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Operational considerations of emulsion treating

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Standard emulsion treating procedures, equipment, and systems used during primary and secondary oil production might be inadequate for treating the emulsions encountered in EOR projects. EOR methods of oil production might cause the production of emulsions that do not respond to treatment that normally is used in primary- and secondary-oil-production operations.


EOR methods

  • in-situ combustion and steam,
  • CO2
  • caustic
  • polymer
  • micellar (surfactant/polymer) floods

The emulsions from EOR projects usually are treated independently of the primary and secondary emulsions from the same fields. Emulsion-treating procedures, equipment, and systems have been and continue to be developed for use in these EOR projects.

Water produced with emulsions

Even though a normal water in oil emulsion exists in the oil production system, produced water that is separated from crude oil usually contains small quantities of oil. This oil has been divided into small particles and dispersed in the water by agitation and turbulence caused by:

  • flow in the formation, into the wellbore, and through equipment
  • reciprocation of sucker rods
  • surface transfer pumps

These small particles of oil are suspended in the water by

  • mechanical forces
  • chemical forces
  • electrical forces

In most systems, the amount of oil in the untreated produced water varies from an average low of 5 ppm to an average high of 2,000 ppm; however, in some water systems, oil contents as high as 20,000 ppm (2.0%) have been observed. These oil particles usually are between 1 and 1,000 μm in diameter, with most ranging between 5 and 50 μm.

Removal of oil from produced water

Various methods can be used to remove oil from the produced water:

  • chemicals
  • heat
  • gravity settling [skim tanks, American Petroleum Institute (API) separators, etc.]
  • coalescence (plate, pipe/free flow)
  • tilted plate (corrugated) interceptors
  • hydrocyclones
  • flotation
  • flocculation
  • filtering

The page on Water Treating Facilities discusses the details of deoiling the produced water.

Burners and fire tubes

The design of burners and fire tubes is important because of the high cost of fuel and the operating problems that can occur when they malfunction. The burner should provide a flame that does not impinge on the walls of the fire tube, but that is almost as long as and is concentric with the fire tube. If the flame touches the fire-tube wall, hot spots can develop, which can lead to premature failure.

Burners should not be allowed to cycle on and off frequently because thermal stresses caused by temperature reversals can damage the fire tube. The combustion controls should be accessible and designed so that the operator can adjust the air and gas easily to achieve the optimum flame pattern and peak combustion efficiency.

Safety devices

A reliable pilot burner is required. Many operators and regulatory agencies require burner safety-shutdown valves that will shut off fuel to the burner in case of pilot failure.

API RP 14C[1] contains a basic description of recommended safety devices needed for fire- and exhaust-heated units. Consideration should be given to installing safety devices on onshore and offshore fired treaters. Such safety devices include:

  • process high-temperature shutdown devices
  • burner-exhaust high-temperature shutdown devices
  • low-flow devices and check valves for heat exchangers
  • high- and low-pressure shutdown sensors
  • pressure-relief valves
  • flame arresters
  • fan-motor-starter interlocks on forced-draft burners
  • etc.

Fuel gas scrubber

Every gas-fired crude-oil heating unit should use fuel gas from which liquids have been “scrubbed.” In large facilities, a central fuel-gas scrubber or filter can provide such fuel gas to all fired units. Many small facilities are equipped with individual fuel-gas-scrubber vessels for each fired unit. These individual scrubbers typically are 8 to 12 in. in diameter and 2 to 4 ft tall, and contain a float-operated shutoff valve. If liquid enters the scrubber, the float closes a valve and stops gas flow to the burners of the heating unit, thus preventing oil from entering the combustion chamber and thus possibly preventing a fire.

Heat transfer

Most fire tubes that transfer heat to crude oil or emulsion are sized to transfer 7,500 Btu/hr per ft2, although some manufacturers use heat-transfer rates as high as 10,000 Btu/hr per ft2. Fire tubes that transfer heat to the water-wash section of a treater, such as in a vertical treater, are sized for 10,000 Btu/hr per ft2, although some manufacturers use heat-transfer rates as high as 15,000 Btu/hr per ft2. These higher rates should be used with caution, though, because they can be overly optimistic and thus might lead to undersizing of the required fire-tube area.

Preventive maintenance

The following equipment should be on a schedule of preventive maintenance, including periodic inspection and cleaning as required:

  • temperature controller
  • fuel-control valve
  • pilot burner
  • main burner
  • combustion-safety controls
  • fuel-gas scrubber

Deposit removal

Deposits of soot, carbon, sulfur, and other solids should be removed from the combustion space periodically to prevent heating-capacity reduction and combustion-efficiency loss. On oil-fired units, the following should be inspected and maintained periodically:

  • combustion controls
  • burner nozzles
  • combustion refractory
  • air/fuel-control linkages
  • oil pump
  • oil preheater
  • pressure and temperature gauges
  • O2 and/or CO2 analyzers

Corrosion

Emulsion-treating equipment that handles corrosive fluids should periodically be inspected internally to determine whether remedial work is required. Extreme cases of corrosion might require a reduction in the working pressure of the vessel, or repair or replacement of vessel and piping. Ultrasonic tests can measure the wall thickness of vessels and piping to detect the existence and extent of corrosion.

Controlling corrosion

Mitigating or controlling corrosion of emulsion-treating equipment usually is accomplished by:

Exclusion of Oxygen

Corrosion rates in most oilfield applications can be kept low if O2 is excluded from the system. Take care in the process design to install and maintain gas blankets on all tanks and to exclude rainwater from the system. Recycled water from sump systems and storage tanks is a prime source for O2 entry into the process.

Corrosion Inhibitors

Corrosion inhibitors are materials that, when added in small amounts to an environment that potentially is corrosive to a metal or alloy, effectively reduce the corrosion rate by diminishing the tendency of the metal or alloy to react with the solution. As liquid solutions or compounds, inhibitors can be injected into the flow stream in the flowline, manifold, or production system. The potential for corrosion inhibitors to act as emulsifying agents should be recognized when they are applied.

Cathodic Protection

Sacrificial galvanic anodes commonly are used for cathodic protection. They are made of a metal the relative position of which in the galvanic series causes it to provide sacrificial protection to the steel vessel. Most galvanic anodes that are used in emulsion treaters are 3 to 6 in. in diameter and 3 to 4 ft long, and usually are sized to last 10 to 20 years. Multiple anodes usually are installed in each vessel. They are considered expendable and always are installed in the vessel through a flange or quick coupling so that they can be replaced easily when expended.

The galvanic anodes must be installed so that they are immersed in the water, which serves as an electrolyte. They will not protect the treater if they are immersed in the oil. The anodes must “see” all metal surfaces that are to be protected (i.e., there must be no obstructions between the anodes and the surfaces they are to protect). Each anode should be located as near as is practical to the center of the compartment or area they are to protect.

An impressed-electric-current cathodic-protection system also can be used to inhibit corrosion. It is a direct electric current that is supplied by a device that uses a power source external to the electrode system. The DC current can be obtained by rectifying an AC current. When resistivity of the electrolyte is > 25 Ω•cm, an impressed-current system should be considered; however, impressed-current systems are difficult and costly to maintain and usually require skilled technicians.

Electrical current-density requirements for cathodic protection of emulsion-treating vessels usually range from 5 to 40 mA/ft2 of bare-water-immersed steel.

Internal Coating. Emulsion-treating vessels can be coated internally for protection from corrosion. It is important that the internal surfaces and the welds of the vessels be properly prepared to receive the coating. A coating system must be able to withstand the physical and chemical environment to which it will be exposed. Also among the very important considerations are:

  • coating specifications
  • application techniques
  • final inspection

Coating alone should not be relied on to prevent corrosion, though, because most coating systems contain some “holidays” (breaks in the coating) or are damaged in shipping or installation.

Steel tanks can be galvanized or lined in the field with fiberglass or other coatings. Some operators use fiberglass tanks in their emulsion-treating process, whereas others feel that using fiberglass creates an unnecessary fire hazard.

Special Metallurgy

In particularly severe environments, such as where large quantities of CO2 are expected and where O2 cannot be eliminated from the system practically, corrosion can be minimized by using stainless-steel vessels or an internal stainless cladding in carbon-steel vessels. In most low-pressure applications, stainless-steel vessels are less expensive than clad vessels. It might also be less expensive to use a stainless-steel vessel than one that is internally coated because of the labor required to prepare and coat the internal surfaces of the vessel.

References

  1. API RP 14C, Recommended Practice for Analysis, Design, Installation and Testing of Basic Surface Safety Systems on Offshore Production Platforms, seventh edition. 2001. Washington, DC: API.

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