Evaluation of gas handling capacity of the ellen east gas gathering system (5)

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EVALUATION OF GAS HANDLING CAPACITY OF
THE ELLEN EAST GAS GATHERING SYSTEM
11-06-2019 0 SENT FOR APPROVAL J. Varajas P. Márquez
DATE
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. N° REASON FOR REVISION PREPARED CHECKED
APPD.
SIDELINE
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COMPANY
DOCUMENT NUMBER : JOB NUMBER:

EVALUATION OF GAS HANDLING
CAPACITY OF THE ELLEN EAST
GAS GATHERING SYSTEM
Sideline Testing LLC
DATE: 11/06/2019
PAGE: 2 of 29
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Disclaimer
While all efforts have been made to exercise due care and caution, Sideline Testing
LLC cannot assume any liability for damage, injury (personnel or plant), leakage,
loss of containment, environmental damage, remediation or the like associated with
the subject pipeline. It is understood by all parties that the measurement techniques
used and discussed in this report are non-invasive, and as such never made actual
physical damage with the subject pipeline. As a result, the data provided may not
be indicative of actual pipeline condition and are deductive in nature. All
recommendations are based upon similar experience, standard industry methods
and best engineering practice.

CAPACITY OF THE ELLEN EAST GAS
GATHERING SYSTEM
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CONTENTS
ABSTRACT 4
LIST OF FIGURES 5
LIST OF TABLES 5
1. OBJECTIVE 6
2. SCOPE OF WORK 6
3. REFERENCES 6
4. TECHNICAL INFORMATION 7
5. HYDRAULIC EVALUATION CRITERIA 11
6. METHODOLOGY 11
7. RESULTS AND ANALYSIS OF RESULTS OF HYDRAULIC
CALCULATIONS 17
8. CONCLUSIONS 20
9. ANNEXES 21

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ABSTRACT
This report presents the validation hydraulic calculations to the gas handling capacity of
the Ellen East gas gathering system operated by Laredo Energy at current operating
conditions and hypothetical new wells.
The following two case studies were considered:
Case study A: Hypothetical new well close to the location of wells # 4-H and # 9-H - East
side).
Case study B: Hypothetical new well close to the location of well # 12-H – West side).
The methodology applied is based on the minimum allowable operating pressure in Ellen
East Drip Station (around 1000.0 psig, or minimum delivery pressure to another operator).
Also, is based on API14E standard that establishes a gas erosional velocity of 60 ft/s for
gas pipelines. Both criteria are evaluated at the same time, and the one that is applied is
achieved first. For the two case studies evaluated, the criterion of maintaining minimum
delivery pressure at Ellen East Drip Station was achieved first.
The maximum gas handling capacity was calculated by trial and error until the pressure
calculated at Ellen East Drip Station equals 1000.0 psig.
The modeling and simulation of pipelines was carried out using the commercial software
Pipephase 9.8. The selected fluid flow model was OLGAS v.1.1 2-Phase, and the following
results were achieved:
 The Ellen East gas gathering system can handle an additional stream of up to 50.0
MMSCFD of natural gas, if the well or wells are located near the location of wells #
4-H and # 9-H and the flow line pressure is in the order of 1200.0 psig.
MMSCFD of natural gas, if the well or wells are located near the location of well #
12-H and the flow line pressure is in the order of 1200.0 psig.

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LIST OF FIGURES
Figure 1. Composition and saturated scheme of Laredo Energy dry gas. ...........................8
Figure 2. Schematic of the gas handling and gathering system of Laredo Energy - Ellen
East Field..............................................................................................................................10
Figure 3. Simulation Setup Wizard......................................................................................11
Figure 4. Pipephase 9.8 simulation model schematic.........................................................13
Figure 5. Pipephase 9.8 simulation model schematic for case A. ......................................14
Figure 6. Pipephase 9.8 simulation model schematic for case. .........................................15
LIST OF TABLES
Table 1. Dry Gas sample chromatography @ 1091 psig y 119°F: Composition and
physical properties of the gas (SG, Z and molecular weight). Supplied by Laredo Energy..7
Table 2. Well production - Ellen East Drip Station. ...............................................................8
Table 3. Compressor operating conditions............................................................................9
Table 4. Results of the calculation of superficial velocity of the gas (Vsg) of the gas
gathering system by Laredo Energy at current operating conditions (Base case). ............17
Table 5. Results of the calculation of the maximun gas handling capacity (MMSCFD) of
the gas gathering system by Laredo Energy (Case study A: Maximum gas handling
capacity - Hypothetical new well close to the location of wells # 4-H and # 9-H - East side).
..............................................................................................................................................18
Table 6. Results of the calculation of the maximun gas handling capacity (MMSCFD) of
the gas gathering system by Laredo Energy (Case study B: Maximum gas handling
capacity - Hypothetical new well close to the location of well # 12-H - East side)..............19

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1. OBJECTIVE
To perform updated hydraulic calculations to determine the gas handling
capacity of the Ellen East gas gathering system operated by Laredo Energy at
current operating conditions and according to project 12" Line Extension
Engineering Design.
2. SCOPE OF WORK
Updated calculation of gas-handling capacity (MMSCFD) of the new pipeline on
Ellen East gas gathering system operated by Laredo Energy at current
operating conditions and according to project 12" Line Extension Engineering
Design.
Laredo Energy will install a gas pipeline extension of 12” X 0.695 miles (0.375
wall thickness) from wells location # 13/14 to wells location # 4/9.
3. REFERENCES
 Calculation of gas handling capacity of the Ellen East gas gathering system
_Rev.0 Date 07-05-2019.

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4. TECHNICAL INFORMATION
1. Composition of natural gas and physical properties produced by Laredo
Energy
Table 1 shown Compositional analysis of the dry gas supplied by Laredo Energy
(Dry base).
Table 1. Dry Gas sample chromatography @ 1091 psig y 119°F: Composition
and physical properties of the gas (SG, Z and molecular weight). Supplied by
Laredo Energy.
Component MOL %
Hydrogen Sulfide 0.0008
Nitrogen 0.0408
Carbon Dioxide 4.0305
Methane 95.7494
Ethane 0.1549
Propane 0.0152
Isobutane 0.0051
N-butane 0.0021
Isopentane 0.0008
N-Pentane 0.0004
Hexanes Plus 0.0000
Total 100.0000
Physical Properties
@60F: 14.650 psi
Specific Gravity
(Real) 0.5950
Compessibility (Z) 0.9979
Molecular Weight 17.2040

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Figure 1. Composition and saturated scheme of Laredo Energy dry gas.
2. Well production - Ellen East Drip Station.
Table 2. Well production - Ellen East Drip Station.
Well #
Gas Production
(MMSCFD)
Head
Pressure
(psig)
Flow Line
Pressure
(psig)
Temperature
(°F)
Choke
# 12-H TBG 3.500 1342.0 1207.0 133 21/64
# 3-H TBG 1.100 450.0 202.0 94 64/64
# 6-H TBG 1.700 500.0 202.0 112 48/64
# 1-H TBG 0.234 500.0 208.0 95 64/64
# 2-H TBG 0.351 400.0 227.0 95 30/64
# 8-H TBG 0.717 450.0 201.0 93 64/64
# 10-H TBG 0.629 400.0 229.0 97 24/64
# 11-H TBG 1.200 550.0 230 115 64/64
# 4-H TBG 0.200 1200.0 ? 89 64/64
# 9-H TBG 4.000 1250.0 ? 118 36/64
# 13-H CSG 10.600 6308.0 1244.0 127 18/64
# 14-H CSG 9.200 5800.0 1238.0 115 17/64
TOTAL - 33.431 - - - -

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Table 3 shows the operating conditions of the compressor.
Table 3. Compressor operating conditions.
Compressor #MC1661
P- suction 180.0 psig
P- discharge 1200.0 psig
3. Gas production from Retama Field: 6.0 MMSCFD @ 200.0 psig y 100°F
(approximate).
4. Maximum ambient temperature: 38 °C (100.4 °F). Represents the critical
condition for the hydraulic calculation.
5. Each well has a gas-liquid separator in location, for this hydraulic analysis is
considered gas-liquid separation with 100% efficiency.

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6. Schematic of the gas handling and gathering system of Laredo Energy - Ellen East Field.
Figure 2. Schematic of the gas handling and gathering system of Laredo Energy - Ellen East Field.
Description: Each well has a gas-liquid separator in location, the liquid flows to a storage tank located on site and the gas flows
to the gas gathering system. Well # 12-H flows through Lean Line to Ellen East Drip Station. Wells # 1-H, # 2-H, # 3-H, # 6-H, #
8-H, # 10-H and # 11-H flow into Reach Line (Header), then the total stream of the 7 wells are mixed downstream with the gas
stream from the Retama field, and then mixed, they feed the compressor where they are pressurized up to 1200 psig. Similarly,
the discharge stream from the compressor is mixed with the stream from well # 12-H, and together they flow to Ellen East Drip
Well
#12-H
Well
#6-H
Well
#3-H
Well
#1-H
Well
#2-H
Well
#8-H
Well
#10-H
Well
#11-H
Well
#4-H
Well
#9-H
Well
#14-H
Well
#13-H
Legend
NC: Normally Closed
NO: Normally Open
6" 600
3.55 mi
NO NO NO NO NO NO NO
NC NC NC NC NC NC NC NC
Compressor
Station
12" 600 12" 6006" 600
2.55 mi 0.69 mi 0.85 mi
3" 600 3" 600 3" 600 3" 600 3" 600 4" 600 3" 600
3" 600 3" 600 3" 600 3" 600 4" 600 3" 600 3" 600
3" 600
Ellen East
Drip Station
1648 ft
6" 600
6" 600
Retama
Stream
Pd=1200psig
Ps=180 psig
LineExtension

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Station. This new stream formed by the 8 wells, downstream, is mixed with the individual gas
streams from wells # 4-H, # 9-H, # 13-H and # 14-H, and finally the stream from the 12 wells
mixed with the production of the Retama field flowing towards Ellen East Drip Station.
5. HYDRAULIC EVALUATION CRITERIA
 API RP 14E: Erosional gas velocity equal to 60 ft/s.
 Minimum allowable operating pressure in Ellen East Drip Station: 1000.0 psig
(minimum delivery pressure to another operator).
6. METHODOLOGY
Pipeline modeling and performance, was simulated by using the commercial software
Pipephase 9.8 with the follow considerations:
1. Select simulation type: Network Model.
2. Select Fluid type: Compositional.
3. Compositional Phase Designation: Rigorous Multi-Phase.
4. Unit: Petroleum.
5. Segmentation: Number of segments (20).
Figure 3. Simulation Setup Wizard.

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Building a simulation model: The simulation was constructed from the
scheme shown in FIGURE 3. The following information is loaded into the
model: 1) The compositional analysis of the gas, 2) The sizes, distances and
thickness of the pipe (standard), 3) The production and temperature of each
well, and 4) The discharge pressure of the compressor (1200.0 psig), 5) the
wall thickness 0.375 in and longitude 0.69 mi, of the 12” pipeline.
The simulation run with OLGA v1.1 2-Phase flow correlation, based on report
“Calculation of gas handling capacity of the Ellen East gas gathering system
_Rev.0” and because it is, a mechanistic correlation highly recommended by
specialists and cataloged as a best practice of the oil and gas industry.

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The figure 4 below shows the Pipephase simulation model schematic for base case.
Figure 4. Pipephase 9.8 simulation model schematic.

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Schematic model simulation for case A.
Figure 5. Pipephase 9.8 simulation model schematic for case A.

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Schematic model simulation for case B.
Figure 6. Pipephase 9.8 simulation model schematic for case.

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6. Running the simulation model:
Base case (Current operating conditions): Load the respective compositional
analysis of the gas, current operating conditions and calculate superficial
velocity of the gas (Vsg).
Case study A: (Maximum gas handling capacity - Hypothetical new well close
to the location of wells # 4-H and # 9-H - East side): Load the respective
compositional analysis of the gas, current operating condition and calculate
the maximum gas handling capacity. By trial and error until the calculated
pressure at Ellen East Drip Station equals 1000.00 psig or gas velocity
exceeds erosional velocity (60 ft/s)
Case study B: (Maximum gas handling capacity - Hypothetical new well close
to the location of well # 12-H – West side): Load the respective compositional
analysis of the gas, current operating condition and calculate the maximum
gas handling capacity. By trial and error until the calculated pressure at Ellen
East Drip Station equals 1000.00 psig or gas velocity exceeds erosional
velocity (60 ft/s).

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7. RESULTS AND ANALYSIS OF RESULTS OF HYDRAULIC CALCULATIONS
Table 4. Results of the calculation of superficial velocity of the gas (Vsg) of the gas gathering system by Laredo Energy
at current operating conditions (Base case).
Links Start point End point Ø (in)
Qgas
(MMSCFD)
Superficial
velocity (*)
(ft/s)
Erosional
Velocity
(ft/s)
API 14E
Comments
L01
Location of wells
13 and 14
Ellen East Drip
Station
12 39.433 7.56
60.00
L02
Location of wells
04 and 09
Location of wells
13 and 14
6 19.635 15.34
L03
Compressor
#MC1661
Location of wells
04 and 09
6 15.424 15.23
L04 Compressor Suction Header 6 11.921 49.79
L04: This link also manages the
production of the Retama field. It
must be monitored, in case of
sending more gas production to the
compressor.
L05
(Reach Line)
Reach Line (Header) 6 5.918 24.75
This link manages the total gas
volume of all the wells that flow to
Reach Line, therefore, it is the limit
condition for the header.
L12A, L12B
(Lean Line)
Lean Line (Header) 6 3.502 2.16
L12C Location Well 12-H Lean Line 6 3.502 2.47
(*) Superficial velocity values were calculated by PIPEPHASE 9.8. For more details see the annex A.

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Table 5. Results of the calculation of the maximun gas handling capacity (MMSCFD) of the gas gathering system by
Laredo Energy (Case study A: Maximum gas handling capacity - Hypothetical new well close to the location of wells #
4-H and # 9-H - East side).
Qgas
(MMSCFD)
Superficial
velocity (*)
(ft/s)
Erosional
Velocity
(ft/s)
API 14E
Comments
L01
Location of wells 13
and 14
Ellen East Drip
Station
12 2.889E2 58.41
60.00
Handles up to 2.889E2 MMSCFD
without flow restrictions.
L02
and 09
Location of
wells 13 and 14
6 2.691E2 51.73
L03
Compressor
#MC1661
Location of
wells 04 and 09
6 15.4247 15.23
production of the Retama field.
L05
(Reach Line)
L12A, L12B
(Lean Line)
Lean Line (Header) 6 3.5029 2.16
(*) PIPEPHASE 9.8 calculated superficial velocity values. For more details, see the annex B.

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Table 6. Results of the calculation of the maximun gas handling capacity (MMSCFD) of the gas gathering system by
Laredo Energy (Case study B: Maximum gas handling capacity - Hypothetical new well close to the location of well #
12-H - East side).
Qgas
(MMSCFD)
Superficial
velocity (*)
(ft/s)
Erosional
Velocity
(ft/s)
API 14E
Comments
L01
and 14
Ellen East Drip
Station
12 65.3823 14.42
60.00
Handles up to 26.00 MMSCFD
without flow restrictions.
L02
and 09
Location of
wells 13 and 14
6 45.5834 10.19
L03
Compressor
#MC1661
Location of
wells 04 and 09
6 41.3720 32.33
production of the Retama field.
L05
(Reach Line)
L12A, L12B
(Lean Line)
Lean Line (Header) 6 29.4502
18.94
Average
(*) PIPEPHASE 9.8 calculated superficial velocity values. For more details, see the annex C.

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8. CONCLUSIONS
 Currently, all pipelines operate away from the erosional velocity (60 ft/s), however, the
compressor suction head must be monitored, in case of sending more gas production
to the compressor.
MMSCFD of natural gas, if the well or wells are located near the location of wells # 4-H
and # 9-H and the flow line pressure is in the order of 1200.0 psig. Complying with the
best engineering practice recommended according to API standard.
MMSCFD of natural gas, if the well or wells are located near the location of well # 12-H
and the flow line pressure is in the order of 1200.0 psig. All pipelines operate away from
the erosional velocity

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9. ANNEXES
Annex A: Case study – Current operating conditions

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Annex B: Case study A (Maximum gas handling capacity - Hypothetical new well
close to the location of wells # 4-H and # 9-H - East side).

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Annex C: Case study B (Maximum gas handling capacity - Hypothetical new well
close to the location of wells # 12-H - West side)

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