Basics of Oil and Gas Treatment - Chapter 1 -

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Fundamentals of Oil and Gas Processing Book
Basics of Gas Field Processing Book
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Basics of Corrosion in Oil and Gas Industry Book

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Chapter 1 11
Basics of Oil and Gas Treatment 11
1.1 Introduction 11
1.2 Hydrocarbon preparation 11
1.3 Produced Hydrocarbon Fluids 12
1.3.1: Hydrocarbon gases 14
1.3.2: Molecular weight and apparent molecular weight 16
1.3.3: Apparent molecular weight of gas mixture 17
1.3.4: Gas Specific Gravity and Density 18
1.3.5: General Gas Law 19
1.4 Natural Gas Field Processing 19
1.5 Natural Gas Composition 21
1.6 The heating value of gases 23
1.7 Natural Gas Sampling 24
1.7.1 General Overview and introduction 24
1.7.2 Sample procedures and precautions 26
1.8 Product specifications 32
1.8.1 Natural gas 32
1.8.2 Natural-Gas Liquids 35
1.9 Physical properties of Hydrocarbon Gases 35
1.9.1 Compressibility Factor (z) 35
1.9.2 Gas density at any condition of Pressure and temperature 38
1.9.3 Gas volume at any condition of Pressure and temperature 39
1.9.4 Velocity of gas, (ft/s) 41
1.9.5 Average pipeline pressure 42
1.9.6 Viscosity of gases 43

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Chapter 1

Basics of Oil and Gas Treatment

1.1 Introduction
Oil and gas wells produce a mixture of hydrocarbon gas, condensate or oil, salt water, other gases, including nitrogen, carbon dioxide (CO2), and possibly hydrogen sulfide (H2S), and solids, including sand from the reservoir, dirt, scale, and corrosion products from the tubing.
These mixtures are very difficult to handle, meter, or transport. In addition to the difficulty, it is also unsafe and uneconomical to ship or to transport these mixtures to refineries and gas plants for processing. Further, hydrocarbon shipping tankers, oil refineries, and gas plants require certain specifications for the fluids that each receive. Also, environmental constraints exist for the safe and acceptable handling of hydrocarbon fluids and disposal of produced salt water. It is therefore necessary to process the produced fluids in the field to yield products that meet the specifications set by the customer and are safe to handle.
1.2 Hydrocarbon preparation
The goal is to produce oil that meets the purchaser’s specifications that define the maximum allowable amounts of water, salt, and sulfur. In addition to the maximum allowable value of Reid vapor pressure and maximum allowable pour point temperature.
Similarly, the gas must be processed to meet purchaser’s water vapor maximum allowable content (Water dew point), hydrocarbon dew point specifications to limit condensation during transportation, in addition to the maximum allowable content of CO2, H2S, O2, Total Sulfur, Mercaptan, Mercury, and maximum gross heating value.
The produced water must meet the regulatory requirements for disposal in the ocean if the wells are offshore, or to meet reservoir requirements for injection into an underground reservoir to avoid plugging the reservoir.
The specifications for the above requirements may include maximum oil in water content, total suspended solids to avoid formation plugging, bacteria counts, toxicity in case of offshore disposal, and oxygen content. Before discussing the industry or the technology of oil and gas processing it is best to define the characteristic, physical properties and main chemical composition of oil and gas produced.

Oil field gas processing which is the subject of this book; generally consists of two distinct categories of operations:
Separation of the gas-oil-brine well-stream into its individual phases,
Removal of impurities from the separated phases to meet sales/transportation/reinjection specifications and/or environmental regulations.
Figures 1-1 and 1-2, illustrates gas-oil separation plant, and gas flow diagram.
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Fig.1-1 .Gas Oil Separation plant function and gas flow diagram.
1.3 Produced Hydrocarbon Fluids
The desirable constituents of crude oil and natural gas are hydrocarbons. These compounds range from methane (CH4) at a lower-molecular-weight end all the way up to paraffin hydrocarbons with 33 carbon atoms and poly-nuclear aromatic hydrocarbons with 20 or more carbon atoms. Natural gas is principally methane. Crude oil is principally liquid hydrocarbon having 4 and more carbon atoms.
There are a tendency to regard crude oil as a liquid and natural gas as a gas and consider production of the two phases as separate operations. However, in the reservoir, crude oil almost always contains dissolved methane and other light hydrocarbons that are released as gas when the pressure on the oil is reduced. As the gas evolves, the remaining crude-oil liquid volume decreases; this phenomenon is known as shrinkage. The gas so produced is called associated or separator gas. Shrinkage is expressed in terms of barrels of stock-tank oil per barrel of reservoir fluid. Crude oil shrinkage is the reciprocal of oil formation volume factor (FVF).
Similarly, natural gas produced from a gas reservoir may contain small amounts of heavier hydrocarbons that are separated as a liquid called condensate. Natural gas containing condensate is said to be wet. Conversely, if no condensate forms when the gas is produced to the surface, the gas is called dry.
A hydrocarbon constituent range or a spectrum of well fluids usually produced are summarized in table 1-1 (as noted by McCain (1973)). The type of fluid produced depends on the phase diagram of the reservoir fluid and the reservoir temperature and pressure, as will be discussed later in phase behavior of natural gas.

Notes.
Separator may be a slug catcher, free water knock out drum, two phase separator, or gun barrel.
Oil and water are separated and undergoes further treatment processes not in the scope of this book.
Image
Fig.1-2. An example of gas flow diagram
Figure 1-3 depicts a typical gas-oil separation sequence (including incidental water removal). Table 1-1 lists the five common types of wellstream fluids and summarizes typical yields and liquid properties.
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Table. 1-1. Petroleum fluid spectrum (after McCain, 1990)
When crude oil is separated from its associated gas during production, the total gas evolved while reducing the oil to atmospheric pressure divided by the volume of the remaining crude oil is called gas-oil ratio or GOR. The GOR is expressed as the total standard cubic feet of gas evolved per 60 0F barrel of stock-tank or atmospheric-pressure oil (scf/bsto). SI units are standard cubic meters of gas per cubic meter of 15 0C oil (metric units).
The total GOR depends on the number of stages used in the separation sequence, as well as the operating pressure of each stage. For three or more stages, the GOR approaches a limiting value. Optimization of the separation sequence usually involves either maximizing crude-oil yield or minimizing recompression horsepower as well be explained briefly in chapter 3.
For wet natural gas, the liquid content is given in barrels of condensate per million standard cubic feet of gas (bbl/MMscf) or in U.S. gallons of condensate per thousand standard cubic feet (GPM).
The various types of produced hydrocarbons have been described using GOR (McCain, 1973- and after McCain, 1990. Table 1-1) or composition (Gould and McDonald, 1979 – Table 1-2).
Of course the gas yield depends on the relative amounts of the various hydrocarbons present, and perhaps Penick (1983) summarizes these relationships best in figure 1-3 ( originally drawn by W.H. Speaker, Jr.).
Allen (1952) emphasizes that classifications like Table 1-1. are an oversimplification in the sense that GOR does not always reflect the condition of the fluid in the reservoir. For example, in the GOR range of 3000 – 7000 scf/bbl the reservoir fluid may be a liquid or a denese fluid (highly-compressed gas) but still be a black oil on the surface. If the fluid is a denese fluid at reservoir temperature and pressure, then any liquid produced is usually defined as condensate. If the reservoir fluid is a liquid, then the produced liquid is called volatile oil. The difference in these two cases is explained in chapter 2.
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Table -1-2 . Well-Fluid Type (Gould and McDonald, 1979)
1.3.1: Hydrocarbon gases
Most of compounds in crude oil and natural gas consist of molecules made up of hydrogen and carbon, therefore these types of compounds are called hydrocarbon.
The smallest hydrocarbon molecule is Methane (CH4) which consists of one atom of Carbon and four atoms of hydrogen. It may be abbreviated as C1 since it consisted from only one carbon atom. Next compound is Ethane (C2H6) abbreviated as C2, and so on Propane (C3H8), Butane (C4H10)...etc.
Hydrocarbon gases are C1:C4), with the increase of carbon number, liquid volatile hydrocarbon is found (e.g. Pentane C5 is the first liquid hydrocarbon at standard conditions).

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Fig. 1-3. Typical Reservoir composition (Penick, 1983).
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Fig.1-4. Stage separation (Gas-oil separator train).

1.3.2: Molecular weight and apparent molecular weight
The molecular weight of a compound is the sum of the atomic weight of the various atoms making up that compound. The Mole is the unit of measurements for the amount of substance, the number of moles is defined as follows:

Mole = Weight/(Molecular weight) (Eq. 1-1)

Expressed as n = m/M (Eq. 1-2)

or, in units as, lb-mole = lb/(lb/lb-mole) (Eq. 1-3)

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Table 1-3 Physical constants of light hydrocarbons and some inorganic gases. Adapted from GPSA, Engineering Data Book, chapter 23.

Example 1.1: Methane molecule consists of one carbon atom with atomic weight =12 and 4 hydrogen atoms with atomic weight = 1 each. Molecular weight for Methane (CH4) = (1 × 12) + (4 × 1) = 16 lb/lb-mole. Similarly, Ethane (C2H6) molecular weight = (2 × 12) + (6 × 1) = 30 lb/lb-mole.

Hydrocarbon up to four carbon atoms are gases at room temperature and atmospheric pressure. Reducing the gas temperature and/or increasing the pressure will condense the hydrocarbon gas to a liquid phase. By the increase of carbon atoms in hydrocarbon molecules, consequently the increase in molecular weight, the boiling point increases and a solid hydrocarbon is found at high molecular weight.
Physical constants of light hydrocarbon and some inorganic gases are listed in Table 1-3.

1.3.3: Apparent molecular weight of gas mixture
For compounds, the term molecular weight is used, while, for hydrocarbon mixture the term apparent molecular weight is commonly used. Apparent molecular weight is defined as the sum of the products of the mole fractions of each component times the molecular weight of that component. As shown in Eq. 1-4
MW= ∑▒ Yi (MW)i (Eq. 1-4)
where
yi =molecular fraction of ith component,
MWi =molecular weight of ith component,
Ʃyi =1.

Example 1.2: Determine the apparent molecular weight for the gas mixture in Table 1-4:

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Table 1-4 Gas mixture for Example 1-2

Solution: Using Table 1-3 & Equation 1-4
MW= ∑▒ Yi (MW)i
MW = (Mole Fraction of component 1 × MW of component 1) + (Mole Fraction of component 2 × MW of component 2) + (Mole Fraction of component 3 × MW of component 3) +…etc.
The following table can be made:

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Table 1-5 Solution of Example 1-2
The apparent molecular weight is 21.36

1.3.4: Gas Specific Gravity and Density
The density of a gas is defined as the mass per unit volume as follows
Density = mass / volume (Eq. 1-5)

The specific gravity of a gas is the ratio of the density of the gas to the density of air at standard conditions of temperature and pressure.

S = (ρ(gas))/(ρ(air)) (Eq. 1-6)

Where
ρ(gas) ρg = density of gas
ρ(air) ρair = density of air

Both densities must be computed at the same pressure and temperature, usually at standard conditions.
It may be related to the molecular weight by Equation 1-7

S = (MW(gas))/(MW(air)) (Eq. 1-7)

Since molecular weight of air is 28.96 (table 1-3)

Specific gravity of gas S = (MW(gas))/28.96 (Eq. 1-8)

Example 1-3: Determine the specific gravity of the gas mixture in example 1-2.
Solution:
Apparent molecular weight of gas mixture is 21.36
Gas specific gravity = 21.36/28.96 = 0.7376

Since the gas is a compressible fluid, its density varies with temperature and pressure, calculating the gas density at a certain pressure and temperature will be explained after discussing the general gas law and gas compressibility factor.

1.3.5: General Gas Law
The general (Ideal) Gas equation, or the Perfect Gas Equation, is stated as follows:

PV = nRT (Eq. 1-9)

Where
P = gas pressure, psia
V = gas volume, ft3
n = number of lb moles of gas (mass/molecular weight)
R = universal gas constant, psia ft3/lb mole OR
T = gas temperature, OR (OR = 460 + OF)
The universal gas constant R is equal to 10.73 psia ft3/lb mole OR in field units.

Equation (1-9) is valid up to pressures of about 60 psia. As pressure increases above this level, its accuracy becomes less and the system should be considered a non-ideal gas equation of state.
PV = znRT (Eq. 1-10)

Where
z = gas compressibility factor.
1.4 Natural Gas Field Processing
The main constituent of natural gas is methane, desirable as a primary fuel. Sales gas also contains smaller amounts of the heavier hydrocarbons listed in table 1- 6. Often a portion of the heavier hydrocarbon can be recovered profitably in a field-gas processing plant as one or more liquid products. These liquefilable components ( or condensate) may be recovered as a single liquid stream that is transported to a separate plant for fractionation into stable products. Alternatively, in very large field units, fractionation is performed in the field. Common natural gas liquid (NGL) products are summarized below.
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Table. 1- 6. Common natural gas liquid (NGL) products nad uses.
The permanet gases occuring in natural gas include nitrogen, helium, argon, hydrogen, and oxygen. Most natural gases contains some nitrogen, and a few have 30 mole percent or more. Nitrogen lowers the heat of combustion of the gas. Since natural gas is usually sold on the basis of energy content with a fixed minimum heating value, the nitrogen content is limited to fairly low amounts in commercially salable gas. The removal of nitrogen require expensive cryogenic processing, so too high a nitrogen content may render a gas unusable.
Many natural gases contain a few hundredth of a percent of helium. Helium has no deleterious effect other than lack of heating value. Separated helium is very valuable and, in the U.S. for example, suffficient lawsuits have awarded royalty payments for helium that could have been recovered economically from sales gases. Analysis also reported occasional small amounts of oxygen, as well as argon and hydrogen. Chromatographic analyses may lump all the inert gases as nitrogen.
Hydrogen sulfide and carbon dioxide are found in many Natural gases and may occur in very high percentages. In fact, essentially pure carbon dioxide is produced, dehydrated, and pipelined for CO2 floods in the enhanced recovery of crude oil. Hydrogen sulfide and carbon dioxide are referred to as acid gases because they dissociate upon solution in water to form acidic solutions. Hydrogen sulfide is very toxic and corrosive, while carbon dioxide is corrosive.
A natural gas containing no hydrogen sulfide is said to be sweet. Conversely, a sour gas containing hydrogen sulfide. Strictly speaking, “sweet” and “sour” refer to both acid gases (CO2 and H2S) but are usually applied to hydrogen sulfide alone.
Sulfur compounds, other than H2S, are present in minute amounts and can affect field processing. These compounds tend to concentrate in the condensate and sometimes require treating (or sweetening) of the liquid products.
Removal of hydrogen sulfide to very low content (4 ppmv or 1/4 grain/100 scf) is required in the field. Carbon dioxide can be tolerated to much higher levels, say 1-2%, as long as the heating value of the sales gas is satisfactory.
There are many so-called “treating” processes for sweetening natural gas. These processes are either batch, reactant-discarded processes for removing low amounts of hydrogen sulfide or continuous solvent-regenerated processes for large amounts. Batch processes are used when the consumable-chemical cost is not prohibitive. The principal continuous, solvent regenerated treating processes use water solution of chemical solvents, typically alkanolamines. Other sweetening such as physical solvents, mixed physical-chemical solvents, or membranes may be more economical in some cases.
Because these processes also remove appreciable amounts of other sulfur compounds and/or carbon dioxide, many gas streams need no further processing to meet total sulfur and acid gas specifications.
Hydrogen sulfide is an extremely toxic substance. Fortunately, the familiar sulfurous smell can be detected at concentration less than 1 ppmv. However, extended exposure at higher levels deadens the sense of smell, so that odor alone cannot be a reliable detector.
Water or brine is undoubtedly present in many gas reservoirs but usually is not entrained to the surface. If free liquid water or brine is produced, a wellhead knockout drum vessel, or separator, is needed to prevent the water entering the gathering lines. At high pressure and low temperature, natural gas and free liquid water form solid hydrates capable of plugging flow lines. Produced water also may contain methanol and/or corrosion inhibitors that have been injected in the well string.
Produced gas is regarded as being saturated with water vapor at the wellhead conditions of temperature and pressure, even if no liquid water is produced. Associated gas is regarded as being saturated with water vapor at the outlet from the gas-oil separator in which it is produced. Water condensed downstream of the wellhead or gas-oil separator will be essentially pure (fresh) water rather than saline brine.
Water vapor is a contaminant that must be removed by proper processing of the natural gas stream. Gas transmission lines often specify water content of 7 lb/MMscf (or a water dew point of 32 0F or less). Triethylene glycol (TEG) is almost always used for such applications. Cryogenic plants require “bone-dry” gas (water dew point as low as -150 0F). Solid desiccants dehydration is typically used for dew points below – 25 0F.
Formation solids are not produced with most natural gas. Nevertheless, solids are sometimes separated from the process plant inlet separator. Usually these solids are mainly mill scale and rust from pipe wall, along with iron sulfide (for sour gas). The solids interfere with treating and dehydration processes and should be removed in a scrubber, filter, or possibly a filter-coalescer separator.
Very deep, high temperature, high pressure sour gas, may contain solid sulfur. Sulfur is inert but must be properly separated to prevent downstream processing problems.
Mercury has been detected in natural gas streams, in concentrations from approximately 1 ppbw to 230 ppmw. Mercury usually causes no processing problems but has caused corrosion of aluminum tubes in heat exchangers. Removal using sulfur-impregnated activated carbon, sulfur beds, or molecular sieves has been suggested.
Recently, arsenic compounds were reported present in natural gas produced from some fields. The discovery was made indirectly by the detection of white powder on regulators in gas company. The arsenic will be removed using a vertical copper-zinc adsorbent bed.
Methanol (to prevent hydrate formation) and corrosion inhibitors are sometimes added downhole and so may be present in natural gas at the wellhead. Any compressed gas will contain some entrained lubricating oils. Field processing may also introduce additional contaminants such as glycols and amines. Mixtures of these liquids with the previously listed solid contaminants are called sludge.
1.5 Natural Gas Composition
The gas analyses shown in table 1-7, span the composition ranges normally encountered. These analyses are typical of the data furnished to the designer of surface processing equipment. As previously mentioned, the heavier hydrocarbon in these gases are regarded as a recoverable liquids. The amount of potentially recoverable liquid is expressed as gallons liquid at 60 0F, if totally condensed, per 1000 standard cubic feet of gas (so called GPM, not to be confused with gallons per minute). A gas is termed lean or rich as follows:
Lean < 2.5 GPM
Moderately-Rich 2.5-5 GPM
Very Rich > 5 GPM
The above classification is based on ethane and heavier hydrocarbons (C2+) because ethane is sometimes regarded as a desirable feed for petrochemical process and can be recovered as a liquid in expander-type gas processing plants. If ethane is not considered as a valuable liquid component, the GPM can be based on propane and heavier hydrocarbons (C3+).

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Table. 1-7. Typical gas analyses (Mol Percent).

Example 1-4. Confirm the GPM given in table 1-7. For the first natural gas stream.
Solution: First find the scf/gal of the C7+ components

scf C7+/ gal liq C7+ = (SG C7+)*(lb H2O/gal)*(1/Mol.Wt.)*(scf/lb mol) (Eq. 1-11)
= (0.803) * (8.334) * (1/172) (379.5) = 14.77
(379.5 = n and is a constant of (scf/lb mol) derived from PV=nRT at standard condition)
The table that follows details the calculations (which are most conveniently done with a spread- sheet program)

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Table. 1-8. Solution of example 1-4.
(a) From Table 1-3.
(b) Column 3/ column 4
GPM is approximately = 0.3 * [100 – (C1 + N2+CO2)].
The weak link in gas analysis is often the composition of the C6+ or C7+ portion of the gas. For many purposes the small amount of the C6+ material renders its characterization unimportant. One important exception is when a full wellstream gas is to be transported in a pipeline over a long distance, such as from an offshore platform. Condensation of liquids in the line will cause a large pressure drop that must be anticipated if adequate platform compression is to be furnished and the proper pipe diameter selected. Very accurate characterization of the C6+ is needed for hydrocarbon (HC) dew points prediction, otherwise the HC can be determined in laboratory.
1.6 The heating value of gases
The heating value of a gas is expressed in Btu/ft3. It represents the quantity of heat in Btu (British Thermal Unit) generated by the complete combustion of one cubic foot of the gas with air at constant pressure (1 atmosphere = 14.7 psia) and at a fixed temperature of 60 0F.
Hydrogen in the fuel burns to water and when the flue gases are cooled to 60°F, the physical state — either vapor or liquid — of this water must be assumed. So the latent heat of vaporization of the water may or may not be considered to be part of the heating value. The result is two definitions for the heating value. The higher or gross heating value, HHV, includes the heat of condensation and the lower or net heating value, LHV, assumes the water remains in the vapor state.
For gas mixture the heating value is calculated as follows:

H = Ʃ xi Hi Eq. 1-12
Example 1-5: Calculate the heating value of gas mixture of Example 1-2
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Table 1-9 Solution of Example 1-5

From table 1-9 the Gross calorific value HHV = 1246 Btu/ft3

The higher, ideal, dry heating value of sweet natural gas at 60°F and 760 mm Hg may be calculated with the following equation:
HHV=1568.72 × SG – 2524.88 × XCO2 – 1658.37 × XN2 +141.05 (Eq. 1- 13)

Applying Eq 1-13 for Example 1-5
The apparent molecular weight= 21.36
Gas Specific gravity = 21.36/28.96 = 0.738
HHV = 1568.72 × 0.738 – 2524.88 × 0.015 – 1658.37 × 0.01 +141.05 = 1244 Btu/ft3
1.7 Natural Gas Sampling
1.7.1 General Overview and introduction

The purpose of natural gas sampling is to secure a representative sample of the flowing gas stream for a specific period of time. Naturally, the more often the sampling system samples the flowing stream, the more likely it is to be truly representative of a stream with varying composition. Refer to figure 1-5.
Sampling systems consist of numerous components and must include some key elements including a sample probe, any necessary connecting tubing, sample containers or sample valves and appropriate heat-tracing and insulation. For online gas chromatographs, or on-stream analyzers, the sampling system ends at the injection valve on the inlet of the g.c.
The sample may be collected on a spot, composite or continuous basis.
Spot sampling simply means that a technician manually collects a sample directly from the stream at scheduled intervals or as needed.
Composite samples are usually collected on a weekly or monthly basis. Composite sampling systems should grab small samples on a flow proportional basis, then inject them into the composite sampling cylinder. There are composite sampling systems that work on a simple time cycle (time proportional sampling), but they are not recommended, especially if they continue to sample even when flow has stopped. If a time proportional system is already in service, it must be equipped with a flow switch or similar device to ensure that when flow stops, sampling will stop.
Continuous systems provide a steady flow of sample through a sample loop that passes near a composite sampler or on stream analyzer. In the case of an on-line chromatograph, the injection valve of the g.c. is able to admit and distribute a sample from the flowing loop that is representative of the flow in the main line. Sample rate flow loops must be carefully sized and generally should operate at velocities around 5 ft/sec., but this may vary if the sample loop is exceptionally long (over 100 feet).
The sample point is usually located downstream of the meter run and must be remote from severe flow disturbances such as control valves and orifice plates by at least five nominal pipe diameters. For flowing streams that are not near their hydrocarbon dew point, the probe should be positioned either upstream or downstream of the meter tube, and at least 5 pipe diameters downstream of any flow disturbing elements, such as elbows, swirl generators, headers, valves and tees. If the sample source is at or near its hydrocarbon dewpoint, some research has indicated that the probe should be located at least 8 pipe diameters downstream of any flow disturbance, including an orifice meter. The sample point must not be installed within the upstream or downstream engineered sections of the meter tube, since the fitting and probe could produce disturbances in the flow profile going through the meter in the run. The probe installed in the sample point extends into the center 1/3 of the internal diameter of the meter run to ensure no heavy materials or contaminants migrating along the pipe walls are allowed to contaminate the sample. Note that for large diameter pipelines, the probe never needs to be longer than 10 inches. The probe is equipped with an outlet valve to allow the system to be shut in when no sampling is being performed or to perform maintenance on downstream equipment in composite or continuous sampling systems.
The tubing connecting the sample probe to the downstream sample system(s) should be internally clean, as short as practical (usually 6 to 24 inches maximum) and made of either nylon or stainless steel. Stainless steel is actually preferred due to its strength and flexibility and resistance to melting and/or sharp edges, but nylon is not porous and when used safely, can also give good analytical results. Teflon, carbon steel, plastic tubing and many other materials do not perform well.
Care must be taken to insure there are no leaks in the sampling system. Typically, if a leak occurs, smaller molecules tend to escape preferentially and create a bias in analytical results. If the leak is large, there may be enough cooling to produce condensation in the sample system and cause the samples to be very non-representative.
Note that whenever the sample line is operating in ambient temperatures below the flowing temperature of the stream, the line may need to be heat-traced and insulated. If the ambient temperature is lower than the dewpoint temperature of the flowing stream, heat tracing and insulation are required.
Be sure that the heat tracing is properly and safely done, using electrically limited tracing meeting appropriate electrical codes for the area classification (typically Class I Group D Division I or II).
Realize that the dewpoint of a gas stream is absolutely critical to accurate sampling. If any component in the sampling system causes the temperature of even a portion of the gas stream being sampled to cool to or below the hydrocarbon dewpoint, the sample will be depleted of heavy components and can no longer be truly representative of the stream. Note that the Btu content in this situation is not always too low. If the sample system continues to condense heavy components for an extended amount of time, accumulations may reach the point that liquid droplets enter the sample and actually cause the indicted Btu content and calculated relative density (specific gravity) to be too high.
The sample cylinders used in spot sampling should be stainless steel, single cavity cylinders. Single cavity cylinders are recommended, due to the difficulty of fully cleaning piston cylinders between uses. Residue that may remain in the piston cylinders and their seals may produce incorrect analyses. The cylinders should be equipped with standard design sample valves that are screw open or closed (not 1/4 turn ball valves) and have a flow passage of approximately 1/8 inch diameter.
It may be convenient to use piston (constant pressure) cylinders in composite sampling systems, since you can easily see that the system is working or not working as the level indicator moves. If constant pressure/piston cylinders are used and oil or grease contamination is present in the system, they must be disassembled between uses, carefully cleaned and then the seal rings must be replaced if the cylinder is expected to provide representative samples.
Note that if sampling is being performed to determine the levels of volatile or reactive contaminants, such as H2S, the cylinder may need to be lined with an epoxy/phenolic lining.
Even then, particularly reactive materials, such as H2S or ethyl mercaptan are likely to be lost prior to analysis unless the sample is collected on-site and analyzed immediately.
Even a few minutes delay can reduce detectable levels of reactive materials. Shipping a sample to a remote lab and delaying analysis beyond a couple of hours will essentially ensure that the indicated levels of the reactive/volatile material will be too low or perhaps not detectable at all.
The two spot sampling methods that are most recommended are the fill and empty method and the helium pop method. The displacement methods also performed reasonably well during the recent API research studies.
The fill and empty method requires that the cylinder be equipped with a “pigtail” following the sample cylinder outlet valve. While leaving the sample cylinder inlet and outlet valves open, the probe outlet valve and the valve at the end of the pigtail are cycled to alternately fill and empty the sample cylinder. The pigtail ensures that the heat of compression created when the sample cylinder is filled more than offsets the Joule-Thomson cooling produced when the sample cylinder is depressurized. It does this by insuring the maximum pressure drop while depressurizing the sample cylinder is far removed from cylinder itself, at the end of the pigtail. The ability of the fill and empty procedure to actually elevate the temperature of the sampling cylinder above the flowing temperature of the stream being sampled during many operating conditions makes this method the most desirable when the ambient temperature is at or near the hydrocarbon dewpoint of the stream.
The pigtail should be approximately 1/4 inch tubing and be at least 36 inches in length, although it may be coiled to make the apparatus easier to handle. The coils should not touch one another, otherwise the heat loss at the end of the pigtail may be transferred quickly across the coils to the sample cylinder.
There should be another sample valve, similar to the sample cylinder valves on the outlet of the pigtail. The flow passage through this valve must not be larger than the passage through the cylinder valves. Refer to API Chapter 14.1 for the detailed procedures for performing the fill and empty method and to either API Chapter 14.1 or GPA 2166 for the number of fill and empty purge cycles required at various line pressures.

1.7.2 Sample procedures and precautions

Collection of a truly representative samples is not a simple job as it looks like. A moment’s thought will confirm that any subsequent design, operating, or investment decision can be no better than the prior sampling and analyses.
In spite of its obvious importance, natural-gas sampling is seldom done well. Natural gas, flowing with accompanying condensate, can not be properly sampled by withdrawal of a portion through a sample tap. Reflection of the complex natural of two phase flow (with its varying flow patterns and liquid-holdup phenomenon, along with velocity gradients in the fluid) should convince one of the impossibility.
In the ideal case, a separator should be set up at the wellhead to collect condensate and meter each phase. Subsequent analysis of the separated gas and liquid allows recombination to obtain the wellstream analysis. This is the reason well-test separators are even installed offshore where space and weight are extremely expensive.
Poor sampling is generally caused by:
Ignorance of its economic and technical importance.
Inadequate training of personnel involved.
Ignorance and/or unwillingness to follow standard procedures.
While sampling in the field do not:
Use dirty cylinders that contain previous samples.
Sample when pressure and temperature are not stable
Sample when separator pressure is different from sample pressure.
Dilute sample with air.
Fail to identify sample completely.
Sampling hydrocarbon fluids can be hazardous. Every body involved in sampling must be familiar with and follow safe practices while handling flammable fluids under pressure. All sample containers must meet the specification to handle sampled fluids, and must be clearly labeled.
Do not fill liquid sample containers completely full. A 150 ml, stainless-steel container was filled full with gasoline and closed at 0 psig and 61 0F. When heated to 105 0F, the sample pressure was 3100 psig!.

1.7.2.1 Gas sampling
GPA standard 2166-86 indicates that good samples can be obtained by all 8 approved methods provided extreme care is taken, however the sampling project report ranked the accuracy of the eight methods in the following order of decreasing accuracy (refer to fig. 1-5):
Water displacement
Continuous purge
Purge and fill
Glycol displacement
Reduced pressure
Floating piston cylinder
Helium filled to 5 psig
Evacuated container
In practice purge and fill is the most popular method while the floating piston cylinder is finding increased use because composite samples cam be obtained.
Several problems can arise during sampling of natural gas:
Condensation of hydrocarbons due to temperature and pressure changes during sampling.
Entrainment of liquid droplets and mist
Sample constituents can react with sample container.
Some sample components may dissolve in the displacement media.
Subsequent handling of the sample is therefore, very important to assure the relatively small amounts of condensable components remain in the gas phase and are removed to the chromatograph or mass spectrometer.
In a natural gas, hydrogen sulfide in small amounts may be overlooked entirely, creating a future problem in design and operation. Hydrogen sulfide reacts rapidly with carbon steel and may disappear from the sample altogether. A stainless-steel sample cylinder should be used if the presence of H2S is suspected. Even austenitic stainless-steel will absorb a small amount of H2S. GPA Standard 2261 recommends that the gas to be analyzed at its source for hydrogen sulfide content less than 3% by GPA Standard method 2377. Teflon-lined cylinders have also been used successfully.
The following precautions are recommended:
Use a pre-filter and/or “knockout” trap on the sample system just downstream from the source valve. This is mandatory on “wet” gas samples.
Use heated sample lines to prevent condensation from low ambient temperature during sampling.
Keep sample lines as short as possible. This should be done for all sample grabbing, wet or dry.
Clean, dry, and evacuate sample cylinders before taking to the field. This prevents possible liquid carryover from the previous sample.
Purge sample cylinder carefully.
Empty cylinders through a non-metallic pigtail on the outlet for the expansion of pressured gas to the atmosphere.
For samples requiring calorimetric heating value determination and chromatographic analysis, use stainless steel or carbon steel, DOT3A and DOT3AA, cylinders, 300 cu.in, volume. Smaller cylinders may be used for GC analysis only; however, a calorimeter Btu determination provides good confirmation of the chromatographic analysis. Calculated Btu from the analysis should not be over +/- 3 Btu from the measured value.
Keep sample cylinders upright while filling. With the purge line at the bottom. Do not lay the cylinders on the ground.
Use line probe that extends at least a third of the way into the line of sampling. This prevents the entry condensate and other contaminants into the sampling line.
Sampling by liquid displacement has been used in the past and still followed by some organizations. It is not recommended for gases or liquids containing acid-gases such as CO2 and H2S. These components dissolve in the liquid, usually water, and are lost. Therefore the resulting analysis is not representative.
Continuous sampling
The following procedures and precautions are recommended for continuous or composite sampling of natural gas:
Sample point should ”see” center one-third of the pipeline in an area of good velocity with minimum turbulence.
Sample probe, equipped with full open ball or gate valve, must be kept away from pipeline fittings and orifice plates. The probe may be bevel or flat cut at end, but must be kept clear of free liquids and aerosols. Bevel may face upstream or downstream.
Probe construction: stationary or permanent, manually insertable or automatic insertion type probe s may be used. The probe should be stainless steel so that it will not react with the sampled gas.
Sampler hook-up and manifold: The sampler should be mounted above the sample point as shown in figure 1- 6. Other precautions are:
a. Line from probe to sampler should slope down to let any free liquid to drain back into pipeline.
b. Never sample a dead-end line.
c. Any leaks in the line from the sampler to the cylinder will “lose” light ends preferentially.
d. Any filters, drips, or regulators between the probe and sampler will invalidate the sample.
Sampler: Should take a composite sample in the same way as an operator would take a spot sample. If the pipeline flow rate varies, the sampler should be actuated proportional to the flow. The sampler should be able to pump the sample into the cylinder and purge itself before pumping each new “bite”.
Sample containers
Proper cleaning and inspection of sample cylinders cannot be overemphasized. Several methods are available:
Volatile solvent and air dry
Steam clean and air dry
Evacuation
Evacuation and fill with 5 psig helium
Correct procedures must be followed rigorously in every detail.

Image
FIG. 1-5. Fill and Empty Sampling Method, and helium pop sampling method.
Image
Fig.1-6 .Gas automatic or continuous sampler.

1.7.2.2 Natural Gas Liquid Sampling

Utilizing Floating Piston Cylinders
Liquid sampling requires special precautions to accumulate and transfer representative samples. Pressure in the sample cylinder and/or accumulator must be maintained at 1.5 times the product vapor pressure. Maximum product vapor pressure should be determined using the highest ambient temperature or flowing temperature (whichever is highest) to determine the minimum pre-charge pressure. A method to break up stratification must be provided prior to transfer of the sample to another container and laboratory analysis. Maintaining the appropriate pressure and mixing the sample can be satisfied by using floating piston sample cylinders with mixers (Fig. 1-7). A “rattle ball” or agitator may be used in place of the mixing rod shown. The floating piston cylinders are precharged on one end with an inert gas at a pressure 1.5 times above product vapor pressure. This prevents sample vaporization, which could result in erroneous analysis. This design also provides a compressible inert gas cushion to allow for thermal expansion of the liquid. A pressure relief valve is needed, but should it discharge, the integrity of the sample will be lost.
Liquid sample cylinders shall not be filled over 80 percent full.
Image
FIG. 1-7. Liquid Sample Container

Samples are acquired through a sample probe inserted into the center third of the flowing stream. The probe should be mounted in the top or side of the line. Continuous samplers should use a continuous flowing sample loop (speed loop) or a probe mounted sample pump to ensure the most current sample is always added to the sample container. Speed loops must have a driving device such as an orifice, differential pump, available pressure drop, or “scoop” probes. The driving device should be sized to provide a complete exchange of liquid in the sample loop once per minute. The sample pump must be set to gather flow proportional samples to ensure a true representative sample is obtained. If flowing pressures are higher than the sample accumulator pre-charge pressure, then the sample pump must prevent “free-flowing” of product into the sample container. See Fig. 1-8 for an example continuous sampling application. Speed loop lines may require insulation when cold ambient temperatures have a significant effect on viscosity. The product in the sample container must be thoroughly mixed before being transferred to a transport cylinder.
Details and alternative methods for obtaining liquid samples are found in GPA 2174.
Image
Fig. 1-8. Continuous Sampler (Automatic sampler)

Procedures and precautions for liquid sampling

A GPA Work group conducted a cooperative natural gas liquid sampling project for future revision of GPA Standard 2174. The following four sampling methods were judged acceptable:
Floating Piston Cylinder.
Water displacement (total removal – 80% hydrocarbons/20%displaced outage)
Water displacement (partial removal – 70% hydrocarbons/20%displaced outage/10%water remaining in cylinder)
Ethylene glycol displacement (total removal – 80% hydrocarbons/20%displaced outage)
The following precautions are recommended for liquid sampling while using the floating piston cylinder:
Pressure on the backside piston should be higher than the line pressure at the beginning of operation
Slowly bleed pressure down to enter sample, and maintain pressures on each side of the piston at nearly equal levels with just enough difference to move the pistons
Do not bleed the pressure off the backside of the piston after sample has been taken, this will flash some of the liquid into gas. Then you will need to resample
Do not fill cylinder 100% full with sample. Leave at least 25% as a pressure buffer to take care of ambient temperature fluctuations.
The floating piston cylinder can be used for “wet” gas sampling with excellent results in getting representative samples. Procedures are as follows:
Pressure up back of cylinder with line gas to full line pressure.
Connect cylinder to source (use of a line probe is mandatory) and open valves to cylinder.
Fill cylinders as you would in taking liquid sample. Note: It is extremely important to avoid any pressure drops. The pressure differences should not exceed 2 psi maximum. This will prevent flashing of heavy components which may be in aerosol form. Sample should be slowly entered into cylinder.
1.8 Product specifications
The objective of field processing is to provide transportable and/or salable fluids. There are two main products: natural gas and condensate (raw mix) or natural gas liquid (NGL).
1.8.1 Natural gas
Table 1-10 lists typical natural gas pipeline specifications listed in a typical sales gas contract. Theses specifications are fixed by negotiation between seller and buyer and vary from case to case. Not all sales gases will have all the specifications shown in the following items.

Image

Table. 1- 10. Natural gas pipeline specifications.
Table. 1-11. Is a typical sales gas/ pipeline contract between two middle east companies.
Image
Table. 1-11. Typical sales gas/ pipeline contract.
Wobbe Index is some times used in sales gas specification. Wobbe Index = [Gross heating value / (Sp.Gr)0.5].
The most important specifications are: water content (water dewpoint), H2S content, and gross heating value. The following table summarizes the effect of water, acid gases, and liquid hydrocarbons in sales gases:

Image
Image
Table.1-13. Water dew point and water content relation. (ANSI/CGA G-7.1 -1989 document).

Note that both water and hydrogen sulfide must be removed to very low concentrations. Heating value is more complex (specification usually from 950 to 1200 Btu/scf).
Refer to table 1-3. For heating value of hydrocarbon gases. (Complete physical properties of hydrocarbon gases are listed in GPSA, Engineering data book, chapter 23).
From table 1-3, we can realize that; the most abundant component, methane, has a relatively low heating value (1010 Btu/scf). Therefore, by itself methane cannot always fulfill the minimum heating value requirement when inert gases (nitrogen and/or carbon dioxide) are present. However, enough heavier hydrocarbons are usually present to provide the required heating value, even with condensate recovery.
When there is a maximum heating value or hydrocarbon dew point specifications, some of the heavier hydrocarbons constituents may have to be removed as condensate. Refrigeration to (-30 0F reduces the heating value) how much, of course, depends on the gas composition and pressure. Further reduction requires cryogenic processing. The remaining specifications are met by suitable processing. These processes are the subjects of the later chapters.
Image
Fig. 1-9 Moisture Content Nomograph for Gases
1.8.2 Natural-Gas Liquids
Hydrocarbon condensate recovered from natural gas may be shipped without further processing or stabilized to produce a safely-transportable liquid. In the case of raw condensate, there are no particular specifications for the product other than the process requirements. Stabilized liquid, on the other hand, will generally have a vapor pressure specifications, since the product will be injected into a pipeline or transport pressure vessel which has a definite pressure limitations.
Natural-gas liquid products are prepared by fractionation of the raw make into appropriate products, either at the field processing site or, perhaps more commonly, at a large central facility. In any case, product specifications are not so typical as those of sales gas, but depends heavily on the particular contract. Liquid product specifications generally include composition, vapor pressure, water content, and sulfur content.
1.9 Physical properties of Hydrocarbon Gases
1.9.1 Compressibility Factor (z)
The Compressibility factor, Z is a dimensionless parameter less than 1.00 that represents the deviation of a real gas from an ideal gas. Hence it is also referred to as the gas deviation factor. At low pressures and temperatures Z is nearly equal to 1.00 whereas at higher pressures and temperatures it may range between 0.75 and 0.90. The actual value of Z at any temperature and pressure must be calculated taking into account the composition of the gas and its critical temperature and pressure. Several graphical and analytical methods are available to calculate Z. Among these, the Standing-Katz, and CNGA methods are quite popular. The critical temperature and the critical pressure of a gas are important parameters that affect the compressibility factor and are defined as follows.
The critical temperature of a pure gas is that temperature above which the gas cannot be compressed into a liquid, however much the pressure. The critical pressure is the minimum pressure required at the critical temperature of the gas to compress it into a liquid.
As an example, consider pure methane gas with a critical temperature of 343 0R and critical pressure of 666 psia (Table 1-3).
The reduced temperature of a gas is defined as the ratio of the gas temperature to its critical temperature, both being expressed in absolute units (0R). It is therefore a dimensionless number.
Similarly, the reduced pressure is a dimensionless number defined as the ratio of the absolute pressure of gas to its critical pressure.
Therefore we can state the following:
Tr = T/Tc (Eq. 1-14)
Pr = P/Pc (Eq. 1-15)

Where
P = pressure of gas, psia
T = temperature of gas, 0R
Tr = reduced temperature, dimensionless
Pr = reduced pressure, dimensionless
Tc = critical temperature, 0R
Pc = critical pressure, psia

Example1-6: Using the preceding equations, the reduced temperature and reduced pressure of a sample of methane gas at 70 0F and 1200 psia pressure can be calculated as follows
Tr = (70 +460) / 343 =1.5
Pr = 1200/666 = 1.8

For natural gas mixtures, the terms pseudo-critical temperature and pseudo-critical pressure are used. The calculation methodology will be explained shortly. Similarly we can calculate the pseudo-reduced temperature and pseudo-reduced pressure of a natural gas mixture, knowing its pseudo-critical temperature and pseudo-critical pressure.
The Standing-Katz chart, Fig. 1.10 can be used to determine the compressibility factor of a gas at any temperature and pressure, once the reduced pressure and temperature are calculated knowing the critical properties.
Pseudo-critical properties allow one to evaluate gas mixtures. Equations (1-16) and (1-17) can be used to calculate the pseudo-critical properties for gas mixtures:
P’c = Ʃ yi Pci (Eq. 1-16)

T’c = Ʃ yi Tci (Eq. 1-17)

where
P’c =pseudo-critical pressure,
T’c =pseudo-critical temperature,
Pci =critical pressure at component i, psia
Tci =critical temperature at component i, 0R
Yi =mole fraction of each component in the mixture,
Ʃ yi =1.

Example 1-7:
Calculate the Compressibility factor for the following Gas mixture at 1000F and 800 psig:

Image
Table 1-14 for Example 1-7.

Using Equation 1-16 and 1-17
T`r = (100+460)/464.5 =1.2
P`r = (800+14.7)/659.4 = 1.23
From fig.1-10. Compressibility factor is approximately, z= 0.72
Image
Figure 1-10 Compressibility Factor For lean sweet natural gas (Surface Production Operations).
(More graphs for compressibility factors and acid gas corrections are available in GPSA, data book)
Calculating the compressibility factor for example 1-6, of the gas at 70 0F and 1200 psia, using Standing-Katz chart, fig. 1-10. Z = 0.83 approximately. For ) Tr = 1.5 , Pr = 1.8).

Another analytical method of calculating the compressibility factor of a gas is using the CNGA equation as follows:
Image
(Eq. 1-18)
Where
Pavg = Gas pressure, psig. [psig = (psia - 14.7)]
Tf = Gas temperature, 0R
G = Gas gravity (air = 1.00)
The CNGA equation for compressibility factor is valid when the average gas pressure Pavg is greater than 100 psig. For pressures less than 100 psig, compressibility factor is taken as 1.00. It must be noted that the pressure used in the CNGA equation is the gauge pressure, not the absolute pressure.

Example 1-8: Calculate the compressibility factor of a sample of natural gas (gravity = 0.6) at 80 0F and 1000 psig using the CNGA equation.
Solution:
From the Eq. (1.18), the compressibility factor is
Image
The CNGA method of calculating the compressibility, though approximate, is accurate enough for most gas pipeline hydraulics work and process calculations.

1.9.2 Gas density at any condition of Pressure and temperature
Once the molecular weight of the gas is known, the density of a gas at any condition of temperature and pressure is given as:

ρg= ((MW)P)/RTZ lb/ft3

Since R=10.73, then
ρg= 0.093 ((MW)P)/TZ lb/ft3 (Eq. 1-19)
where
ρg = density of gas, lb/ft3,
P =pressure, psia,
T =temperature, 0R,
Z =gas compressibility factor,
MW=gas molecular weight.

Example 1-9: Calculate the pseudo-critical temperature and pressure for the natural gas stream composition given in example 1-2, calculate the compressibility factor, and gas density at 600 psia and 1000F.
Solution:

Image
Table 1-15 solution of Example 1-9.
From the table MW= 21.36
T`c = 451.5 0R
P`c = 667 psia

From Eq. (1-14) and Eq. (1-15)
Tr = T/T`c = (100+460)/451.5 = 1.24

Pr = P/P`c = 600/667 = 0.9

Compressibility factor z could be calculated from figure 1-10, or from Eq. (1-18)
Value from figure, z = 0.83
From Equation 1-15 z = 0.87
For our further calculation we will use the calculated z value [Eq. (1-18)]
Using eq. (1-19) density of gas

ρg = 0.093 ((21.36)600)/(560 ×0.83) = 2.56 lb/ft3
Comparing ρg at standard condition (z=1)
ρg at standard condition = 0.093 (21.36)14.7/(520 ×1) = 0.056 lb/ft3
We can conclude that density increases with pressure while the volume decreases.
1.9.3 Gas volume at any condition of Pressure and temperature
Volume of a gas is the space occupied by the gas. Gases fill the container that houses the gas. The volume of a gas generally varies with temperature and pressure.
Volume of a gas is measured in cubic feet (ft3).
Gas volume are commonly referred to in "standard" or "normal" units.
Standard conditions commonly refers to gas volumes measured at: 60°F and 14.696 psia
The Gas Processors Association (GPA) SI standard molar volume conditions is 379.49 std ft3/lb mol at 60°F, 14.696 psia.
Therefore, each mole (n) contains about 379.5 cubic feet of gas (ft3)at standard conditions.
Therefore, by knowing the values of mass and density at certain pressure and temperature, the volume occupied by gas can be calculated.

Example 1-10: Calculate the volume of a 10 lb mass of gas (Gravity = 0.6) at 500 psig and 80 0F, assuming the compressibility factor as 0.895. The molecular weight of air may be taken as 29 and the base pressure is 14.7 psia.
Solution:
The molecular weight of the gas (MW) = 0.6 x 29 = 17.4
Pressure =500+14.7 = 514.7 psia
Temperature = 80+460 = 540 0R
Compressibility factor z= 0.895
The number of lb moles n is calculated using Eq. (1-2). n=m/(MW)
n = 10/17.4
Therefore n= 0.5747 lb mole
Using the real gas Eq. (1-10), PV=nzRT
(514.7) V = 0.895 x 0.5747 x 10.73 x 540. Therefore, V = 5.79 ft3

Example 1-11: Calculate the volume of 1 lb mole of the natural gas stream given in the previous example at 1200F and 1500 psia (compressibility factor Z = 0.811).
Solution:
Using Eq.(1-10), PV = nzRT
V= 0.811 x 1 x 10.73 x (120+460)/1500. V = 3.37 ft3

Example 1-12: One thousand cubic feet of methane is to be compressed from 60°F and atmospheric pressure to 500 psig and a temperature of 50°F. What volume will it occupy at these conditions?
Solution:
Moles CH4 (n) = 1000 / 379.5 = 2.64
At final conditions, (Compressibility factor z must be calculated), from equations 1-14 and1-15
Tr = (460 + 50) / 344 = 1.88
Pr = (500 + 14.7) / 673 = 0.765
From Figure 1-10, Z = 0.94
From eqn. 1-10, PV = nzRT
V = ft3
Example 1-13: One pound-mole of C3H8 (44 lb) is held in a container having a capacity of 31.2 cu ft. The temperature is 280°F. "What is the pressure?
Solution:
Volume = V = 31.2 ft3
A Trial-and-error solution is necessary because the compressibility factor Z is a function of the unknown pressure. Assume Z = 0.9.
Using Eq. 1-10, PV = nzRT
P ×31.2 = 0.9 × 1.0 × 10.7 × (460 + 280)
P = 229 psia
From table 1-3, eqns. 1-14 and 1-15
Pr = 229 / 616 = 0.37,
Tc = 665ºR
Tr = (460 + 280) / 665 = 1.113
According to Figure 1.9, the value of Z should be about 0.915 rather than 0.9. Thus, recalculate using eq. 1-10, the pressure is 232 rather than 229 psia.

Example 1-14: Calculate the volume of gas (MW=20) will occupy a vessel with diameter 24 in, and 6 ft. length. At pressure 200 psia and temperature 100 0F. (Assume compressibility factor z=0.9), and what will be the volume of gas at 14.7 psia and 60 0F.
Then calculate gas density and mass inside the container at pressure 200 psia and temperature 100 0F.
Volume of vessel = π L r2
V = 3.14 × 6 × (24)2/ (2 ×12)2 ft3
V = 18.8 ft3.
(We divided by 2 to get (r) from the diameter, and divided by 12 to convert from in. to ft.)
T = 460 + 100 = 560 0R
Using Eq. 1-10, PV=nZRT
n = 18.8 × 200 / (0.9 × 10.73 × 560)
n = 0.7 lb. moles. (Remember gas volume ft3 = 379.5 x n)
Volume of gas at 200 psia and 100 0F= 0.7 * 379.5 = 266 ft3
n of Gas at 14.7 psia and 60 0F ( z=1) = 18.8 × 14.7 / (1 × 10.73 × 520)
n = 0.0495 lb. moles
Volume of gas at 14.7 psia and 60 0F = 0.0495 * 379.5 = 18.8 ft3

From the previous example 1-14, the gas volume will equal to the container volume at standard conditions (14.7 psia and 60 0F).

Gas density is calculated using Eq. 1-19
ρg = 0.093 ((MW)P)/TZ lb/ft3
Density of gas ρg = 0.093 × 20 × 200 / (0.9 × 560) = 0.738 lb/ft3
Mass of gas inside the vessel = Volume × density = 0.738 × 265 = 196 lb mass

1.9.4 Velocity of gas, (ft/s)
The velocity of gas equal the volume flow rate (ft3) per second divided by flow area (ft2).

Example 1-15: Calculate the gas velocity for gas flow rate 100 MMscfd through 24 in. internal diameter gas pipe, the gas specific gravity is 0.7, pressure 500 psia, Temperature 100 0F, and assume compressibility factor 0.85.
Solution: Using Eq. 1-10, PV=nzRT, and remember that n= V (ft3)/379.5).
n = 100 × 106/379.5
Gas volume at operating conditions V= 100 × 106 × 0.85 × 10.73 × 560 / (379.5 × 500)
= 2,695,000 ft3/day
Gas flow rate cubic foot per second = 2,695,000 / (24×60×60) = 31.2 ft3/sec
Area of flow = π r2 = 3.14 × 12 × 12 / (144) = 3.14 ft2
(144 to convert r2 from in. to ft2.)
Velocity of gas will be 31.2/3.14 = 9.9 ft/s
The gas velocity may be calculated directly from the following equation:

Velocity = 6 ZTQ/(100,000×Pd2) ft/s. Eq 1-20
Where Q = Flow rate scfd, d = diameter in inches.

The maximum recommended velocity of dry gas in pipes is 100 ft/s, (60 ft/s for wet gas), and to be less than the erosional velocity which is defined as:
Erosional velocity: The erosional velocity represents the upper limit of gas velocity in a pipeline. As the gas velocity increases, vibration and noise result. Higher velocities also cause erosion of the pipe wall over a long time period. The erosional velocity Vmax may be calculated approximately as follows:

Vmax = 100 √(2&ZRT/29GP) Eq 1-21

Where G= gas sp. Gt (air=1), P = pressure psia
For Example 1-15, the erosional velocity Vmax is:

Vmax = 100 √(2&0.85×10.73×560/(29×0.7× 500)) Vmax = 70.9 ft/s.

1.9.5 Average pipeline pressure
The gas compressibility factor Z used in the General Flow equation is based upon the flowing temperature and the average pipe pressure. The average pressure may be approximated as the arithmetic average
Pavg = (P1+P2)/2 of the upstream and downstream pressures P1 and P2. However, a more accurate average pipe pressure is usually calculated as follows

Pavg = 2/3 (P1+P2 - (P1× P2)/(P1+ P2)) Eq 1-22

Where
P1, P2, Pavg = pressure, psia

Example 1-16: A natural gas pipeline with internal diameter 19 in. transports natural gas (Sp. Gr.= 0.65) at a flow rate of 200 MMscfd. Calculate the gas velocity at inlet and outlet of the pipe, assuming isothermal flow. The inlet temperature of 70 0F, inlet pressure is 1200 psig, and outlet pressure is 900 psig. Use compressibility factor of 0.95. Also, calculate the erosional velocity for this pipeline.
Solution:
Using Eq. 1-20, the gas velocity at inlet of the pipe:
Velocity = 6 × 0.95× 530×200,000,000/(100,000×1214.7×192) ft/s.
Velocity = 13.8 ft/s.
The gas velocity at outlet of the pipe:
Velocity = 6 × 0.95× 530×200,000,000/(100,000×914.7×192) ft/s.
Velocity = 18.3 ft/s.
Finally, the erosional velocity can be calculated using Eq. 1-21
Vmax = 100 √(2&0.95 ×10.73×530/29×0.65×1214.7)
Vmax = 48.6 ft/s.

The above example may be solved by calculating the gas density at inlet and outlet of the pipe, then calculating the operational flow rate, divide it by pipe cross sectional area to get the velocity as follows:
Gas molecular weight = 0.65 × 28.96 = 18.8
Using Eq. 1-10, PV = nzRT
Calculating n = 200,000,000 / 379.5
Flow rate under operating conditions =
Gas volume V (= flow rate Q) = 200,000,000 × 0.95 × 10.73 × 530 / (379.5 ×1214.7)
Q = 2,347,000 ft3 per day at operating conditions. Q = 27.16 ft3/s.
Pipe cross sectional area = π r2 = 3.14 × 19 × 19 /(4× 144) = 1.97 ft2
Velocity of gas at the inlet = 27.16/1.97 = 13.8 ft/s.

1.9.6 Viscosity of gases
Viscosity of a fluid relates to the resistance to flow of the fluid. Higher the viscosity, more difficult it is to flow. Viscosity is a number that represents the drag forces caused by the attractive forces in adjacent fluid layers. It might be considered as the internal friction between molecules, separate from that between the fluid and the pipe wall.
The viscosity of a gas is very small compared to that of a liquid. For example, a typical crude oil may have a viscosity of 10 centipoise (cp), whereas a sample of natural gas has a viscosity of 0.0019 cp.
Viscosity may be referred to as absolute or dynamic viscosity measured in cp or kinematic viscosity measured in centistokes (cSt). Other units of viscosity are lb/ft-sec for dynamic viscosity and ft2/s for kinematic viscosity.
Fluid viscosity changes with temperature. Liquid viscosity decreases with increasing temperature, whereas gas viscosity decreases initially with increasing temperature and then increases with further increasing temperature.

Image
Table 1- 16 Viscosity conversion factors

Figure 1-11 can be used to estimate the viscosity of a hydrocarbon gas at various conditions of temperature and pressure if the specific gravity of the gas at standard conditions is known. It is useful when the gas composition is not known. It does not make corrections for H2S, CO2, and N2. It is useful for determining viscosities at high pressure.

Image
Figure 1-11 Hydrocarbon gas viscosity.
Fundamentals of Oil and Gas Processing
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1 - Fundamentals of Oil and Gas Processing
2- Basics of Gas Field Processing
3- Prediction and Inhibition of Gas Hydrates
4 - Basics of Corrosion in Oil and Gas Industry
Fundamentals of Oil and Gas Processing
Basics of Gas Field Processing
Basics of Corrosion in Oil and Gas Industry
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