Ken Arnold

Chapter 5 – Three-Phase Oil and Water Separation

Publisher Summary This study explains the concepts, theory, and sizing equations for the separation of two immiscible liquid phases (in this case, those liquids are normally crude oil and produced water). “Three-phase separator” and “free-water knockout” are terms used to describe pressure vessels that are designed to separate and remove the free water from a mixture of crude oil and water. Because flow normally enters these vessels directly from either a producing well or a separator operating at a higher pressure, the vessel must be designed to separate the gas that flashes from the liquid as well as separate the oil and water. The term “three-phase separator” is normally used when there is a large amount of gas to be separated from the liquid, and the dimensions of the vessel are determined by the gas capacity equations. “Free-water knockout” is generally used when the amount of gas is small relative to the amount of oil and water, and the dimensions of the vessel are determined by the oil–water separation equations, which is also briefly discussed in this chapter. The basic design aspects of three-phase separation are identical to those discussed for two-phase separation. The only additions are that more concern is placed on liquid-liquid settling rates and that some means of removing the free water must be added. Liquid-liquid settling rates are also discussed later in this chapter. Water removal is a function of the control methods used to maintain separation and removal from the oil. Several control methods are applicable to three-phase separators. The shape and diameter of the vessel will, to a degree, determine the types of control used.

Produced Water Treating Systems

The purpose of this chapter is to present the engineer with a procedure for selecting the appropriate type of equipment for treating oil from produced water and to provide the theoretical equations and empirical rules necessary to size the equipment. When this design procedure is followed, the engineer will be able to develop a process flow sheet, determine equipment sizes, and evaluate vendor proposals for any wastewater treating system once the discharge quality, the produced water flow rate, the oil specific gravity, the water specific gravity, and drainage requirements are determined. When hydrocarbons (crude oil, condensate, and natural gas) are produced, the well stream typically contains water produced in association with these hydrocarbons. The produced water is usually brine, brackish, or salty in quality but in rare situations may be nearly “fresh” in quality. The water must be separated from the hydrocarbons and disposed of in a manner that does not violate established environmental regulations. Typically, the produced water is separated from the hydrocarbons by passing the well stream through process equipment such as three-phase separators, heater-treaters, and/or a free-water knockout vessel. These gravity separation devices do not achieve a full 100% separation of the hydrocarbons from the produced water. Furthermore, the study briefly explains offshore operations and onshore operations, characteristics of produced water, scale removal, and many other concepts.

Part 3 – Glycol Maintenance, Care, and Troubleshooting

Publisher Summary This chapter deals with glycol maintenance and care. Prevention and control programs should include system monitoring through corrosion coupons and glycol analysis (pH and iron). Three steps in combating corrosion in glycol systems are: using an effective corrosion inhibitor in both the liquid and vapor phases, using corrosion resistant alloys (CRA) in construction, and keeping the unit clean to prevent acid formation due to contamination. Operating and corrosion problems usually occur when the circulating glycol gets dirty. To achieve a long, trouble-free life from the glycol, it is necessary to recognize these problems and know how to prevent them. Some of the major areas are oxidation, thermal decomposition, pH control, salt contamination, hydrocarbon, sludge, and foaming. Excessive turbulence and high liquid-to-vapor contacting velocities usually cause the glycol to foam. The best way to prevent foaming is proper care of the glycol, such as effective gas cleaning ahead of the glycol system and good filtration of the circulating solution. Even the best preventive maintenance program does not guarantee that the dehydration unit will operate trouble-free. The most obvious indication of a unit malfunction is high water content (dew point) of the outlet stream. High water content is brought about by insufficient glycol circulation and reconcentration of the glycol. These problems can be caused by a variety of contributing factors such as mechanical causes and existing operating conditions for which the equipment was not designed.

Two-Phase Oil and Gas Separation

This chapter discusses the requirements of good separation design and how various mechanical devices take advantage of the physical forces in the produced stream to achieve good separation Separators are sometimes called “gas scrubbers” when the ratio of gas rate to liquid rate is very high. A “slug catcher,” commonly used in gas gathering pipelines, is a special case of a two-phase gas–liquid separator that is designed to handle large gas capacities and liquid slugs. Some operators use the term “traps” to designate separators that handle flow directly from wells. In any case, they all have the same configuration and are sized in accordance with the same procedure. Separators are classified as “two-phase” if they separate gas from the total liquid stream and “three-phase” if they also separate the liquid stream into its crude oil and water components. Separators are designed and manufactured in horizontal, vertical, spherical, and a variety of other configurations. Each configuration has specific advantages and limitations. Selection is based on obtaining the desired results at the lowest “life-cycle” cost. Many types of separators, such as horizontal, vertical, centrifugal, and venturi, are discussed in this chapter.

The Production Facility

The job of a production facility is to separate the well stream into three components, typically called “phases” (oil, gas, and water), and process these phases into some marketable product(s) or dispose of them in an environmentally acceptable manner. In mechanical devices called separators, gas is flashed from the liquids and “free water” is separated from the oil. These steps remove enough light hydrocarbons to produce a stable crude oil with the volatility (vapor pressure) to meet sales criteria. Separators can be either horizontal or vertical in configuration. The gas that is separated must be compressed and treated for sales. Compression is typically done by engine-driven reciprocating compressors. Usually, the separated gas is saturated with water vapor and must be dehydrated to an acceptable level, normally less than 7 lb/MMscf (110mg H 2 O/Sm 3 ). This is normally done in a glycol dehydrator. Dry glycol is pumped to the large vertical contact tower, where it strips the gas of its water vapor. The wet glycol then flows through a separator to the large horizontal reboiler, where it is heated and the water boiled off as steam. In some locations it may be necessary to remove the heavier hydrocarbons to lower the hydrocarbon dew point. Contaminants such as H 2 S and CO 2 may be present at levels higher than those acceptable to the gas purchaser. If this is the case, then additional equipment will be necessary to “sweeten” the gas.

Chapter 6 – Crude Oil Treating Systems*

Publisher Summary This chapter discusses several factors that are considered to determine the most desirable methods of treating crude oil to contract requirements. The chapter describes the emulsion treating theory. For an emulsion to exist there must be two mutually immiscible liquids, an emulsifying agent, and sufficient agitation to disperse the discontinuous phase into the continuous phase. In oil production, oil and water are the two mutually immiscible liquids. An emulsifying agent in the form of small solid particles, paraffins, and asphaltenes, is almost always present in the formation fluids, and sufficient agitation always occurs as fluid makes its way into the well bore, up the tubing, and through the surface choke. The difficulty of separating the emulsified water from the oil depends on the “stability” of the emulsion. In the process of gravity separation most oil-treating equipment rely on gravity to separate water droplets from the oil continuous phase, because water droplets are heavier than the volume of oil they displace.

Part 2 – Dehydration Considerations

Publisher Summary If hydrate prevention methods are unsuitable and hydrates are liable to form, some water must be removed from the gas stream. Dehydration is the process of removing water from the stream. Water removal from gas can be accomplished by several processes; the two most common methods are adsorption and absorption. Adsorption is a physical phenomenon that occurs when molecules of a gas are brought into contact with a solid surface and some of them condense on the surface. It involves a form of adhesion between the surface of the solid desiccant and the water vapor in the gas. In the absorption process, a hygroscopic liquid is used to contact wet gas and remove the water vapor. The most common liquid used in absorption type dehydration units is triethylene glycol (TEG). Through absorption, the water in a gas stream is dissolved in a relatively pure liquid solvent stream. In addition, one less common method of dehydration is nonregenerable dehydrator (calcium chloride brine unit).

Part 1 – Hydrate Prediction and Prevention

Publisher Summary Dehydration refers to removing water vapor from a gas to lower the stream’s dew point. If water vapor is allowed to remain in the natural gas, it reduces the efficiency and capacity of a pipeline, causes corrosion that causes holes in the pipe or vessels through which the gas passes, and forms hydrates or ice blocks in pipes, valves, or vessels. Dehydration is required to meet gas sales contracts (dependent upon ambient temperatures). Liquid water is removed by gas–liquid and liquid–liquid separation. When a gas has absorbed the limit of its water-holding capacity for a specific pressure and temperature, it is said to be saturated or at its dew point. Any additional water added at the saturation point does not vaporize, but falls out as free liquid. If the pressure is increased and the temperature decreased, the capacity of the gas to hold water decreases, and some of the water vapor condenses and drops out. Methods of determining the water content of gas include partial pressure and partial fugacity relationships and empirical plots of water content versus pressure and temperature.

Water Injection Systems

This chapter provides information on equipment selection and sizing for removing suspended solids and dissolved gases from water. The waters source affects the types and amounts of contaminants in the water. The treatment of water to remove calcium and magnesium dissolved solids is important, especially if the water is to be used as boiler feed water for the generation of steam, as in a steam flood. The removal of suspended solids and dissolved gases from water may be desirable for a variety of reasons, the most common of which are to prepare the water for injection into a producing formation and to minimize the corrosion and solids build-up in surface equipment. Prior to injecting water, it may be important to remove solids above a certain size to minimize damage to the formation caused by solids plugging. This plugging can limit injection volumes, increase pump horsepower requirements, or lead to fracturing of the reservoir rock. Dissolved gases such as oxygen in the water may promote bacteria growth within the formation, or they may speed the process of corrosion. Selection of a specific design of a water treating system for removing suspended solids and dissolved gases from a water source requires establishing the year-round quality of the water source. This determination normally requires that tests be performed to identify the amount of dissolved gases present in the water, the total mass of suspended solids and their particle size distribution, and the amount of oil present in the source.

Crude Oil Treating Systems

This chapter describes oil-field emulsions and their characteristics, treating oil-field emulsions so as to obtain pipeline quality oil, and equipment used in conditioning oil-field emulsions. Conditioning of oil-field crude oils for pipeline quality is complicated by water produced with the oil. Separating water out of produced oil is performed by various schemes with various degrees of success. The problem of removing emulsified water has grown more widespread and oftentimes more difficult as production schemes lift more water with oil from water-drive formations, water-flooded zones, and wells stimulated by thermal and chemical recovery techniques. Removing water from crude oil often requires additional processing beyond the normal oil–water separation process, which relies on gravity separation. Crude oil treating equipment is designed to break emulsions by coalescing the water droplets and then using gravity separation to separate the oil and water. In addition, the water droplets must have sufficient time to contact each other and coalesce. The negative buoyant forces acting on the coalesced droplets must be sufficient to enable these droplets to settle to the bottom of the treating vessel. Therefore, it is important when designing a crude oil treating system to take into account temperature, time, viscosity of the oil, which may inhibit settling, and the physical dimensions of the treating vessel, which determine the velocity at which settling must occur.