the filter. Chlorine is a very strong oxidizing agent and reacts with many materials. Once it reacts, it is no longer available to kill bacteria. Chlorine may react with ferrous iron, hydrogen sulfide, organic compounds, and sulfite ions (present in the oxygen scavenger chemicals).
To evaluate a biocide, a bacteria culture is first obtained from the field. The culture is usually a mixed strain of the organisms that can grow in the media used. If a field culture is not available, cultures of bacteria can also be obtained from a commercial laboratory. One or more of the following methods are then used to select a biocide.
Bacteriostatic Test. This test is used for preliminary screening of biocides and involves exposing a bacteria sample to a known concentration of biocide. The test is performed in broth bottles with a range of biocide concentrations that are incubated for 15 days. Afterward, the bottles are observed for bacterial growth. The minimum concentration that shows no bacteria growth is the effective concentration.
Planktonic Time Kill Test. This test involves putting the field sample into a known concentration of biocide for a specific contact time, then counting the bacteria that were not killed. The effectiveness of the chemical is determined by comparing the results to a blank determination in which no biocide is present. A biocide concentration that results in a 99% or better kill is considered to be effective. The kill rate is calculated with the lowest number in the population range for the blank and the highest number in the bacteria population range observed for each biocide concentration.
Sessile Bacteria Time Kill Test. This test uses a mild steel coupon that has been exposed to a bacteria culture for at least 14 days. This period is sufficient to allow for the development of a sessile population on the surface of the coupon. The contaminated coupon is then used in the time kill test.
Once a biocide has been selected, a field test is conducted. In general, batch treatment is more economical than continuous treatment. However, the effectiveness and economics of chemicals are dependent on field producing conditions.
It should be noted that generally, because of the enormous complexity and density of microorganisms, there is no single biocide that is completely effective. For this reason, and because bacteria can adapt themselves (i.e., build up an immunity) to a biocide, it is customary to use alternate slugs of different biocides or biocide blends.
Chemical scavengers are used to remove dissolved oxygen from water-flow streams of less than 10,000 B/D. There are a number of compounds commercially available to remove dissolved oxygen, and all can be considered as a source of sulfur dioxide or sulfite. These include sodium sulfite (Na2SO3), sulfur dioxide (SO2), sodium bisulphate (NaHSO3), sodium metabisulfite (Na2S2O5), and ammonium bisulfite (NH4HSO3). Ammonium bisulfite is commonly used on river and aquifer water systems because it is relatively stable to the atmosphere (solutions in storage tanks will not absorb oxygen from the air), and its rate of reaction with dissolved oxygen is catalyzed by the trace of metals, particularly iron, in the water. It is, thus, the most convenient chemical to use. To speed the reaction rate, a catalyst such as cobalt is often required.
Some water systems (e.g., seawater) have a tendency to create foam when subjected to high pressure-drop or turbulence conditions. This foaming is very unpredictable and can cause enormous problems, particularly in deaerator columns. In the deaerator, foaming may result in failure of the level control on the base of the column and reduced oxygen-removal efficiency.
Antifoam chemicals are polyglycols or silicones contained in a solvent that is fully water-soluble or water-dispersible. At dose levels usually less than 1 ppm, they act by decreasing the surface tension of bubbles so that they expand and coalesce. They are dosed to the inlet of the deaerator before the inlet distributor. In water-injection systems, the polyglycols are preferred because silicones produce fine precipitates, which can cause injectivity loss. However, silicones may be required in difficult applications, usually in low-temperature vacuum systems or when the foaming tendency is very high.
Surfactants are normally water-based alkaline cleaners that are biodegradable. These chemicals are used as detergents in cleaning oil films from equipment surfaces. A common use for surfactants is to aid in cleaning media filters. Because of its physical properties, oil is not easily removed from media filters during normal backwashes. To properly remove oil, a surfactant is slug-dosed into the media filter inlet and flushed into the bed. The combination of detergent and air scour breaks the viscous bond between the anthracite and oil and allows the particles to separate. The oil is removed during the subsequent backwash steps.
Material Selection for Water-Treating Equipment
Material Produced-Water Systems
Selection of materials for produced-water-treating equipment must take into account the pressure rating of the application, the corrosivity and erosivity of the fluid, and the end location. The primary problem constituents in produced water are salt, hydrogen sulfide, carbon dioxide, and sand. Proper material selection is critical for long operation life and minimal maintenance. A small increase in capital expenditure for an optimum material selection can greatly reduce the mean time to maintenance or failure, thus greatly saving on operating expenses.
Normal Service Materials
Ordinary carbon steel is by far the most important alloy in the oil and gas industry because it accounts for more than 98% of the construction materials used in produced-water systems. As a general rule, every attempt should be made to use steel, such as modifying the process with corrosion inhibitors in the fluid or coating the steel. Even though the chloride content can be higher than seawater, piping and vessel equipment used to treat normal produced water is usually manufactured from carbon steel because the oxygen level is very low. Carbon dioxide in the water stream may present a problem because it will form carbonic acid, which is corrosive to carbon steel, even in the absence of oxygen. As little as 1 ppm carbon dioxide in pure water will lower the pH to 5.49, sufficient for a corrosion problem. A corrosion inhibitor or coating must be used in this case to protect the carbon steel.
Piping Systems. The most commonly used material for piping systems in produced-water treatment is carbon steel. Piping systems for produced water are normally designed to the American Soc. of Mechanical Engineers (ASME) standard B31.3 for process piping and use ASME specification SA-106 carbon steel piping. Because of its strength, this material can withstand high pressures and is commonly available in diameters up to 48 in.
Steel pipe has excellent impact resistance and flexural strength. It is susceptible to both internal and external corrosion. When oxygen is excluded from the system, which is the normal case for produced water, internal corrosion may not be a problem. External corrosion is normally fought with a coating system. For pipe exposed to salt air, a three-coat epoxy-paint system is often specified. Underwater pipe may be protected by a thin-film-epoxy, coal-tar-epoxy, or extruded-plastic system. Thin-film epoxy is more popular because of its greater toughness to potential handling and installation damage.
Vessel Fabrication. Vessels and other equipment to handle produced water are most commonly fabricated from carbon steel. Small pressure vessels (< 48 in.) can be made from seamless pipe (SA-106), and larger pressure vessels are fabricated from rolled plate (SA-516). These grades of steel exhibit a yield strength of at least 60,000 psi, which can easily be fabricated into inexpensive, large, high-pressure-containing components. Nonpressure-vessel applications normally use carbon steel plate (SA-516 or SA-36).
Much like a carbon steel piping system, the vessels must be protected from internal and external corrosion. Produced water normally contains insignificant amounts of oxygen, which greatly minimizes internal corrosion. If oxygen is present, sacrificial anodes (normally of aluminum) can be used within a pressure vessel. External corrosion is normally combated with a coating system. In offshore, salt-air environments, a three-coat epoxy-paint system is most commonly used.
Materials for Severe Service Environments
Severe service environments are encountered increasingly as oil and gas production embraces more difficult production situations. Materials have been developed to handle highly corrosive well products (CO2 and H2S) at high production temperatures and pressures. The two most common classes of metals used in highly corrosive applications are stainless steels and superalloys. These materials may be expensive; however, they may provide the only acceptable long-term solution.
The most common stainless steels used are 316 and 316L (UNS S31600 and S31603), providing moderate resistance to chloride and H2S and good resistance to CO2. The L grade is used for components that require welding. For higher chloride and H2S resistance, duplex (UNS 31803) and superduplex stainless steel (UNS 32750) are finding increased use. Extreme conditions are being met by the use of Incoloy* 625 (UNS N06625) and 825 (UNS N08825), which are nickel-based superalloys. [UNS refers to the "unified numbering system" that is a standard practice of the American Soc. for Testing and Materials (ASTM) for commercial metals and alloys.]
* Incoloy is a registered trademark of Special Metals Corp.
Materials for Erosion Protection
Material selection for erosion protection (i.e., sand) is dependent on the type of wear exhibited. There are two main mechanisms for wear—impact and sliding abrasion. Impact wear occurs where the particles directly impinge against the material surface from a near-perpendicular angle. These particles may hit the surface once and bounce off. Sliding wear occurs where the particles move parallel to the material surface and rub repeatedly against the material substrate. Each mechanism abrades the material surface differently; therefore, appropriate materials are suggested for each.
Impact Wear. To accommodate impact wear, a material is needed that will absorb the impact without breaking. Leaded tees are used in piping to make 90° turns. The soft lead absorbs particle impact without wearing into the steel pipe. Elastomer rubbers provide good impact resistance but find limited use in produced-water applications because of dissolution in the presence of hydrocarbons. Nitrile rubber overcomes this hindrance because it displays a moderate resistance to hydrocarbons and can be used to internally line vessels or pipe.
Sliding Wear. Material hardness is the main characteristic used to accommodate sliding wear. If the material substrate is harder than the abrading material, ideally, no wear will occur. The most common solid present in produced water is sand, which is primarily quartz (SiO2). The two groups of materials used to handle sliding wear are hard metals and ceramics.
Hard Metals. Metals are used in cases of moderate sliding-wear protection and where some toughness is required. The most economical hard metal is white iron, which is a high iron-carbide-content cast iron. White iron is used for slurry pump impellors and casings, and corrosion-resistant grades are available. A slightly less hard metal that is also commonly used is Stellite**, a cobalt alloy that finds large use in smaller, intricate-wear applications. Both white iron and Stellite are cast materials, difficult to machine, and not as hard as quartz.
Ceramics. The best commercial materials to handle this type of wear are ceramics. Ceramic materials are brittle (and, therefore, hard to work with) and expensive, but in cases of sliding wear, they provide the maximum erosion protection. The most common ceramic used is alumina (Al2O3), which can be cast into intricate sections or made into tiles for hand lining. This is the most common material for manufacturing desander liners. Additional common, though more expensive, ceramics are silicon carbide (SiC) and tungsten carbide (WC). These materials provide 5 to 10 times higher wear resistance than alumina but are correspondingly more expensive. Diamond films provide the best protection possible but find limited use in large-scale erosion protection because of the cost. The ceramics listed above are harder than quartz.
- Mark of Deloro Stellite, Swindon, U.K.
Materials for Seawater Systems
The selection of materials for equipment in seawater treating must take into account the pressure rating of the application, the corrosivity of the fluid, and the end-use location. Seawater contains approximately 3.5% salt (sodium chloride) and is slightly alkaline (pH 8). It is a good electrolyte and can cause severe corrosion. Oxygen content, liquid velocity and temperature, and the presence of biological organisms affect the corrosion rate. In most oil and gas seawater-handling systems, oxygen content is the biggest concern in designing for corrosion protection because the dissolved oxygen greatly accelerates the corrosion rate. Typical pipe-transport velocities are in the range of 3 to 12 ft/sec, which will have a minimal effect on corrosion but will minimize the ability of fouling organisms to attach themselves to the piping materials. Generally, erosion resistance is not a major factor in handling seawater because the solids are not very erosive.
Metals for Piping and Vessels. For untreated seawater, exotic metals such as titanium, Hastelloy C, and copper-nickel (70-30 or 90-10) must be used to prevent severe corrosion. Stainless steel (Type 316 or 304) will exhibit severe pitting in a flowing seawater application. This can be reduced somewhat by upgrading to duplex stainless steel. Vessels can be made of standard carbon steel but must be lined with an internal coating to prevent corrosion. Common materials for internal vessel coating are neoprene rubber or glass-flake-filled, amine-cured epoxy. Both epoxy lining and neoprene are good to 200°F. Standard carbon steel piping can be used on seawater after removal of dissolved oxygen.
Plastic Piping. Plastic pipe is the most common material for low- to moderate-pressure raw seawater service. It has a pressure rating up to 450 psig, depending on the pipe size. Plastic pipe is not susceptible to either internal or external corrosion in seawater service, it has a low friction factor, and its light weight makes it easy to install. In general, plastic pipe can be purchased in accordance with the following API specifications: Spec. 5LE for polyethylene line pipe (PE), Spec. 5LP for thermoplastic line pipe [polyvinyl chloride (PVC) and chlorinated polyvinyl chloride (CPVC)], and Spec. 5LR for reinforced thermosetting resin line pipe (RTRP).
Because of the superior strength and greater resistance to internal pressure and hydrocarbons, fiber-reinforced plastic (FRP) is the most commonly used material for this service. This pipe is available as a filament-wound fiberglass-reinforced vinyl ester material, usually with a resin-rich reinforced liner. It is available up to a 16-in. nominal pipe size and a pressure rating from 150 to 450 psig (this decreases with pipe diameter). FRP pipe has the disadvantage of being very brittle, which can lead to damage during installation. Ultraviolet (UV) light, or sunlight, can degrade the physical strength of FRP by attacking the resin-glass bond. Pigments or dyes are incorporated into the resin to form a barrier for UV penetration into the laminate, which maintains degradation to a surface-only attack. In certain cases, an overwrap, such as an organic veil layer, can be used to provide even greater UV resistance.
Materials for Steam Systems
Of primary concern with steam transport systems are temperature and pressure. Corrosion is usually not a major issue in clean, dry steam systems because the dissolved solids and gases are removed before steam generation. Corrosion can be a problem if the steam is not fully dried and if the water content concentrates boiler water chemicals. Plain carbon steel is resistant to general corrosion by clean, deaerated steam up to 850°F. For higher temperatures, high-strength, low-alloy (HSLA) steel is needed, such as 2 1/4Cr-1Mo, which is good to 1,200°F. Generally, erosion resistance is not a major factor in these systems because steam from a boiler is free of solids. Proper material selection is critical for long operation life and minimal maintenance.
|A||=||membrane area, ft2|
|Ad||=||deck area, ft2|
|Bp||=||width of the plate section perpendicular to the axis of water flow, ft|
|c||=||solids concentration, fraction by volume|
|dd||=||droplet diameter, μm|
|di||=||vessel ID, in.|
|di||=||pile ID, in.|
|dmax||=||droplet diameter, μm|
|dp||=||dispersed particle diameter|
|D||=||ID of cyclone, in.|
|fV||=||volume fraction of the dispersed phase|
|F||=||factor accounting for turbulence and short-circuiting|
|g||=||g-force acceleration factor|
|gc||=||gravity acceleration constant|
|hf||=||height of flume, ft|
|K||=||permeate flow coefficient at standard temperature, gal/D-psi-ft2|
|Ks||=||empirical settling constant|
|KT||=||membrane temperature-correction factor|
|L||=||length of the plate section parallel to the axis of water flow, ft|
|Lbs||=||length of baffle section, ft|
|Le||=||effective length in which separation occurs, ft|
|Lp||=||perpendicular distance between plates, in.|
|Nc||=||number of nonflow cycles that a particle sees as it traverses the baffle section|
|qr||=||rainfall rate, in./hr|
|qw||=||water flow rate, BWPD|
|qWD||=||washdown rate, B/D|
|Qf||=||feed volumetric flow rate, m3/s|
|Qpf||=||permeate flow, gal/D|
|tc||=||time valves are closed|
|tr||=||retention time, minutes|
|vw||=||velocity of water, ft/s|
|x98||=||particle size at 98% efficiency, m|
|Zp||=||height of the plate section perpendicular to the axis of water flow, ft|
|Zw||=||height of water column, ft|
|Δp||=||pressure drop, psi|
|Δpavg||=||average transmembrane pressure drop, psi|
|Δγ||=||difference in specific gravity relative to water|
|Δγow||=||difference in specific gravity between oil and water|
|Δρ||=||difference in density of the dispersed particle and the continuous phase|
|σ||=||surface tension, dynes/cm|
|ρl||=||liquid density, kg/m3|
|ρs||=||solid density, kg/m3|
|μL||=||viscosity of the continuous phase (liquid)|
|μw||=||water viscosity, cp|
|θ||=||angle of the plate with the horizontal|
- Collins, A.G. 1987. Properties of Produced Waters. In Petroleum Engineering Handbook, H.B. Bradley ed., Ch. 24. Richardson, Texas: SPE.
- Arnold, K. and Stewart, M. 1991. Surface Production Operations. In Design of Oil-Handling Systems and Facilities, Vol. 1, Ch. 7. Houston, Texas: Gulf Publishing Co.
- Oil-Water Separator Process Design. 1975. In Manual on Disposal of Refinery Wastes, Volume on Liquid Wastes, Ch. 5. Dallas, Texas: API.
- Ditria, J.C. and Hoyack, M.E. 1994. The Separation of Solids and Liquids With Hydrocyclone-Based Technology for Water Treatment and Crude Processing. Presented at the SPE Asia Pacific Oil and Gas Conference, Melbourne, Australia, 7-10 November 1994. SPE-28815-MS. http://dx.doi.org/10.2118/28815-MS.
- Flanigan, D.A., Stolhand, J.E., Shimoda, E. et al. 1992. Use of Low-Shear Pumps and Hydrocyclones for Improved Performance in the Cleanup of Low-Pressure Water. SPE Prod Eng 7 (3): 295-300. SPE-19743-PA. http://dx.doi.org/10.2118/19743-PA.
- Rye, S.E. and Marcussen, E. 1993. A New Method for Removal of Oil in Produced Water. Presented at the Offshore Europe, Aberdeen, United Kingdom, 7-10 September 1993. SPE-26775-MS. http://dx.doi.org/10.2118/26775-MS.
- Faucher, M. and Sellman, E. 1998. Produced water deoiling using disk stack centrifuges. Paper presented at the API Tech Chapter 1998 Produced Water Management Forum, Lafayette, Louisiana, November.
- Neff, J.M. and Stout, S. 2002. Predictors of Water-Soluble Organics (WSOs) in Produced Water—A Literature Review. Washington, DC: API.
- Caudle, D.D. and Stephenson, M.T. 1988. The Determination of Water Soluble Organic Compounds in Produced Water. Report for the Offshore Operators Committee Task Force on Water Soluble Organic Compounds in Produced Water, June.
- Stephenson, M.T. 1992. Components of Produced Water: A Compilation of Industry Studies. J Pet Technol 44 (5): 548-550, 602-603. SPE-23313-PA. http://dx.doi.org/10.2118/23313-PA.
- Georgie, W.J., Bryne, K.H., and Kjaerland, G. 1992. Handling of Produced Water: Looking to the Future. Presented at the European Petroleum Conference, Cannes, France, 16-18 November 1992. SPE-25040-MS. http://dx.doi.org/10.2118/25040-MS.
- Svarovsky, L. 1984. Hydrocyclones, 96-97. London: Technomic Publishing Co. Inc.
- Rawlins, C.H., Staten, S.E., and Wang, I.I. 2000. Design and Installation of a Sand Separation and Handling System for a Gulf of Mexico Oil Production Facility. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 1-4 October 2000. SPE-63041-MS. http://dx.doi.org/10.2118/63041-MS.
- Tao, F.T., Curtice, S., Hobbs, R.D. et al. 1993. Conversion of Oilfield Produced Water Into an Irrigation/Drinking Quality Water. Presented at the SPE/EPA Exploration and Production Environmental Conference, San Antonio, Texas, 7-10 March 1993. SPE-26003-MS. http://dx.doi.org/10.2118/26003-MS.
- Tao, F.T. et al. 1993. Reverse Osmosis Process Successfully Converts Oil Field Brine into Freshwater. Oil & Gas J 91 (38): 88.
- VandeVenter, L.W., Ford, B.R., and Vera, M.W. 1989. Innovative Process Provides Cogeneration Power Plant with the Ability to Use Oil Field Water. Paper presented at the 1989 Annual International Water Conference, Pittsburgh, Pennsylvania, 23–25 October.
- Performance data of Filmtec FT-30 membrane, Dow Chemicals.
- Performance data of B-9 Hollow Fiber membrane, DuPont.
- Iler, R.K. 1979. The Chemistry of Silica, 42. New York City: John Wiley and Sons.
- Jones, J. and Williams, R.L. 1993. A Two-Phase Flow-Splitting Device That Works. SPE Prod & Oper 8 (3): 197-202. SPE-21532-PA. http://dx.doi.org/10.2118/21532-PA.
- Hong, K.C. and Griston, S. 1995. Two-Phase Flow Splitting at an Impacting Tee. SPE Prod & Oper 10 (3): 184-190. SPE-27866-PA. http://dx.doi.org/10.2118/27866-PA.
- Stoy, J.R. et al. 1995. Method and Apbrtus for Controlling Phase Splitting at Branch Pipe T Junctions. US Patent 5,415,195.
- Berger, E.L., Kolthoff, K.W., Schrodt, J.L.G. et al. 1997. The SpliTigatorTM: A Device for the Mitigation of Phase Splitting. Presented at the International Thermal Operations and Heavy Oil Symposium, Bakersfield, California, 10-12 February 1997. SPE-37516-MS. http://dx.doi.org/10.2118/37516-MS.
- Pauley, J.C., Wheeler, M.C., and Schrodt, J.L.G. 1998. The SpliTigator: Enhancing the Value of Steamflooding. Paper 1998.159 presented at the 7th UNITAR International Conference on Heavy Crude and Tar Sands, Beijing, October.
- Sims, J.C. 1998. Texaco’s Steam Flow Research Facility. Paper 1998.161 presented at the 7th UNITAR International Conference on Heavy Crude and Tar Sands, Beijing, October.
- Snorre water injection tries new treatment technology. 1991. Ocean Industry (January): 22.
- Daniels, I. 1995. Developments in compact deoxygenation: the MINOX ‘compact tower’ process. Paper presented at the 4th International Water Management Offshore Conference, Aberdeen, 3–6 April.
- Henriksen, N., Nord, L., and Kjøberg, S.A. 1987. Efficient New Processing System for Water Deoxygenation. Presented at the Offshore Technology Conference, Houston, Texas, - 1987. OTC-5591-MS. http://dx.doi.org/10.4043/5591-MS.
- Heatherly, M.W., Howell, M.E., and McElhiney, J.E. 1994. Sulfate Removal Technology For Seawater Waterflood Injection. Presented at the Offshore Technology Conference, Houston, Texas, - 1994. OTC-7593-MS. http://dx.doi.org/10.4043/7593-MS.
- Vu, V.K., Latapie, D., and Davis, R.A. 1999. Barite Scale Prevention for Elf Angola’s Girassol Field Using Sulphate Removal Technology. Paper presented at the Deep Offshore Technology Conference, Stavanger, 19–21 October.
- NACE TM0374-2001, Standard Test Method Laboratory Screening Tests to Determine the Ability of Scale Inhibitors to Prevent the Precipitation of Calcium Sulfate and Calcium Carbonate from Solution (for Oil and Gas Production Systems ). 2001. Houston, Texas: NACE.
- API RP-38, Recommended Practice for Biological Analysis of Subsurface Injection Waters. 1975. Washington, DC: API.
- Fontana, M.G. 1986. Corrosion Engineering, 389-392. New York City: McGraw-Hill Book Co. Inc.
- Condensate Corrosion, H2OChem.com website. 2001. www.h2ochem.com/info/tips/boilers/boiler06.asp.
- Billmeyer, F.W. 1971. Textbook of Polymer Science, second edition, 546. New York City: Wiley-Interscience.
- Erosion Resistance of Hexoloy® SA Silicon Carbide. 2001. Niagara Falls, New York: Carborundum Corp.
- Fontana, M.G. 1986. Corrosion Engineering, 373-378. New York City: McGraw-Hill Book Co. Inc.
- Corrosion Basics, 151. 1984. Houston, Texas: Natl. Assn. of Corrosion Engineers.
- Billmeyer, F.W. 1971. Textbook of Polymer Science, second edition, 548. New York City: Wiley-Interscience.
- Corrosion Basics, 151. 1984. Houston, Texas: Natl. Assn. of Corrosion Engineers.
- Weathering and UV Resistance of Fiberglass Piping Systems, Bull. FP473E. 1997. Houston: Ameron Intl.
- Corrosion Basics, 169-171. 1984. Houston: NACE Intl.
SI Metric Conversion Factors
|Å||×||1.0*||E – 01||=||nm|
|°API||141.5/(131.5 + °API)||=||g/cm3|
|bbl||×||1.589 873||E – 01||=||m3|
|Btu||×||1.055 056||E + 00||=||kJ|
|cp||×||1.0*||E – 03||=||Pa s|
|dyne||×||1.0*||E – 02||=||mN|
|ft||×||3.048*||E – 01||=||m|
|ft2||×||9.290 304*||E – 02||=||m2|
|ft3||×||2.831 685||E – 02||=||m3|
|°F||(°F – 32)/1.8||=||°C|
|gal||×||3.785 412||E – 03||=||m3|
|in.||×||2.54*||E + 00||=||cm|
|in.3||×||1.638 706||E + 01||=||cm3|
|lbm||×||4.535 924||E − 01||=||kg|
|psi||×||6.894 757||E + 00||=||kPa|
Conversion factor is exact.