Field Operations & Inlet Receiving
Chapter 8
Based on Presentation by Prof. Art Kidnay
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
Topics
• Field Operations
 Wellhead operations
 Piping
 Compressor stations
 Pigging
• Inlet Receiving
 Separator principles
 Slug catcher configurations
• Gas Hydrates
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
2
Topics
• Field Operations
 Wellhead operations
 Piping
 Compressor stations
 Pigging
• Inlet Receiving
 Separator principles
 Slug catcher configurations
• Gas Hydrates
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
3
CO2
Gas & Liquids from Wells
Field Liquids Removal
Elemental
Sulfur
Sulfur Recovery
Field Acid Gas Removal
Field Dehydration
Field Compression
Inlet Receiving
Inlet
Compression
Hydrocarbon
Recovery
Water &
Solids
Gas
Treating
Nitrogen
Rejection
Dehydration
Helium
Recovery
Outlet
Compression
Raw
Helium
Sales
Gas
N2
Liquefaction
Liquids Processing
Liquefied
Natural Gas
Natural
Gas Liquids
Natural
Gasoline
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
4
GOSP
• Gas-Oil Separation Process
(GOSP) for removing gas from
high pressure oil well.
• Associated gas is almost always
saturated with water.
 Either dehydration (usually
glycol dehydration, see Chapter
11) or…
 hydrate inhibitors (see section
8.3) are added to prevent
hydrate formation.
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
5
Gas wells with condensate tank and fired separators
Figure 8.2
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
6
Booster station on gathering system
Figure 8.3
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
7
Compression station
Schematic of common
operations at a compression
station on a gathering system.
Condensed liquids may be
stored or returned to the line.
Some locations may have
dehydration or sweetening
facilities.
Figure 8.4
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
8
Gas Well with Separator and Tankage
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
9
Gas Wells and Metering
Courtesy of the Williams
Companies
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
10
“Typical” Compression Station (Booster Station)
Inlet Scrubber
Compressor
Air Cooler
Gas From
Wells
Gas To Plant
Metering
Pump
Water /Condensate
Storage
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
Hydrate
Inhibitor
Corrosion
Inhibitor
11
Booster station
Courtesy of Wind River Environmental Group
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
12
Topics
• Field Operations
 Wellhead operations
 Piping
 Compressor stations
 Pigging
• Inlet Receiving
 Separator principles
 Slug catcher configurations
• Gas Hydrates
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
13
Pigging
Pigging is used to:
 Provide a barrier between liquid products using the same pipeline
 Check wall thickness and find damaged sections of lines
 Remove debris such as dirt and wax from lines
 Provide a known volume for calibrating flow meters
 Coat inner pipe walls with inhibitors
 Remove condensed hydrocarbon liquids and water in multiphase pipelines
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
14
Common Pigs
Courtesy of Girard Industries
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
15
Common Pigs
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
16
Common Pigs
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
17
Instrumented Pig
from GmbH
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
18
Instrumented Pig
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
19
Pig Launcher & Receiver
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
20
Inlet Receivers with Pigs
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
21
Como Ball Receiver
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
22
G-Line Pig Receiver
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
23
H-Line Pig Receiver
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
24
Inlet Facilities
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
25
Automated Ball Launcher
From Kimmitt, et al., 2001
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
26
Remote automated pig launcher
Figure 8.8
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
27
Smart pig removed from receiver
Figure 8.9
Smart pig being removed from pig receiver. The pig uses magnetic flux to detect corrosion
and mechanical damage in pipeline wall. (Courtesy of ROSEN Group)
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
28
Topics
• Field Operations
 Wellhead operations
 Piping
 Compressor stations
 Pigging
• Inlet Receiving
 Separator principles
 Slug catcher configurations
• Gas Hydrates
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
29
Gas-Liquid Separators
• Final protection for downstream equipment
• Either vertical or horizontal
• Vessel has four stages of separation:
1. Primary Separation
2. Gravity Settling
3. Coalescing
4. Liquid Collecting
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
30
Gas-Liquid Separators
Mesh
Pad
C
Gas +
Liquid
Gas
Gas + Liquid
Gas
Mesh
Pad
A
C
A
B
B
D
Vortex
Breaker
Liquid
Vertical Separator
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
Vortex
Breaker
Boot
Hydrocarbon
Liquid
Water
Horizontal Separator
A = Inlet Device
C = Mist Extraction
B = Gas Gravity
Separation
D = Liquid Gravity
Separation
31
Typical 3-phase Separator
From: Natural Gas Production/Dehydration, J.W. Williams Inc.
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
32
Inlet Receiving (Slug Catchers)
• Protect plant from large, sudden liquid influxes
• Two kinds
 Manifolded piping
• Good for high pressures, open space
• Still require liquid storage
 Large vessels
• Good at lower pressures
• Combines slug catching and liquid storage
• Adequate liquid storage needed in both kinds
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
36
Harp Design Slug Catcher
Kimmitt et al., 2001
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
37
Harp Design Slug Catcher
“A new approach for sizing finger-type (multiple-pipe) slug catchers”
H. R. Kalat Jari, P. Khomarloo, & K. Ass
http://www.gasprocessingnews.com/features/201506/a-new-approach-for-sizing-finger-type-(multiple-pipe)-slug-catchers.aspx
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
38
Harp Design Slug Catcher
Ref: http://www.statoil.com/en/OurOperations/pipelines/Documents/veien_til_lng_engelsk_enkel.swf
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
39
Inlet receivers (slug catchers)
Figure 8.18
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
40
Multiple Slug Catcher
Liquid volume 500 bbls, nominal gas rate 206MMscfd
Kimmitt et al., 2001
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
41
Aerial view of slug catcher
Courtesy of The Williams Companies
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
42
Topics
• Field Operations
 Wellhead operations
 Piping
 Compressor stations
 Pigging
• Inlet Receiving
 Separator principles
 Slug catcher configurations
• Gas Hydrates
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
43
What are Gas Hydrates?
• Ice-like solids which can form well above 32oF.
• Natural gases form in one of three structures but most commonly in Structure II.
• Hydrate forming gases include:
 N2, O2, C1 through iC5, H2S and CO2.
• Hydrate formation conditions highly dependent upon gas composition.
 Propane content is a major factor.
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
44
Hydrate structure
• Conceptual image of one hydrate cage
with a methane molecule inside.
Hydrogen atoms are not shown but
oxygen atoms are located at each
intersection point of outer cage.
Courtesy of USGS
Figure 8.11
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
45
Hydrate forming conditions
Figure 8.12
Hydrate formation conditions for pure methane, ethane, and propane
(data from Sloan, 1998) and a natural gas mixture from Rio Arriba County,
New Mexico.
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
46
Hydrate forming conditions
Below 1,000 psia the figure can be
approximated as:
t=
−16.5 −
6.83
+ 13.8 ln ( P )
γ 2g
where t in units of oF & P in units of psia
Figure 8.13
Pressure-temperature curves for estimation of hydrate-formation conditions as a function of gas gravity.
These curves should be used for approximation purposes only. Divide pressure by 14.5 to obtain bars.
(Adapted from Engineering Data Book, 2004c.)
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
47
Hydrate plug
Courtesy of Petrobas
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
48
Avoid hydrate complications
If prediction shows that the plant or pipeline will be operating within the hydrate
formation region, what can you do??
1. Change operating conditions so you are outside the hydrate formation region
2. Dehydrate the gas
3. Add hydrate inhibitors
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
49
Chemical inhibitors for hydrates
• Advantages
 Used properly, they work
• Disadvantages
 Cost
 Determining proper dose
 Injection site may be at a remote location
• Transportation to site and possible dealing with hazardous materials}
 Possible interaction with other additives (such as corrosion inhibitors)
 Possible problems with downstream processes
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
50
Classes of chemical hydrate inhibitors
• Antiagglomerates (AA)
 Prevent small particles form grouping into larger particles
• Kinetic
 Interfere by with construction of cages
• Thermodynamic
 Mainly methanol and ethylene glycol (antifreeze)
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
51
Predicting Hydrate Formation
Two factors in hydrate formation
• Thermodynamics
 Equilibrium formation temperature and pressure
 PREDICTABLE
• Kinetics
 Initiation and rate of growth
 UNPREDICTABLE
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
52
Hydrate Structures & Types of Cages
512
512 62
2
16
512 64
3
6
Structure I
8
43 56 63
Structure II
2
512 68
46 Water Molecules
1
136 Water Molecules
Structure H
34 Water Molecules
Center for Hydrate Research
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
53
What do they form?
Either of three crystalline structures
Waters per unit cell
Cages per unit cell
Average cage radius,
nm
Gases fitting into
cages
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
Structure I
46
Small
Large
Structure II
136
Small
Large
Small
Structure H
34
Med
Large
6
39.1
2
43.3
8
39.0
16
46.8
3
39
2
4.1
1
5.7
N2,O2,
C1,H2S
N2,O2,
C1,H2S,C
O2,C2
N2,O2,
C1,H2S
N2,O2,
C1,H2S,C
O2, C2,C3,
iC4,C4
N2,O2,
C1,H2S
N2,O2,
C1,H2S
N2,O2,
C1,H2S,C
O2, C2,C3,
iC4,C4, iC5
54
How To Predict Hydrate Formation
Two factors in hydrate formation
• Thermodynamics
 Equilibrium formation temperature and pressure
 PREDICTABLE
• Kinetics
 Initiation and rate of growth
 UNPREDICTABLE
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
57
Hydrate forming conditions
Figure 8.13
Pressure-temperature curves for estimation of hydrate-formation conditions as a function of gas gravity.
These curves should be used for approximation purposes only. Divide pressure by 14.5 to obtain bars.
(Adapted from Engineering Data Book, 2004c.)
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
58
Methods for Predicting Equilibrium Formation
Temperature and Pressure
• Gas gravity curve (Katz, 1945)
 Advantages
• Quick & simple
 Disadvantages
• Poor accuracy
• Valid for pure water only
• Statistical Mechanics (van der Waals and Plateeuw, 1959)
 Advantages
• Most accurate
• Handles salts, MeOH, EG
 Disadvantages
• Complex & requires computer for calculations
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
59
Kinetics of hydrate formation
• Hydrate onset is stochastic and unpredictable
• Subcooling always occurs
 Usually can operate 2 to 4oF into hydrate region without problem
• Factors affecting onset and kinetics:
 Amount of subcooling
 Presence of liquid water
 Presence of nucleation sites, e.g., scale, wax, asphaltenes
 Flow rates
 Presence of other hydrocarbon phases
 “History” of water phase
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
60
How To Prevent Hydrate Formation
• Operate outside of hydrate formation
region
 Advantages
• Good where practical
 Disadvantages
• Dry the gas - Must avoid free liquid
water
 Advantages
• Safest
 Disadvantages
• Frequently impractical
• Frequently impractical
• Heating systems are expensive and
must be robust
• Dehydration expensive, capex & opex
• lowering pressures likely requires
recompression
• CO2, NOX, BTEX emissions
• Add equilibrium (thermodynamic)
inhibitors
 Alters temperature and pressure of
hydrate formation
• Add Low Dosage Inhibitors (LDI)
 Alters rate of formation (kinetic
inhibitors) or prevents agglomeration
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
62
Effect of Methanol on Hydrate Formation Conditions
10000
Wt % Methanol
Pressure, psia
74
65
50
35
20 10 0
1000
100
-100
-80
-60
-40
-20
0
20
40
60
80
Temperature, ºF
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
63
Hammerschmidt equations (1939)
2335 X i
∆t ( °F ) =
M i (1 − X i )
 ∆t ( °F )  Mi
Xi =
 ∆t ( °F )  Mi + 2335
where ∆t is the hydrate depression temperature difference, Mi is the molecular
weight of the inhibitor, & Xi is the mass fraction inhibitor in the free water phase
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
64
Comparison of kinds of inhibitors
Equilibrium
Low Dosage
MeOH
Universal
MEG
Universal
KI
Site Specific, <20
°F Subcooling
None
None
Delay’s formation
Unit Cost
Amount Needed
Compatibility
Environmental
Cheap
20 to 50 Wt%
????
Toxic
Expensive
~0.5 Wt%
????
Good
Volatility
Processing Issues
High
Recovery?
Cheap
20 to 50 Wt%
????
Toxic, Oil &
Grease
Low
Recovery?
AA
Site Specific,
Liquid HC phase
present
Prevents
agglomeration
Expensive
~0.5 Wt%
????
????
Low
None
Low
Break emulsion
Applicability
Time Dependence
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
66
Using Inhibitors
Factors determining injection rate:
 Maximum subcooling (include brine effect)
• Determines inhibitor concentration
 Amount of free and condensing water present
• Determines injection rate for treating water
 Hydrocarbon flow rate
• If gas phase present, must include vapor losses for MeOH
• If condensed hydrocarbon phase present, must include inhibitor losses
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
67
Summary – How Can Hydrates Be Prevented
• When practical, operate outside of hydrate region or avoid free water in system.
• Add equilibrium inhibitors, MeOH or EG
 Many costs associated with this option and it may not be available in future.
• Add LDI, KI at low subcooling, AA at higher subcooling
 Emerging and attractive technology, but need to verify effectiveness
No matter which option is chosen, remember hydrate inhibitors must be
compatible with other inhibitors.
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
68
How To Remove Hydrates
• Onboard/onshore process equipment
 Shut-in, depressurization and warm-up
• Well and pipeline plugs
 Learn what happened prior to plugging and possible cause
 Locate plug by altering line pressure
 Determine best route, MeOH injection, heating, depressurization
• Beware of JT cooling, safety issues.
 Decide restart procedure, including removal of water
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
69
Is there anything good about hydrates?
• Very large potential source of C1 from C1-hydrates on ocean floor
• Inexhaustible source of research projects for graduate students
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
70
Topics
• Field Operations
 Wellhead operations
 Piping
 Compressor stations
 Pigging
• Inlet Receiving
 Separator principles
 Slug catcher configurations
• Gas Hydrates
John Jechura – jjechura@mines.edu
Updated: February 1, 2016
71