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Most produced water contains salts that can cause problems in production and refining, when solids precipitate to form scale on process equipment. The salts also accelerate corrosion in piping and equipment. The salt content of crude oil almost always consists of salt dissolved in small droplets of water that are dispersed in the crude. Sometimes the produced oil contains crystalline salt, which forms because of pressure and temperature changes and because of stripping of water vapor as the fluid flows up the wellbore and through the production equipment.

Salinity of produced brine

The salinity of produced brine varies widely, but for most produced water, it ranges from 5,000 to 250,000 ppm of equivalent NaCl. Crude oil that contains only 1.0% water with a 15,000-ppm salt content has 55 lbm of salt per 1,000 bbl of water-free crude. The chemical composition of these salts varies, but nearly always is mostly NaCl, with lesser amounts of calcium and magnesium chloride. Salt content limits might be by either of the following:

  • transportation requirements in the production field or shipping terminal
  • concerns over corrosion, fouling, or catalyst degradation in the refinery

Purpose of a desalting system

The purpose of a desalting system is to reduce the salt content of the treated oil to acceptable levels. When the salinity of the produced brine is not too high, merely ensuring that there is a low fraction of water in the oil can reduce salt content. In that case, the terms desalting and emulsion treating effectively have the same meaning, and the concepts and equipment can be used.


Salt specification

The required maximum concentration of water in oil to meet a known salt specification can be derived from Eq. 1:

Vol3 page 078 eq 001.PNG(Eq. 1)

where

Cso = the salt content of the oil, lbm/1,000 bbl

Csw = the concentration of salt in produced water, ppm

γw = the specific gravity of produced water

fw = the volume fraction of water in crude oil

Desalter

In produced brine with a high salt concentration, it might not be possible to treat the oil to a low enough water content ( < 0.2% is difficult to guarantee). A desalting system such as the one shown schematically in Fig. 1 consists of a mixing device (in which fresh water is used to wash the crude oil) and any of the electrostatic treating systems described below (which then are used to dehydrate the oil to a low water content). Mixing dilution water with the produced water lowers the effective value of Csw in Eq. 1. If a single-stage desalting system requires too much dilution water or is unable to reach the desired salt concentration, then a two-stage system is used, such as the one shown schematically in Fig. 2.


Mixing efficiency

The mixing efficiency is the fraction of wash water that actually mixes with the produced water. In effect, the remainder of the water bypasses the desalting stage and is disposed of as free water. A mixing efficiency of 70 to 85% is considered the highest attainable. Because mixing efficiency depends on the probability of contact between the dilution water and entrained brine, it varies with the drop population in the crude oil. The effectiveness of this dilution reaction is determined by a variety of influences, e.g.:

  • mixing intensity and duration
  • diffusional transport
  • interdrop-collision frequency

Dilution water

Enough dilution water must be available to satisfy mass-balance requirements for diluting the dispersed brine enough that the salt specification can be met while considering the residual basic sediment and water (BS&W) in the oil. Dilution-water quality also must be considered and can be a problem because of high pH, the presence of surfactants, and other conditions that can lead to increased emulsion stability.[1]

Obviously, to remove salt, the dilution water must have low enough salt content to achieve the required equilibrium concentration in the residual entrained water. Less obvious but also important is the need for dilution water to be of sufficient quality to avoid contributing to emulsification. Streams that contain considerable amounts of the following materials should not be used:

  • coke particles
  • suspended solids
  • iron sulfide

and/or

  • emulsified oil

Neither should streams contain traces of surfactant chemicals or excess caustic soda. Limiting ammonia to < 200 ppm avoids fouling and corrosion in the crude-distillation unit overhead and limits pH excursions. Preferably, the pH of the dilution water should be < 9.0, and provision for acid injection for pH control should be made if higher values are expected. High pH might enhance the formation of stable emulsions, whereas pH values < 6.5 might raise concerns about corrosion within the desalter vessel. The dilution water should contain < 0.02 ppm oxygen and < 1 ppm fluoride and should be low in:

  • sodium salts
  • suspended solids
  • hardness ions

Water recycle

Contact efficiency, or collision frequency, between drops of dispersed brine and dilution water is proportional to the drop populations. Increasing the number of dilution-water drops yields more efficient contact. Because quantities of available dilution water usually are limited, the effluent water often is recycled to increase drop population. Effluent water from the second-stage desalter is much less saline than the dispersed brine, so that it can be used for dilution water for the first stage, as shown in Fig. 2. This is known as interstage recycling.

Another recycle scheme, intrastage recycling, was previously limited because it requires mixing of the recycle water and the fresh water, thereby lessening the effectiveness of the fresh water; however, the advent of counterflow desalting made it feasible to inject recycle water ahead of the mixing valve of a single-stage desalter and to inject the fresh water into the counterflow distributors, thereby increasing the drop population without raising the salinity of the fresh dilution water.

With all recycle streams, be careful as to the quality of the water: if interface sludge or mud-wash solids are allowed to recycle, they might produce stable emulsions and cause rapid buildup of the interface-sludge layer. If this problem appears likely to occur, the recycle should be taken after an effluent water-cleaning device.

Effluent-water quality

The effluent water from a properly operating desalter, exclusive of mud-wash cycles, is frequently < 250 ppm oil in water. Field dehydrators might carry more oil in their effluent water, depending on the conditions of the crude oil being treated. Further clarifying the water requires additional retention time and different chemical treatment, both of which are more economically provided externally to the desalter vessel.

Water solubility in crude oil

Water exhibits an appreciable solubility in crude oil at elevated temperatures. A rule of thumb is that approximately 0.4% water might be dissolved at temperatures of approximately 300°F, as shown in Fig. 3.12 for a variety of crude oils. A desalter or dehydrator can separate only dispersed water and has no effect on water that is soluble at operating conditions; however, a significant quantity of soluble water can precipitate when the output is sampled through a sample cooler and the sample is further cooled while awaiting analysis. This precipitated water might be erroneously assumed to be dispersed water in the effluent oil.

A more insidious aspect of water solubilization occurs in the preheat train ahead of a desalter. As the oil is heated to operating temperature, water from the dispersed brine is solubilized into the oil phase while leaving behind precipitated salts. This can cause the formation of crystalline salt, which is very difficult to remove from the oil. Injecting fresh water ahead of the preheat train can help offset this problem and can alleviate heat exchanger fouling.

Incompatibilities of oils

Crude oils might contain semisoluble organic materials (e.g., waxes and asphaltenes), which can precipitate during processing and cause the production of troublesome sludges or the stabilization of emulsions. Wax precipitation can be controlled through temperature and chemicals, but asphaltenes are more troublesome. By definition, asphaltenes precipitate in hydrocarbons of the molecular weight of pentane; therefore, if light hydrocarbons are recycled as slop oil into a vessel that is processing asphaltic crude oil, serious sludge precipitation might result.

Analytical methods

Several procedures are currently in use, depending on:

  • the values to be measured
  • the accuracy required
  • the equipment available

BS&W measurements

BS&W measurements usually are done by centrifugation, as discussed in Sampling and Analyzing Crude Oil Emulsions and as described in ASTM D-96[2] and ASTM D-4007.[3] Salt analysis by conductivity, as described in ASTM D-3230,[4] is a widely used technique for process monitoring and quality control. It is reliable at salt concentrations > 5 lbm/1,000 bbl and, with care, can be used at concentrations of from 2 to 5 lbm/1,000 bbl. At low salt levels, oil conductivity becomes a function of water content and pH, as well as of salt content. Because the ions responsible for pH changes are 2.6 to 4.6 times as conductive as chloride, the effects of minor pH changes far outweigh those of chloride-concentration changes. Other problems (e.g., variation in the composition of the salt mix in oils) also help to preclude the use of this method as a reliable indicator of absolute desalter performance at low effluent salt contents unless exacting calibration procedures are followed.

Laboratory results usually are obtained by analyzing total chloride ion, converting it to equivalent sodium chloride, and reporting it in lbm/1,000 bbl. At salt levels of 2 lbm/1,000 bbl and below, achieving meaningful and reproducible results requires great care. Of the several available salt-analysis methods, extraction and analysis of soluble salts has proved to be the most reliable, the one least subject to interference from other constituents.

Extraction and analysis

Extraction and analysis of soluble salts involves diluting an oil sample with xylene and extracting the mixture with boiling deionized water. The extraction funnels then are placed in a water bath at 140 to 160°F for phase separation. If necessary, one the following methods may be used to enhance separation:

  • acidification
  • electrostatic cells
  • chloride-free emulsion breaker

Aqueous layer

The aqueous layer is removed and filtered if it is cloudy or if entrained oil is present. Then it is titrated with dilute silver nitrate (0.01N), using a chromate indicator under incandescent lighting. The titration procedure is known as the Mohr method and is described in API RP 45.[5] Endpoint recognition requires a practiced eye when using dilute titrant. If available, ion chromatography also may be used for chloride determination. Ion chromatography is extremely accurate for determining small quantities of chloride, but its equipment is more expensive than titration equipment. Because of the widespread occurrence of chloride in nature and the very small quantity being measured in this method, take care to avoid contaminating the sample during handling.

Spectrophotometric determination

Another commonly used method is the spectrophotometric determination of the following metals:

  • sodium
  • calcium
  • magnesium

These techniques use atomic absorption or inductively coupled plasma and are accurate and highly automated; however, they do not distinguish between water-soluble salts and those that exist primarily in the oil phase (e.g., metal-organic compounds or mineral precipitates), so their results might relate poorly to desalter performance.

Nomenclature

Cso = the salt content of the oil, lbm/1,000 bbl
Csw = the concentration of salt in produced water, ppm
γw = the specific gravity of produced water
fw = the volume fraction of water in crude oil

References

  1. Warren, K.W. 1993. Reduction of Corrosion through Improvements in Desalting. Paper presented at the Benelux Refinery Symposium, Lanaken, Belgium, 2–3 December.
  2. ASTM D-96-88 (withdrawn 2000), Standard Test Methods for Water and Sediment in Crude Oil by Centrifuge Method (Field Procedure). 1988. West Conshohocken, Pennsylvania: ASTM.
  3. ASTM D-4007-02, Standard Test Methods for Water and Sediment in Crude Oil by Centrifuge Method (Laboratory Procedure). 2002. West Conshohocken, Pennsylvania: ASTM.
  4. ASTM D-3230-05, Test Method for Salts in Crude Oil (Electrometric Method). 2005. West Conshohocken, Pennsylvania: ASTM.
  5. API RP-45, Recommended Practice for Analysis of Oilfield Waters, third edition. 1998. Washington, DC: API.

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See also

PEH:Emulsion Treating

Emulsion treating

Separating emulsions

Sampling and analyzing emulsions

Emulsion treating subsystems

Emulsion treating methods

Operational considerations of emulsion treating

Economics of treating emulsions

Produced water properties