SECTION III.III: Middle Stream Operations: “Surface Operations”

15 Principal Field

Principal Field Processing Operations and Field Facilities

15.1 FIELD PROCESSING OPERATIONS

Field processing of produced crude oil-gas mixture aims to separate the well stream into quality oil and gas saleable products in order to recover the maximum amount of each at minimum cost. Our objective in this chapter is to offer a basic understanding and to present a concise description for every processing surface unit from wellhead to finished quality stream products as shown in Figure 15.1.

15.1.1 Separation of Gases from Oil

The first step in processing the well stream is to separate the crude oil. natural gas, and water phases into separate streams. A gas-oil separator is a vessel that does this job. Gas-oil separators can be horizontal, vertical, or spherical.

Oil-field separators can be classified into two types based on the number of phases to separate:

• • Two-phase separators, which are used to separate gas from oil in oil fields, or gas from water for gas fields
• • Three-phase separators, which are used to separate the gas from the liquid phase, and water from oil

The liquid (oil, emulsion) leaves at the bottom through a level-control or dump valve. The gas leaves the vessel at the top, passing through a mist extractor to remove the small liquid droplets in the gas. Separators can be categorized according to their operating pressure. Low-pressure units handle pressures of 10-180 psi (69-1,241 kPa). Medium pressure separators operate from 230 to 700 psi (1,586-4,826 kPa). High-pressure units handle pressures of 975-1,500 psi (6,722-10,342 kPa).

Gravity segregation is the main force that accomplishes the separation, which means the heaviest fluid settles to the bottom and the lightest fluid rises to the top. The degree of separation between gas and liquid inside the separator depends on the following factors: separator operating pressure, the residence time of the fluid mixture, and the type of flow of the fluid (turbulent flow allows more gas bubbles to escape than laminar flow).

FIGURE 15.1 Overall flow diagram for crude oil processing.

15.1.2 Oil Dehydration and Emulsion Treatment

Once crude oil is separated, it undergoes further treatment steps. An important aspect during oil field development is the design and operation of wet crude handling facilities.

One has to be aware that not all the water is removed from crude oil by gravity during the first stage of gas-oil separation. Separated crude may contain up to 15% water, which may exist in an emulsified form. The objective of the dehydration step is a dual function: to ensure that the remaining free water is totally removed from the bulk of oil and to apply whatever tools necessary to break the oil emulsion. In general, free water removed in the separator is limited to water droplets of 500 pm and larger.

Produced crude oil contains sediment and produced water (BS&W), salt, and other impurities. These are readily removed from the crude oil through this stage. Produced water containing the solids and impurities is discharged to the effluent water treatment system. Clean, dehydrated oil flows from the top of the vessel. Depending on the salt specifications, a combination dehydrator followed by a desalter may be required.

A dehydration system, in general, comprises various types of equipment according to the type of treatment: water removal or emulsion breaking. Most common are the following:

• • Free water knockout drum (FWKO)
• • Wash tank
• • Gunbarrel
• • Flow treater
• • Chemical injector
• • Electrostatic dehydrator

It is very common to use more than one dehydrating aid. particularly for emulsion breaking. Examples are the heater-treater and chem-electric dehydrator.

The role played by adding chemicals to break emulsions should not be overlooked. These chemicals act as de-emulsifiers—once absorbed on the water-oil interface, they will rupture the stabilizing film causing emulsions.

15.1.3 Desalting

The removal of salt from crude oil is recommended for refinery feed stocks if the salt content exceeds 20 PTB (pounds of salt, expressed as equivalent sodium chloride, per thousand barrels of oil). Salt in crude oil, in most cases, is found dissolved in the remnant water (brine) within the oil. It presents serious corrosion and scaling problems and must be removed.

Electrostatic desalting, whether employed for oil field production dehydration and desalting or at oil refineries, is used to facilitate the removal of inorganic chlorides and water-soluble contaminants from crude oil. In refinery applications, the removal of these water-soluble compounds takes place to prevent corrosion damage to downstream distillation processes.

Salt content in crude oil (PTB) is a function of two parameters: the amount of remnant water in oil (R) and the salinity of remnant water (S). To put it in a mathematical form, we say:

The electrostatic desalting process implies two important consecutive actions:

• 1. Wash water injection in order to increase the population density of small water droplets suspended in the crude oil (w'ater of dilution)
• 2. Creating a uniform droplet size distribution by imparting mechanical shearing and dispersion of the dispersed aqueous phase (electrostatic coalescer)
• 15.1.4 Stabilization and Sweetening

Once degassed, dehydrated, and desalted, crude oil should be pumped to gathering facilities for storage. However, stabilization and sweetening are a must in the presence of hydrogen sulfide (H₂S). H,S gas is frequently contained in the crude oil as it comes from the wells. It not only has a vile odor, it is also poisonous. It can kill a person if inhaled. It is also corrosive in humid atmosphere forming sulfuric acid. Pipeline specifications require removal of acid gases (carbon dioxide, CO,) along with H,S.

The stabilization process, basically a form of partial distillation, is a dual job process. It sweetens “sour” crude oil (removes the H,S and CO, gases) and reduces vapor pressure, thereby making the crude safe for shipment in tankers. Vapor pressure is exerted by light hydrocarbons, such as methane, ethane, propane, and butane. As the pressure on the crude is light hydrocarbons vaporize and escape from the bulk of the oil. If a sufficient amount of these light hydrocarbons is removed, the vapor pressure becomes satisfactory for shipment at approximately atmospheric pressure.

15.1.5 Gas Sweetening

Having finished crude oil treatment, we turn now to the treatment and processing of natural gas. The actual practice of processing natural gas to pipeline dry gas quality levels can be quite complex but usually involves three main processes to remove the various impurities:

• • Sulfur and CO, removal (gas sweetening)
• • Water removal (gas dehydration)
• • Separation of natural gas liquids (NGLs)

It should be pointed out that sweetening of natural gas almost always precedes dehydration and other gas plant processes before the separation of NGLs. Dehydration, on the other hand, is usually required for pipeline Sour natural gas composition can vary over a wide concentration of H,S and CO,. It varies from parts per million to about 50 volume percent. Most important are H,S and CO, gases. Gas sweetening is a must for the following reasons: the corrosiveness of both gases in the presence of water; and the toxicity of H,S gas and a heating value of no less than 980 Btu/SCF.

Some of the desirable characteristics of a sweetening solvent are:

• • Required removal of H,S and other sulfur compounds must be achieved.
• • Reactions between solvent and acid gases must be reversible to prevent solvent degradation.
• • Solvent must be thermally stable.
• • The acid gas pickup per unit of solvent circulated must be high.
• • The solvent should be noncorrosive.
• • The solvent should not foam in the contactor or still.
• • Selective removal of acid gases is desirable.
• • The solvent should be cheap and readily available.

Amine gas treating, also known as gas sweetening and acid gas removal, refers to a group of processes that use aqueous solutions of various alkylamines (commonly referred to simply as amines) to remove H,S and CO, from gases. They are known as regenerative chemical solvents. It is a common unit process used in refineries, and it is also used in petrochemical plants, natural gas processing plants, and other industries.

15.1.6 Gas Dehydration

Glycol dehydration is a liquid desiccant system for the removal of water from natural gas and NGLs. It is the most common and economical means of water removal from these streams. Triethylene glycol (TEG) is used to remove water from the natural gas stream in order to meet the pipeline quality standards. This process is required to prevent hydrates formation at low temperatures or corrosion problems due to the presence of CO, or H,S (regularly found in natural gas). Dehydration, or water vapor removal, is accomplished by reducing the inlet water dew point (temperature at which vapor begins to condense into a liquid) to the outlet dew point temperature, which will contain a specified amount of water.

15.1.7 Recovery and Separation of Natural Gas Liquids

Although some of the needed processing of natural gas can be accomplished at or near the wellhead (field processing), the complete processing of natural gas takes place at a processing plant, usually located in a natural gas producing region. NGLs usually consist of the hydrocarbons ethane and heavier (C₂).

In order to recover and to separate NGLs from a bulk of a gas stream, a change in phase is to be induced. In other words, a new phase has to be developed for separation to take place.

Two distinctive operations are in practice for the separation of NGL constituents, dependent on the use of either energy or mass as a separating agent:

• 1. Energy separating agent (ESA)—Removing heat by refrigeration will allow heavier components to condense, hence a liquid phase is formed. Production of NGLs at low temperature is practiced in many gas processing plants. For example, to recover, say, C₂, C„ and C₄ from a gas stream, demethanization by refrigeration is done.
• 2. Mass separating agent (MSA)—To separate NGLs a new phase is developed by using a liquid (solvent), MSA, to be introduced in contact with the gas stream, that is, absorption. This solvent is selective to absorb the NGL components.
• 15.1.8 Fractionation of Natural Gas Liquids

Once NGLs have been separated from a natural gas stream, they are further separated into their component parts, or fractions, using the distillation or fractionation process. This process can take place either in the field or at a terminal location hooked to a petrochemical complex. NGL components are defined as ethane, propane, butane, and pentanes plus natural gasoline.

Fractionation in gas plants has many common goals. As presented earlier in Figure 15.1, it is aimed at producing on-specification products and making sources available for different hydrocarbons. Fractionation is basically a distillation process leading to fractions or cuts of hydrocarbons. Examples of cuts or fractions are C,/C₄, known as liquefied petroleum gas (LPG), and C₃, known as natural gasoline.

Liquid fractionation towers are used to separate and remove NGLs. They can be controlled to produce pure vapor-phase products from the overhead by optimizing the following factors: ^[1]

• • Reflux temperature
• • Column pressure
• 15.2 FIELD FACILITIES

This include two important facilities: Field Storage Tanks, Vapor Recovery System (VRS)

15.2.1 Field Storage Tanks

Production, refining, and distribution of petroleum products require many different types and sizes of storage tanks. Small bolted or welded tanks might be ideal for production fields while larger, welded storage tanks are used in distribution terminals and refineries. There are many factors that should be considered in the selection of storage tanks in oil field operations.

Field operating conditions, storage capacities, and specific designs are most important. Storage tanks are often cylindrical in shape, perpendicular to the ground with flat bottoms, and with a fixed or floating roof. Atmospheric storage tanks, both fixed roof and floating roof tanks, are used to store liquid hydrocarbons in the field.

Storage tanks are needed in order to receive and collect oil produced by wells before pumping to the pipelines and to allow for measuring oil properties, sampling, and gauging.

The design of storage tanks for crude oil and other hydrocarbon products is a function of the following factors:

• • The vapor pressure of the materials to be stored
• • The storage temperature and pressure
• • Toxicity of the petroleum material
• 15.2.2 Tank Classification and Types

According to the National Fire Protection Association (NFPA), atmospheric storage tanks are defined as those tanks that are designed to operate at pressures between atmospheric and 6.9 kPa gage. Such tanks are built in two basic designs: the cone- roof design where the roof remains fixed, and the floating-roof design where the roof floats on top of the liquid and rises and falls with the liquid level.

Pressure storage tanks, on the other hand, are used to store liquefied gases such as liquid hydrogen (LH) or a compressed gas such as compressed natural. They can be referred to as “high-pressure tanks”. Storage tanks can also be classified as aboveground storage tanks (AST) and underground storage tanks (UST).

There are usually many environmental regulations and others that apply to the design and operation of each category depending on the nature of the fluid contained within.

As far as the types of storage tanks there are four basic types of tanks that are commonly used to store crude oil and its products:

• • Floating Roof Tanks
• • Fixed Roof Tanks
• • Bullet Tanks
• • Spherical Tanks (Storage Spheres)
• 15.2.3 Vapor Recovery System

In production operations, underground crude oil contains many lighter hydrocarbons in solution. When oil is brought to the surface it experiences drastic pressure drop by going through the gas-oil separator plant (GOSP). The evolution of hydrocarbon vapors is dependent on many factors:

• • The product’s physical characteristics
• • The operating pressure of upstream equipment
• • Tank storage condition

During storage, light hydrocarbons dissolved in the crude oil or in the condensate, including methane, other volatile organic compounds (VOCs), and hazardous air pollutants (HAPs), vaporize or flash out. These vapors collect in the space between the liquid and the fixed roof tank. As the liquid level in the tank fluctuates, these vapors are vented to the atmosphere, or flared. Alternatively, a vapor recovery compressor (or blower) may be installed to direct vapors vented from storage to downstream compressors for sales or injection. Significant economic savings are obtained by installing vapor recovery units (VRUs) on the storage tanks. These units are capable of capturing about 95% of the vapors. Losses of dissolved light are identified as:

• • Flash losses due in the GOSP
• • Working losses due change in the fluid level inside the tank during pumping, filling, or emptying
• • Standing or breathing losses that occur with daily and seasonal temperature changes

Vacuum relief valves are needed to keep a vacuum from occurring because of tank breathing and pumping operations. If a vacuum develops, the tank roof will collapse.

15.2.4 Economic and Environmental Benefits

VOC and HAP emissions to the atmosphere cause pollution of the air we breathe. These emissions can be controlled by either destruction or by recovery using VRUs. VRUs are designed to comply with the U.S. Environmental Protection Agency (EPA)

FIGURE 15.2 The economic return of installing VRU system.

standards, provide economic profits to the oil and gas producers, and eliminate of stock vapors to the atmosphere. Waste gas is the lost product, hence a lost revenue. Gases flashed from crude oil or condensate and captured by VRUs can be sold at profit or used at an oil field facility. Options for utilizing the recovered gases are to be used as a fuel for oil field operations, to be collected to natural gas gathering stations and sold, or to be used as a stripping agent.

In order to estimate the economic return when installing a VRU, one should follow the procedure as shown in Figure 15.2.

• [1] Inlet flow rate • Reflux flow rate • Rebolier temperature