Upgrade to remove ads
Production II final
Terms in this set (51)
Techniques for Natural Gas Dehydration
1. Absorption with liquid desiccants
2. Adsorption with solid desiccants
6. Calcium Chloride
7. Gas Stripping
Properties of Dehydration agents
- High water absorption efficiency
- High decomposition temp
- Low vaporization losses
- Easy and economic to be separated and regenerated
- Non-corrosive and non-toxic to the system
selection of desiccant
1. Comparative cost of the glycols
2. Viscosities of the glycol in the hydrocarbon process fluids as well
3. Solubility of the glycol in the hydrocarbon process fluids
4. Temperature of operation
5. Stability at regeneration temperature
6. Low foaming and emulsifying tendencies
Design Data for dehydration system
1. Gas flow rate
2. Composition or SG of gas
3. Operating temperature and Pressure
4. Desired outlet dew-point or water content
List of Equipment
1. Inlet cooler (optional)
2. Inlet scrubber
3. Absorber or Contactor
4. Glycol cooler
5. Glycol/Glycol heat exchanger
6. Flash drum/skimmer
7. Glycol filters
8. Glycol re-boiler
9. Still column
10. Surge vessel/drum
11. Glycol pump
Modes of Heat transfer
1. Conduction: The transfer of heat from one molecule to an adjacent molecule while the particles remain in fixed positions relative to each other is conduction.
2. Convection: The transfer of heat within a fluid as the result of mixing of the warmer and cooler portions of the fluid is convection.
3. Radiation: The transfer of heat from a source to a receiver by radiant energy is radiation. This type of energy is carried by electromagnetic waves (light). Those waves could be radio waves, infrared, visible light, UV, or Gamma rays.
Q = kA(∆T)/L
Q = heat transfer rate, Btu/hr
A = heat transfer area, ft2
∆T = temperature difference, °F
k = thermal conductivity, Btu/hr-ft-°F
L = distance heat energy is conducted, ft
Q = heat transfer rate, Btu/hr
A = heat transfer area, ft2
∆T = temperature difference, °F
h = film coefficient, Btu/hr-ft-°F
Types of Heat Exchangers
2. Plate Type
3. Extended Surface
Log Mean Temperature Difference (LMTD)
LMTD = ([ΔT1 - ΔT2]/[ln(ΔT1/ ΔT2)])*F
ΔT1 = hot fluid temp difference ⁰F
ΔT2 = cold fluid temp difference ⁰F
F = correlation factor
Heat Transfer in Heat exchanger
1. The heat energy is transferred from the hot fluid to the exchanger tube (convection)
2. Through the exchanger tube wall (conduction)
3. And from the tube wall to the cold fluid (convection)
overall heat transfer coefficient components
1. internal film coefficient
2. Tube wall thermal conductivity and its thickness
3. External film coefficient
4. fouling factors
Natural Gas Contaminants
1. Hydrogen sulfide (H2S)
2. Carbon dioxide (CO2)
3. Nitrogen (N2)
4. Carbonyl sulfide (COS)
5. Carbon disulfide (CS2)
6. Mercaptans (RSH)
7. Water (H2O)
max legal limit for H2S in gas stream
0.25 grain/ 100 scf
H2S exposure levels
1. Threshold limit value (TLV) for prolonged exposure: 10 ppmv
2. Slight symptoms after several hours exposure: 10-100 ppmv
3. Maximum concentration that can be inhaled for one hour without serious effects such as significant eye and respiratory irritation: 200-300 ppmv
4. Dangerous after exposure of 30 minutes to one hour: 500-700 ppmv
H2S exposure limits (cont.)
5. Fatal in less than 30 minutes: 700-900 ppmv and above.
6. Death in minutes: greater than 1000 ppmv
7. Hydrogen sulfide is highly flammable and will combust in air at concentrations from 4.3 to 46.0 volume percent. Hydrogen sulfide vapors are heavier than air and may migrate considerable distances to a source of ignition.
Factors affecting gas sweetening
1. Flow rate, pressure, temperature and composition of the gas to be processed
2. Types and concentrations of contaminants in the gas
3. Degree of contaminant removal desired
4. Selectivity of acid gas removal required
5. Carbon dioxide to hydrogen sulfide ratio in the gas
6. Desirability of sulfur recovery due to process economics or environmental issues.
Adsorption and Absorption
Adsorption is a physical phenomenon in which the gas is concentrated on the surface of a solid to remove impurities
Absorption is a process in which gas is ultimately distributed throughout the absorbent (liquid). Common absorbing media used are water, aqueous amine solutions, caustic, sodium carbonate.
The use of Mono-ethanolamine (MEA) in gas treating applications is well established. As a primary amine, MEA is used for H2S and/or CO2 removal.
2. It has also the ability to remove COS, Mercaptans and CS2.
However, the reaction with these trace components is irreversible and leads to increased solvent degradation.
3. MEA solvents are usually applied in concentration of 15 - 25 wt % in water.
Advantages of MEA
- Relatively low solvent cost
- Removal of COS and CS2
- High reactivity due to its primary amine character, a ¼ grain H2S specification can usually be achieved and CO2 removal to 100 ppmv for applications at low to moderate operating pressures
- Reclaimable by thermal distillation at regenerator pressure
Disadvantages of MEA
- Non-selective removal in mixed acid gas presence
- High solvent vapor pressure which results in higher solvent losses than the other alkanol-amines
- Higher corrosion potential than other alkanol-amines
- High energy requirements due to the high heat of reaction with H2S and CO2
- Formation of irreversible degradation products with CO2, COS and CS2, which require regular reclaiming.
components of sweetening unit
1. Inlet Knock-out Drum
3. Three Phase Flash Drum
4. Rich/Lean Heat Exchanger
5. Cartridge Filter
6. Activated Carbon Filter
7. Amine Regenerator
8. Reflux Condenser
9. Reflux Accumulator
10. Amine reclaimer
11. Amine cooler and surge tank
MEA circulation rate (general)
GPM = 41*(Qy/x)
Q = sour gas to be processed, MMscfd
y = acid gas concentration in sour gas, mole %
x = amine concentration in liquid solution, wt %
Oil-Water emulsion types
1. Regular/Normal emulsion; In such emulsions, water droplets are dispersed in oil as the continuous phase
2. Reverse emulsion; In such emulsions, oil droplets are dispersed in water as the continuous phase
Factors for emulsion formation
1. Two mutually immiscible liquids
2. Presence of Emulsifying agent or stabilizer
3. Sufficient agitation to disperse the discontinuous phase into the continuous phase.
factors affecting the stability of emulsions
1. The difference in density between the water and oil phases
2. The size of dispersed water particles
4. Interfacial tension
5. The presence and concentration of emulsifying agents
6. Water salinity
7. Age of the emulsion
Naturally occurring emulsifiers
- Organic acids
- Metallic salts
- Asphaltenes (S, N2, O2)
Selection of Treatment of emulsion
1. Stability or tightness of the oil-water emulsion
2. Specific gravity of the oil and produced water
3. Corrosiveness of the crude oil, produced water, and associated gas
4. Scaling tendencies of the produced water
5. Flow rate of fluid to be treated and percent water in the fluid
6. Paraffin-forming tendencies of the crude oil
7. Desirable operating pressures for equipment
8. Availability of a sales outlet and value of the associated gas produced
Emulsion Treating Methods
1. Chemical addition
2. Settling time
4. Electrostatic coalescing
sections of horizontal heater treater
Oil Surge section
same as heater treater, but added electrostatic grid in coalescing section to promote coalescence.
Grid has voltage from 10,000 to 35,000 VAC applied with power consumption of 0.05 to 0.10 KVA/ft2.
Usually optimim field intensities fall between 1000 and 4000 V/in.
Treater Sizing factors
• Heat input required
• Gravity separation considerations
• Settling equations
• Retention time equations
• Water droplet size
salt allowances in crude oil
10 to 20 lbs per thousand bbls
any device that removes water can be used as desalter, but majority of desalters are horizontal electrostatic treaters
1. The first step is to mix fresh water with entrained produced water. This will lower the produced water salinity by diluting the salt.
2. The second step is dehydration which is the removal of the water from the crude. This dilution and dehydration produces a lower salinity in the residual water in the crude oil. The dilution water in desalting does not have to be fresh. Any water with a lower salt content than the produced water can be used.
safety device definition
all devices used to protect any/all modules of a production system
most important safety device
pressure relief valves to prevent pressure in pipes, valves, fittings, and pressure vessels from going over design Pressure
ASME code about relief valves
requires pressure vessels that can be blocked in to have a relief valve to prevent overpressure
API safety codes
1. API RP 14C: recommends that relief valves be installed at various locations in the production system
2. API RP 520: recommends various conditions for sizing relief valves.
3. API RP 521: Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries
1. Blocked discharge
2. Gas blow-by
3. Regulator failure
5. Thermal condition
6. Heat exchanger tube rupture
Types of Relief Valves
1. Conventional Relief valve
2. Balanced Relief valve
3. Pilot operated Relief valve
disc that will rupture at a certain pressure.
not resealable, only one use. normally used as backup to relief valve
the deterioration or destruction of metal by reactions with the environment. can be external or internal, may result from chemical or electrochemical action
usually caused by presence of CO2 and organic acids or by presence of H2S or combination
usually caused by exposure to atmospheric Oxygen, microbes, high temp, or electrochemical corrosion action caused by the flow of electric currents or combination.
body who handles corrosion
National Association of Corrosion Engineers (NACE)
They identify and solve corrosion problems
Forms of Corrosion
1. Uniform corrosion
2. Galvanic corrosion
3. Pitting corrosion
4. Crevice corrosion
5. Inter-granular corrosion
6. Stress cracking corrosion
8. Hydrogen damage
9. Corrosion in Concrete
10. Microbial corrosion
Types of Corrosion
1. Chemical Corrosion
2. Electro-chemical Corrosion
3. Microbial Corrosion
Factors promoting corrosion
1. Energy differences in the form of stress gradients or chemical reactivity across the metal surface in contact with corrosive solution.
2. Differences in concentration of salts or other corrosive agents in electrolytic solution.
3. Differences in the amount of deposits, either solid or liquid, on the metal surfaces, which are insoluble in the electrolyte solutions.
4. Temperature gradients over the surface of the metal in contact with corrosive solution.
5. Compositional differences in the metal surface.
deep rounded pits w/ sharp edges. especially prevalent in turbulent areas. partial pressures give indication of corrosion
1. A partial pressure of CO2 above 30 psi usually indicates that corrosion will occur.
2. A partial pressure of 3 to 30 psi indicates that corrosion may occur.
3. A partial pressure below 3 psi indicates that corrosion generally is not a serious problem.
Corrosion control methods
1. Injection of corrosion inhibitors
2. Application of effective coatings
3. Use of special corrosion resistant alloys
4. Properly applied and maintained cathodic protection
THIS SET IS OFTEN IN FOLDERS WITH...
Production 2 Test 2
Production 2 Test 3
Production 2 Final Deck
Production 2 Final New Material
YOU MIGHT ALSO LIKE...
CHEM EXAM #3
Physics 2010, Test 4 (Andersen, UVU) me
PHYS 202 Chapters 11-13
Comfort Systems Residential final