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Primary contact: Fernandez, Gabriel Thomas on +966-3-8809476
CopyrightSaudi Aramco 2013. All rights reserved.
Engineering Standard SAES-A-010 26 February 2013
Gas Oil Separation Plants (GOSPs)
Document Responsibility: Process Engineering Standards
Committee
Saudi Aramco DeskTop Standards
Table of Contents
1
Scope.................................................................
2
2 Conflicts and Deviations.....................................
2
3
References.........................................................
3
4
Definitions...........................................................
4
5 GOSP Product Specification.............................. 7
6 Overall Process Design......................................
8
7 GOSP Equipment Design Considerations.... 10
7.1 Flowlines/Trunklines 7.2 Production Manifold 7.3 Production
Separators 7.4 3-Phase Production Separators 7.5 2-Phase Production
Separators 7.6 Charge Pumps 7.7 Crude Oil Dehydration/Desalting 7.8
Booster/Shipping Pumps 7.9 Gas Compression 7.10 Gas
Conditioning
8 Auxiliary Systems.............................................
21
8.1 Wash Water Systems 8.2 Chemical systems 8.3 Hot Oil Systems
8.4 Closed Drain System 8.5 Instrument and Plant Air Systems 8.6
In- Plant Piping
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Document Responsibility: Process Engineering Standards Committee
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Next Planned Update: 26 February 2018 Gas Oil Separation Plants
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Page 2 of 32
Table of Contents (contd)
9 GOSP De-Bottlenecking...................................
26
Appendix I Simplified Schematic of Satellite On-Shore
GOSP........................... 27
Appendix II Simplified Schematic of Off-Shore
GOSP......................................... 28
Appendix III Simplified Schematic of Simple GOSP with Gas
Compression. 29
Appendix IV-Simplified Schematic of Complex GOSP with Gas
Compression and Crude Stabilization.. 30
Appendix V Simplified Schematic of Hot Oil
System............................................ 31
1 Scope
1.1 This Standard provides the minimum mandatory requirement for
the design of a
grass root Gas Oil Separation Plant (GOSP) with or without crude
stabilization.
1.2 The standard also provides the minimum requirement for
debottlenecking an
existing GOSP.
1.3 The crude Oil stabilization, Produced water treatment &
disposal and Heat
Exchangers are excluded from the scope of this standard.
Other support systems that are part of the GOSPs (e.g. Fire
water system, Fire &
Gas detection, Plant alerting & Alarm system, Safety
equipment, Flare system,
etc.) are also excluded from this standard. These shall be
referenced in the
relavant SAESs.
2 Conflicts and Deviations
2.1 Any conflicts between this standard and other applicable
Saudi Aramco
Engineering Standards (SAESs), Materials System Specifications
(SAMSSs),
Standard Drawing (SASDs), or industry standards, codes, and
forms shall be
resolved in writing by the Company or Buyer's Representative
through the
Manager, P&CSD of Saudi Aramco, Dhahran.
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Document Responsibility: Process Engineering Standards Committee
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2.2 Direct all requests to deviate from this standard in writing
to the Company or
Buyer's Representative, who shall follow internal company
procedure SAEP-302
and forward such requests to the Manager, P&CSD of Saudi
Aramco.
3 References
All referenced Specifications, standards, Codes, Forms, Drawings
and similar material
shall be considered part of this standard and shall be the
latest issue (including all
revisions, addenda and supplements unless stated otherwise).
3.1 Saudi Aramco References
Saudi Aramco Engineering Procedures
SAEP-14 Project Proposal
SAEP-250 Safety Integrity Level Assignment &
Verification
SAEP-302 Instructions for Obtaining a Waiver of a Mandatory
Saudi Aramco Engineering Requirement
SAEP-354 High Integrity Protective Systems Design
Requirements
SAEP-363 Pipeline Simulation Model Development and Support
SAEP-364 Process Simulation Model Development and Support
SAEP-1663 Design Guidelines for Gas Oil Separation Plant
(GOSP)
Saudi Aramco Engineering Standards
SAES-A-020 Equipment Specific P&ID Templates (ESPT)
SAES-A-400 Industrial Drainage Systems
SAES-A-401 Closed Drain Systems (CDS)
SAES-A-403 Off-Shore Platform Drainage Systems
SAES-B-006 Fireproofing for Plants
SAES-B-014 Safety Requirements for Plants and Operations
Support Buildings
SAES-B-062 Onshore Well Site Safety
SAES-D-001 Design Criteria for Pressure
SAES-H-001 Coating Selection and Application Requirements
for
Industrial Plants and Equipment
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Document Responsibility: Process Engineering Standards Committee
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SAES-H-002 Internal and External Coatings for Steel Pipeline
and Piping
SAES-J-005 Instrumentation Drawings and Forms
SAES-J-601 Emergency Shutdown and Isolation Systems
SAES-J-901 Instrument Air Supply Systems
SAES-K-402 Centrifugal Compressors
SAES-L-100 Applicable Codes and Standards for Pressure
Piping Systems
SAES-S-020 Oily Water Drainage Systems
SAES-Z-003 Pipelines Leak Detection Systems
Saudi Aramco Best Practices
SABP-A-015 Chemical Injection Systems
SABP-A-018 GOSP Corrosion Control
SABP-A-036 Corrosion Monitoring Best Practice
SABP-K-401 Site Performance Testing of Centrifugal
Compressors
3.2 Industry Codes and Standards
American Petroleum Institute
API SPEC 12J Specification for Oil and Gas Separators
Institute of Electrical and Electronic Engineers (IEEE)
IEEE 519 Guide for Harmonic Control and Reactive
Compensation of Static Power Converters
4 Terms and Definitions
AC: Alternating Current
AC/DC: Alternating Current/Direct Current
AFD: Adjustable Frequency Drive
APSD: Advanced Process Solutions Division
BPD: Barrels Per Day
BS&W: Basic (Bottom) Sediments and Water
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CDS: Closed Drain System
CFD: Computational Fluid Dynamics
CML: Corporate Model Library
Crude Types: (Degree API: Typical range for various Saudi Aramco
crudes)
ASL : Arab Super Light (49-52 API)
AXL : Arab Extra Light (37-41 API)
AL : Arab Light (32-36 API)
AM : Arab Medium (28-32 API)
AH : Arab Heavy (26-28 API)
CSD: Consulting Services Department
DCS: Distributed Control System
Dehydrator: Electrostatic Coalescer for removal of majority of
water and salt from
Crude Oil.
Desalter: Electrostatic Coalescer for removal of residual Water
and salt from crude oil.
(Identical to dehydrator).
DBSP: Design Basis Scoping Paper
Disposal Water: Treated produced water for downhole/surface
disposal/injection
DFD: Dual Frequency Desalter
DF-LRC: Dual Frequency-Load Responsive Controller
DPD: Dual Polarity Desalter
E&P: Exploration and Production
EIV: Emergency Isolation Valve
EPD: Environmental Protection Department
ESD: Emergency Shutdown
ESI: Emulsion Separation Index to measure Emulsion Stability
ESP: Electrical Submersible Pump
FEA: Finite Element Analysis
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FEED: Front End Engineering Development
Flowline: Pipelines connected to a single Oil, Gas or water
wells for production or
Injection.
Formation (Produced) Water: Water produced from Reservoir with
Oil and Gas
production
FPD: Facilities Planning Department
GOR: Gas Oil Ratio in Standard Cubic Feet of Gas per Barrel of
Stock Tank Oil
GOSP: Gas Oil Separation Plant
GOSP (Satellite): Onshore Gas Oil Separation Plant without oil
dehydration/desalting,
produced water separation and treatment facilities
GOSP (Offshore): Offshore Gas Oil Separation Plant without
oil
dehydration/desalting, produced water separation and treatment
facilities
EPD: Environmental Protection Department
H2S: Hydrogen Sulfide
HP: High Pressure
HPPT: High Pressure Production Trap (2 or 3-phase separator)
Injection (Power) Water: Treated Sea Water or aquifer water for
reservoir pressure
support
IPPT: Intermediate Pressure Production Trap (2 or 3-phase
separator)
L/D: Length to Diameter Ratio
LPDT: Low Pressure Degassing Tank (2 or 3-phase separator)
LPPT: Low Pressure Production Trap (2 or 3-phase separator)
MBCD: Thousand Barrels per Calendar Day
MBOD: Thousand Barrels per Operating Day
MBOD= MBCD/Overall Operating Factor
MCC: Mechanical Completion Certificate
MOC: Management of Change
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MOV: Motor Operated Valve
OOK: Out of Kingdom
OSPAS: Oil Supply Planning and Scheduling Department
Overall Operating Factor: Factor accounting for shrinkage and
downtime (Fraction)
PPM: Parts Per Million
P&CSD: Process and Control Systems Department
P&FDD: Production & Facilities Development
Department
PFD: Process Flow Diagram
P&ID: Piping and Instrumentation Diagram
PM&OU: Process Modeling & Optimization Unit
Production Manifold: Piping manifold where all incoming
Trunklines/Flowlines
combine within the GOSP battery limit to feed the production
Trap
PTB: Pounds of salt per thousand Barrels of Crude oil
Remote Production Manifold: Piping Manifold where
Trunklines/Flowlines combine
into one Trunkline outside the GOSP fence to feed the GOSP
Production manifold
RMD: Reservoir Management Department
RVP: Reid Vapor Pressure
Shrinkage: Decrease in oil volume caused by the evaporation of
solution gas or by
lowering of fluid temperature during storage
Stock Tank Oil: Stabilized dry oil as it exists at atmospheric
conditions in a stock tank.
TDS: Total Dissolved Solids
TEG: Tri-Ethylene Glycol
Trunkline: Pipeline to which two or more flowlines are
connected
TT: Temperature Transmitter
Turndown: The ratio of normal maximum flow to Minimum
controllable flow of the
GOSP, expressed in a percentage
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TVP: True Vapor Pressure (@ temperature)
VSD: Variable Speed Drive
Wash Water: Low salinity water used to wash the crude oil and
dilute the formation
water in the crude desalting process.
Water cut (Percent): Produced water rate*100/(Crude rate+
Produced water Rate)
Well-head Piping: Piping system connecting the well head to the
flowline first
isolation valve
WOSEP: Water Oil Separator. Collect and treat separated water
mainly from the
3-phase separators and dehydrator to remove the entrained oil
before disposal to the
reservoir.
5 GOSP Product Specification
5.1 Desalted Dry Crude
- Salt-in-Crude to Pipeline: 10 PTB (Max)
- BS&W to Pipeline: 0.2 Vol% (Max)
5.2 Stabilized Crude (for GOSPs with Stabilizers)
- H2S in Crude: 70 PPM by weight (Max)
30 PPM by weight (Design conditions)
1-60 PPM by weight (Operating Range)
- True Vapor pressure 13 psia (Max) at export or storage
temperature,
(whichever is higher).
5.3 Disposal Water (for GOSPs with Produced Water Treatment
Units)
- Target Oil-in-water 100 mg/L (Max), when treated produced
water is
injected in oil reservoir for pressure maintenance
When treated produced water is injected in tighter disposal
reservoir:
- Target Oil-in-water As stated by RMD,
Note: The 100 mg/L mg/L oil-in-water of disposal water quality
is the maximum allowable requirement. The required Disposal water
quality is to be specified by Upstream based on the disposal
reservoir permeability and the economics of the water disposal over
the life Cycle. DBSP shall refer to the final agreed disposal water
specification.
- Disposal Header Pressure: Specified by E&P based on
Injection well pressure
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Document Responsibility: Process Engineering Standards Committee
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Note: Maximum injection pressure is recommended to be below 3000
psig at disposal pump shut off so that 1500# rating disposal piping
can be used.
6 Overall Process Design
6.1 The GOSP design shall progress through conceptual study,
pre-DBSP study,
DBSP approval, Project Proposal or FEED followed by Detailed
Design and
construction. The data required to conduct GOSP process studies
during the
various phases shall be referred in SAEP-1663. RMD/P&FDD
shall provide the
required data. The necessary Safety Reviews (HAZOP, SIL,
Building Risk
Assessment, etc.) shall be conducted per applicable sections of
SAEP-14,
SAES-J-601, and SAES-B-014 respectively.
6.2 The Base Case production option and other alternative
production Options shall
be finalized in discussion with Upstream, P&CSD and FPD.
6.3 Simulations
6.3.1 Steady State Process simulation shall be based on the
latest version of
the approved simulation Software package based on SAEP-363
and
SAEP-364. The Process simulation software package that will be
used
in the project shall be concurred by P&CSD.
6.3.2 The GOSP simulations shall be carried out for summer and
winter
conditions at Design Water cut, initial Water cut and
intermediate
production phase.
6.3.3 The Gas compression simulations shall be carried out for
summer and
winter conditions. The gas compression to be sized on the
controlling
gas rates based on the simulations.
6.3.4 The Process simulation during the FEED and Detailed Design
Phase
shall be reviewed and approved by P&CSD.
6.3.5 The Final Process simulation models shall be included as
part of the
project deliverable during the FEED and Detailed Design
Stage.
All final process simulation models, with their documentation,
during
FEED and Detailed Design stage shall be delivered to P&CSDs
CML coordinator through document transmittal.
6.3.6 Transient Dynamic process simulation shall be performed
for each gas
compressor system during the detailed design stage to confirm
the
functionality of the compressor control system under all
start-up,
operating and shutdown conditions per SAES-K-402.
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6.3.7 Transient Dynamic simulations shall also be performed on
parallel gas
compression trains to confirm the functionality of the
compressor
control system during start-up, operating and shutdown
conditions of
individual or multiple gas compressors.
6.3.8 The Transient Dynamic simulations of the Gas compressors
individually
and combination of parallel trains shall be reviewed and
approved by
P&CSD/APSD/PM&OU. The final dynamic Simulation Models
shall
be delivered to P&CSDs CML coordinator as part of the
MCC.
6.4 PFDs
6.4.1 Preliminary PFDs showing the heat & material balances
for Summer and
Winter conditions of the GOSP and the crude stabilizer (if
included in
the GOSP) for the following conditions shall be developed:
6.4.1.1 Design Water Cut
6.4.1.2 Initial Water cut
6.4.1.3 Final Water Cut
6.4.2 The Preliminary PFDs showing the Heat & Material
Balances for
Summer and Winter conditions shall be developed for the Gas
compression. Preliminary gas export pipelines pressure shall
be
available to determine the Gas compression HP requirement.
6.4.3 Energy System Optimization Assessment study shall be
conducted
based on the preliminary PFDs per SAEP-14. The energy
optimization
shall satisfy all operating conditions for summer, winter and
the life
cycle of the project per paragraph 6.8.1.
6.4.4 The simulations and PFDs to be finalized after completing
the Energy
system Optimization Assessment Study.
6.4.5 Stream Data for Summer, Winter and Design condition shall
be
provided in the PFDs.
6.5 P&IDs
6.9.1 SAES-A-020 shall be used as a building block to develop
the project
P&IDs.
6.9.2 SAES-J-005 provides the Instrument data to be included in
the P&IDs.
The following additional instrument data shall be included in
the P&IDs:
a) Orifices- Orifice Bore and Flow Transmitter Range
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b) Control Valves- Tight Shut-Off requirement
c) Level Transmitter- Type of level transmitter, Calibration
Range
d) Additionally, the vessel template shall show the various
level
alarm settings as height from vessel bottom for horizontal
vessels
and Tan line for Vertical vessels. Level alarm settings shall
be
shown as actual levels (instead of percentages) in DCS block
or
display.
e) Level Gauge: Type of Level Gauge, backlighting
requirement
f) Temperature Transmitter- Type of TT and Range. Alarm
setting
on the DCS block or display
g) Temperature Gauge- Range of Temperature Gauge
h) Pressure transmitter/gauge- Range of the pressure
transmitter/gauge. Alarm settings on the DCS block.
i) All shutdown switch settings
j) All shutdown Alarms shall be shown connected to the
Sequence
of Events Recorder.
Note: The above required instrument details can be included in
SAES-J-005.
6.10 All the GOSP shall be designed for 40% turndown. For GOSPs
with crude
stabilization, the stabilizer column turndown will be the
controlling factor for
the GOSP turndown.
6.11 All GOSPs shall be designed for Wet Sour Service for
potential souring of the
production field during the life cycle unless RMD recommends
otherwise.
7 GOSP Equipment Design Considerations
7.1 Flowlines and Trunklines
7.1.1 Flowlines and trunklines sizing shall be based on
transient simulations
over the full field life including turndown conditions and
trunkline
scraping. The outcome of the transient analysis shall be applied
in the
design of GOSP.
7.1.2 The selected trunkline size shall satisfy both minimum and
maximum
velocities at minimum water cut and design water cut
including
turndown.
7.1.3 The flowlines and trunkline network shall be designed to
the maximum
shut-in pressure of the field including future artificial lift
(Gas lift, ESP
or multiphase pump).
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Note: For existing Flowline/Trunkline networks, HIPPS to be
evaluated in accordance with SAEP-250 and SAEP-354 if the shut-in
well head pressure exceeds the design pressure.
7.1.4 Slug flow in trunklines shall be avoided and slug
mitigation measures
to be provided to minimize production trap level and pressure
upsets.
7.2 Production Manifold/Header
7.2.1 For new GOSPs the Production manifold and the production
header to
the last block valve to the inlet of the first production
Separator (Trap)
shall be designed for the maximum shut-in pressure of the
field
including future artificial lift (Gas lift, ESP or multiphase
pump).
Note: For existing GOSPs, HIPPS to be implemented at the subject
well-heads that exceeds the design pressure of the production
manifold.
7.2.2 Flowline/Trunkline connections to the Production Manifold
shall be
from the Top for new facilities.
7.2.3 As per RMD/P&FDD requirements, spare connections with
blinds
shall be provided on the production manifold for connecting
future
trunklines. To avoid dead legs, the active trunklines to be
connected at
the ends of the production manifold with the spare connections
in the
middle.
7.2.4 Each crude increment shall have its own production
manifold and all
trunklines shall be connected to the individual increment
production
manifolds. This will enable selecting the trunklines to the
desired
increment for uniform distribution of the field production to
the
individual crude increments.
7.2.5 Two parallel production separators (HPPTs) can be
connected to one
production manifold with symmetrical piping arrangement
downstream
of the T dividing the flow to the two production separators.
However, the inlet to the T shall be from below the horizontal.
7.2.6 Long Radius elbows (5D) shall be provided on the
production header
downstream of the inlet ESD valve to the first Production
Separator.
7.2.7 The inlet header from the production manifold to the first
production
separator shall be sized to avoid mist/spray flow.
7.3 Production Separators
7.3.1 The number of Flashing stages and Flash pressures in the
GOSP for the
crude production shall be determined by Upstream in consultation
with
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P&CSD and FPD based on life cycle economics during the
initial field
development study.
7.3.2 The flash stage pressures shall be based on Flowing well
head
Pressures, Individual stage GORs, reservoir production strategy
over
the field life and crude type to optimize production cost during
the
field life and maximize reservoir recovery.
Note: The number of flash stages increases at higher GOR and
higher Flowing Well Head pressures to optimize the gas compression
cost.
7.3.3 The number of flash stages and flash pressures shall be
specified in the
DBSP along with the flash stage descriptions.
7.3.4 The following requirements shall be met in all production
Separators:
The bottom of the feed inlet nozzle shall be at least 6 above
the HH liquid level shutdown
Perforated (not Slotted) Anti-Wave baffles shall be
provided.
Any internals for optimum separation efficiency shall be
selected based on the results of the Computational Fluid Dynamic
Model.
The low low liquid level alarms and shutdowns shall be minimum
12 above the bottom of the vessels.
Vortex breakers shall be provided in all liquid outlet nozzles
of production separators
Non-Slam type check valve shall be provided on the common Gas
outlet
All gas relief valves shall be installed directly above the
vessel with minimum pipe length.
7.3.5 Crude oil heat exchanger shall not be located between the
production
manifold and the first production separator.
7.3.6 The first Production Separator receiving the well
production fluids
from the production manifold shall be equipped with suitable
inlet
device (Vane type, impingement plate or cyclonic device). The
inlet
device shall be designed to withstand the forces over the full
operating
range based on transient simulation of the flowline/trunkline
network.
Note: Finite Element Analysis (FEA) of the inlet device support
structure is recommended.
7.3.7 Mist eliminators shall be provided in production separator
vessels to
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minimize liquid carry over in the Gas. Liquid carry over in gas
shall
be less than 1 gal/MMSCF.
7.3.8 The design pressure of Tanks in low pressure production
separation
service shall be minimum 10 psig.
7.4 GOSP Three Phase Production Separators
7.4.1 The 3-phase Production Separator shall be designed for the
design
water cut or minimum 30% water cut whichever is higher.
7.4.2 Typical liquid retention (Holdup) time for water-oil
separation shall
comply with API standard, i.e., API Spec 12J.
7.4.3 The minimum seam-seam to Vessel Diameter ratio (L/D) shall
be 7 for
the horizontal 3-phase production separator vessel.
7.4.4 The water weir for the 3-phase production separator vessel
shall be
located at least one vessel diameter from the vessel tan
line.
7.4.5 The normal oil level in the 3-phase production separator
vessel shall be
at least 6above the Weir top. The High-High Interface level
alarm setting shall be at least 6 below the weir top.
7.4.6 Following are the minimum surge times between different
level settings
for the 3-phase production separator vessels based on design
flow rates:
Between High High oil level shutdown and High oil Level alarm: 1
Minute
Between High oil Level alarm and Low Oil level alarm: 3
minutes
Between High High interface level alarm and high interface level
alarm: 2 Minutes or 6 height
Between High interface and Low interface alarms: 5 minutes or 1
height
Between Low interface and Low Low interface shutdown: 3 minutes
or 1 height
7.4.7 The nozzles for the interface level instruments shall be
located close to
the water weir. The nozzles for the interface level instruments
shall be
taken from the side of the vessel.
7.4.8 The selected 3-phase separator sizing shall be approved by
P&CSD.
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7.5 Two Phase Production Separators
7.5.1 The 2-phase production separator upstream of the crude
oil
dehydration/desalting train shall be sized for 30% water
cut.
7.5.2 The minimum seam-seam to Vessel Diameter ratio (L/D) shall
be 7 for
the horizontal 2-phase production separator vessel.
7.5.3 The typical retention time (Hold up) for Gas-oil
separation for 2-phase
vessels are given in API SPEC 12J.
7.5.4 Following are the minimum surge time between the oil-level
settings
based on design flow rates:
Between High High Oil level shutdown and High Oil level alarm: 2
Minutes
Between High Oil level alarm and Lo Oil level alarm: 2
Minutes
Between Lo Oil level alarm and Lo Lo oil level shutdown: 1
minute
7.5.5 The selected 2-phase separator sizing shall be approved by
P&CSD.
7.6 Charge Pumps
7.6.1 Minimum 3 x 50% capacity charge pumps shall be provided
for
pumping the wet crude through the crude desalting train.
7.6.2 The charge pumps shall be Vertical Can type. Gas supply
connection
shall be provided to pressurize the pump can to displace the wet
crude
to the suction vessel.
7.6.3 The charge pump isolating MOVs (EIVs) shall be located
outside the fire hazard zone as defined by SAES-B-006 to avoid the
need of
fireproofing
7.6.4 The charge pump discharge pressure at pump shut-off shall
not exceed
the design pressure of the dehydrator and desalter vessels.
7.6.5 The charge pump seals shall be flushed by dry crude oil or
other
suitable buffer fluid.
7.7 Crude Oil Dehydration and Desalting (Production Field)
7.7.1 For GOSPs processing AXL and AL crude grades, minimum two
stage
dehydration/desalting shall be provided to minimize instances of
off-
spec crude to the crude stabilizer/pipeline during electrostatic
grid upsets
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or crude production interruptions during maintenance of one
stage.
7.7.2 For GOSPs processing AM and AH crude grades minimum 3
stage
dehydration/desalting shall be provided.
Notes: Two stage dehydration/desalting can be considered in AH
and AM crude production with new technology internals provided the
Vendor is guaranteeing the desalted crude specification with single
stage operation at minimum 60% dry crude throughput. The two-stage
desalting in AH and AM crude service shall be concurred by both
P&CSD and Operations.
For ASL crude grade and Khuff gas condensate processing, the
need of crude desalting to be evaluated based on the formation
water TDS and Emulsion stability Index to meet the specification to
the pipeline.
7.7.3 The dehydrator and desalter piping configuration shall be
designed to
operate with the any one vessel bypassed at a time. The
bypass
capability shall be provided for both vessels.
7.7.4 Where reservoir pressure support is provided by power
water injection,
the crude dehydration and desalting trains shall be designed for
30%
water cut. Reduced trims to be installed on control valves for
better
controllability during the initial production phase where the
water cut
is low.
7.7.5 The dry crude viscosity in all desalting vessels shall be
below 10 cP
and preferably below 5cP. The feed to the dehydrator/desalter
shall be
heated to achieve the desired viscosity.
7.7.6 The operating pressure of the last stage desalting vessel
shall be at least
25 psig above the vapor pressure of the crude at the
operating
temperature. Power to the electrical grids shall be switched off
after a
time delay of 20 sec if the last stage desalter pressure drops
to 10 psig
above the crude vapor pressure. The system shall be designed to
allow
for a 20 sec delay for 10 psi below vapour pressure. The crude
export
to pipeline shall be stopped if the power is not restored to the
electrical
grids within 5 minutes.
7.7.7 Recommended Desalting technologies:
- AC Field Desalting: Double volt; Tri-Volt; 0-30% Water cut
Note: AC Field Bi-electric designs with emulsion feed
distributed between the grids shall not be used in the production
field. Bi-electric desalting designs shall be limited to refinery
applications.
- Dual Polarity Desalting: AC/DC field 0-10% water cut
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- Dual Frequency Desalting: Upgrade of Dual Polarity
Desalting
technology with Frequency modulation and Arc control. 0-30%
water cut
7.7.8 Minimum two levels of charged grids (double volted) shall
be
provided for the AC field dehydrator/desalter in the production
field.
Single Volted Electrical grid configuration (Bottom grids
charged and
Upper Grid Grounded) shall not be used in the production
field.
7.7.9 The electrostatic grids of AC field and DPD shall be
charged by
3 single phase step-up transformers. The preferred primary
supply
voltage to the AC field and DPD technology transformers is
4160 Volts. The transformers shall be equipped with external
tap
changers to adjust the secondary voltage for the required
voltage level.
7.7.10 The electrostatic grids of the DFD desalters shall be
charged by
3 power units. The primary supply to the Power units shall
be
480 volts, 3 Phase, 60 Hz. The DFD power unit harmonics level
shall
be below the TIF values identified within IEEE 519. If necessary
a
filtering system shall be used to meet the criteria.
7.7.11 The AC field desalters shall be equipped with Carbon
Steel rod type
electrostatic grids. The rods shall run parallel to the length
of the
desalters and not across the cross-section. At least 6 clearance
shall be provided between the rod ends and the vessel dished end to
prevent
arcing to the vessel wall.
7.7.12 Carbon Steel Plate electrostatic grids shall be provided
for DPD and
DFD technology desalters. The DPD desalters are limited to
0-10%
water cut due to the lack of arc control which could potentially
damage
the carbon steel plates. The DFD desalters are equipped with
arc
control and additionally will drop out majority of the water
before it
reaches the grids. Composite plates are not recommended due to
the
short service life.
7.7.13 Oil immersed High pressure entrance bushings rated above
the
maximum secondary voltage of the transformer shall be provided
to
connect the transformer secondary to the vessel internal grids.
High
pressure bushing is also recommended at the transformer
secondary.
7.7.14 Vessel nozzle size for the entrance bushing shall be
minimum 6, 300# rating. A spacer with vent connection between the
vessel nozzle
and the entrance bushing standpipe shall be provided to
eliminate
vapor. The spacer vent shall be connected to the oil outlet
pipe.
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7.7.15 The entrance bushing standpipe shall be equipped with a
transparent
type level gauge and a sampling point for periodic sampling of
the
standpipe oil for analysis of di-electric constant on a
quarterly basis as
a minimum.
7.7.16 Emulsion Feed distributors shall be designed based on CFD
modeling
for uniform distribution of the feed over the electrical grid
area and
prevent channeling/ recirculation. The distance between the top
of the
feed distributor and bottom of the charged grids shall be
minimum
3.3 feet (1 meter).
7.7.17 Electrical grid loading for the AC field desalting
systems in the
production field shall be the following:
AXL crude service: 150 BPD/Square Feet of grid area
AL crude service: 150 BPD/Square Feet of grid area
AM crude service: 110 BPD/Square Feet of grid area
AH crude service: 80 BPD/square Feet of Grid area
Note: The above grid loading is field proven with the minimum
life cycle operating costs for the AC field systems.
7.7.18 Internal Interface skimming header and water (sand)
jetting header
shall be provided. Interface sampling valves to collect
interface
samples shall be provided.
7.7.19 All internal piping below the center line of the vessel
shall be
internally and externally coated.
7.7.20 Minimum 2 out of the following 3 types of interface
measuring devices
shall be provided to control the interface level:
Nucleonic type- Top mounted
Microwave type (2 probes)- Side mounted
External displacer type directly mounted on vessel nozzles
Flexibility shall be provided to select any one of the
interface
measuring instruments to control the interface level.
Note: Nozzles shall be provided for installing all three types
of instruments. Adequate clearance and space shall be provided to
measure the various interfaces including solids at the bottom of
the vessel. The probes shall be retrievable type for on-line
maintenance.
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7.7.21 Two Transparent type interface monitoring sight glasses
with
backlighting shall be provided. The sight glasses shall be
located at
both ends of the vessel and directly connected to vessel nozzles
taken
from the side.
7.7.22 Level switch shall be installed and connected to
permissive circuit to
ensure the vessel is filed with liquid before applying the
power.
7.7.23 Internal floats shall be provided to ground the grids in
case the crude
oil level drops for AC field and DPD technology. For DFD
technology, external level switch to be connected to the ESD
system to
switch-off power in case of falling oil level.
Note: For DFD technology internal floats to ground the grids is
not recommended due to concern on life expectancy of the
electronics.
7.7.24 For AC field and DPD technology desalters a local panel
shall be
provided with a power switch, transformers secondary voltage
indication, current indication, green/red pilot lights for each
secondary
phase and a local panel light. The transformer secondary voltage
shall
also be indicated in the DCS.
7.7.25 For the DFD technology desalters all feed-back signals
and control
signals that are displayed in the DF-LRC II panel shall be
interfaced to
the DCS system.
7.7.26 GOSPs with crude desalting shall be designed to start on
wet crude.
GOSPs shall be designed for recycling off-spec dry crude.
7.7.27 Online BS&W analyzers shall be provided at the outlet
of the desalter.
Insertion type sample take off installed on vertical main pipe
to be
provided for representative stream.
Note: Online salt-in-crude analyzer (without using chemicals) to
be tested to prove the accuracy and repeatability.
7.7.28 The Dehydrator/Desalters shall be designed to withstand
the shut-off
head of the charge pump with the design margin per
SAES-D-001.
7.8 Booster and Shipping Pumps
7.8.1 Variable speed drives shall be evaluated for crude oil
shipping pumps
without booster pumps.
7.8.2 The Booster pumps and Shipping Pumps isolating MOVs (EIVs)
shall be located outside the fire hazard zone as defined by
SAES-B-006 to
avoid the need of fireproofing.
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7.9 Gas Compression
7.9.1 Each GOSP gas compressor shall be provided with its own
suction
drum, after cooler and compressor discharge KO drum.
Notes: Individual Compressor discharge drum can be deleted in
lean gas compression where negligible liquids are formed after
cooling.
7.9.2 Compressor suction drum shall be equipped with mist
eliminator to
remove 99.99% liquid droplets of 6 microns and larger. Fiber
Glass or
other synthetic coalescing packing shall not be used in the
compressor
suction drums. Large capacity HP gas compressors suction drums
in
the GOSPs shall be equipped with V type mist eliminator.
7.9.3 CFD shall be performed on the gas compressor suction drum
to
confirm the liquid removal efficiency over the full operating
range of
the compressor.
7.9.4 The compressor discharge temperature under normal
operating
conditions shall not exceed 320F. For higher compressor
discharge temperatures, the materials selected, specially the O
rings for H2S service shall be approved by CSD.
7.9.5 Variable Speed drives shall be evaluated for all gas
compressors based
on SAES-K-401 and SAES-K-402. However, the GOSP gas
compressor energy consumption over the life cycle shall take
into
consideration the crude production forecast, fluctuations in
crude
production rate and energy loss due to compressor recycling. The
life
cycle economics of compressor driver selection report shall be
submitted
to CSD, P&CSD/UPED and P&CSD/Energy division for
review.
7.9.6 The number of gas compressors shall be determined based on
the
production forecast over the life cycle of the project to
minimize
compressor recycling.
7.9.7 Spare gas compressor shall be provided to eliminate gas
flaring.
Reduction of crude rate and operating on one gas compressor
is
acceptable.
Note: The deletion of spare gas compressor shall be concurred by
Operating organization, P&CSD/UPED and EPD.
7.9.8 Besides the normal operating point, 3 other operating
points for summer,
winter and 105% of the normal gas rate shall be specified in
the
compressor data sheet. The rated point of the compressor shall
be
selected by the manufacturer based on these conditions per
SAES-K-402.
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7.9.9 Fixed speed motors of Spheroid and LP gas compressor shall
be sized to
start the compressor at normal operating pressure. Refer
SAES-K-402
for start-up capability requirements of fixed speed motors for
low
suction pressure gas compressors.
7.9.10 Field performance testing shall be conducted on all new
process gas
compressors within 6 months of start-up or immediately after
overhaul
to establish the baseline performance per SABP-K-401.
Compressor
performance testing to repeated on a 3-6 years interval in
GOSPs.
All compressor performance records shall be maintained by
the
respective plant engineering Unit.
7.9.11 The maximum approach temperature of after cooler (Air) is
15F based on summer design dry bulb temperature @ 1%.
7.10 Gas Dehydration and Hydrocarbon Dew Point Control
7.10.1 Gas dehydration and hydrocarbon dew point control shall
be provided
in the following applications:
Lift Gas for producing wells
Sub-sea gas pipelines transporting compressed associated gas to
on-shore.
On-shore gas pipelines transporting compressed associated gas
through populated area as defined by SAES-B-062.
Note: In dense phase gas injection systems, only gas dehydration
is required to remove the water.
7.10.2 A knock out drum shall be installed upstream of the Gas
dehydration
unit coalescing filter to knock out liquid droplets carried over
in the
flashed gas from the production traps. The knock out drum shall
be
equipped with mist eliminator to remove 99.99% of liquid
droplets
6 microns and larger. Compressor discharge drums located
upstream
of the dehydration unit coalescing filter shall be equipped with
mist
eliminators to remove 99.99% of liquid droplets 6 microns and
larger.
7.10.3 The water content of dehydrated gas shall not exceed 7
lb/MMSCF.
7.10.4 Hydrocarbon dew point control units shall be designed to
eliminate
liquid dropout in the gas transfer lines.
7.10.5 The design TEG circulation rate for the TEG based gas
dehydration
systems in the production facilities shall not exceed 3 GPM per
pound
of water removal.
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7.10.6 Gas Dehydration standard is under development by
P&CSD / UPED /
GPU.
Note: The requirements for gas dehydration included in this
standard are in addition to the Gas dehydration standard.
8 Auxiliary Systems
8.1 Wash Water Systems for Crude Oil Desalting
8.1.1 The design TDS of the Wash water used in crude oil
desalting depends
on factors such as type of crude oil, formation water TDS,
BS&W at
the inlet of the final stage desalter, BS&W and
salt-in-crude
specification of the desalted crude, wash water rate and
mixing
efficiency. Water treatment systems to reduce TDS of the wash
water,
if required, shall be provided. Wash water injection points
shall be
upstream dehydrator and desalter.
8.1.2 The design mixing efficiency shall exceed 50%. High
efficiency
Mixing control valves shall be used for mixing wash water with
the
crude at the inlet of the final stage desalter. Mixing pressure
drop
range is 7 -25 psid.
8.1.3 Wash water systems for aquifer water shall be designed for
minimum
4% of the dry crude rate. Three, 50% capacity wash water pumps
shall
be provided. Provide recycle line for wash water pumps to allow
for
low wash water rates at low crude rates.
8.1.4 Wash water rate for Low TDS wash water from Flash
evaporation shall
be minimum 1.25% of the dry crude rate. Recycle pumps shall
be
provided to provide internal recycle under flow control to the
inlet of
the desalter to optimize wash water (Low TDS) consumption
and
maintain the minimum required wash water rate.
8.1.5 A gas blanketed surge drum shall be provided to receive
the wash
water from its source. The wash water shall be pumped from the
Wash
Water surge drum by the Wash Water pumps to the desalting
facility.
8.1.6 Wash water shall be controlled by flow control to provide
steady
required wash water rate to crude oil desalting. Wash water
supply
shall not be based on level control of the surge drum.
8.1.7 Water jetting header take off shall be upstream of the
wash water flow
orifice for aquifer water based wash water systems. For low TDS
wash
water systems, the desalter recycle pump discharge water to be
used
for water jetting.
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8.1.8 Sand/sludge recovery system shall be provided on the water
jetting
effluents from the dehydrator/desalter.
8.2 Chemical Systems
8.2.1 All GOSPs shall be provided with facilities for bulk
storage (tanks) and
injection of Demulsifier, corrosion inhibitor and Scale
inhibitor.
Note: The need of chemical systems for Biocide, Oxygen Scavenger
and Methanol injection need to be evaluated on a case by case
basis.
8.2.2 All chemical storage tanks and injection skids shall be
preferably
located at one location. Large chemical storage tanks shall
be
accessible for road tankers.
8.2.3 The chemical dosing pumps shall be positive displacement,
metering
type capable of adjusting the dosage rates both locally and
remotely
from the control system. Pump rate shall be confirmed by
graduated
cylinder installed on the pump suction. Refer to SABP-A-015.
8.2.4 Each chemical dosage point shall have its own dedicated
pump or
pumps discharge manifold for dedicating the pump to one
injection
point. Each chemical dosage point shall be provided with a flow
meter
to monitor the chemical dosage rate and Low flow alarm.
8.2.5 Strainers shall be provided upstream of the chemical
dosing points.
Two parallel strainers with isolation valve shall be provided
if
chemical dosing cannot be interrupted.
8.2.6 With the exception of Demulsifier and methanol, all other
chemical
dosage rates and injection locations shall be finalized in
consultation
with CSD and Plant Corrosion control. Refer to SABP-A-018
and
SABP-A-036.
8.2.7 On line corrosion monitoring system (MICROCOR or
equivalent)
shall be provided in the GOSP to monitor corrosion. The
locations for
on-line corrosion monitoring shall be reviewed with CSD and
Plant
corrosion control. Refer to SABP-A-018 and SABP-A-036.
Note: Recommended locations for on-line corrosion monitoring
are: Production Manifold, Wash water supply, HPPT water Out, LPPT
Oil out, Dehydrator water out, Disposal Water out to disposal Line,
GOSP crude to pipeline and Gas to pipeline.
8.2.8 Corrosion monitoring coupon locations shall be finalized
in
consultation with Plant Corrosion Control. Required space shall
be
provided for on-line coupon retrieval and installation tools.
Refer to
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SABP-A-018 and SABP-A-036.
8.2.9 Anode Monitoring System (AMS) shall be provided on all
vessels
(HPPT, IPPT, LPPT, Dehydrator, desalter, WOSEP) that handle
wet
crude and are installed with anodes for cathodic protection.
8.2.10 Corrosion inhibitor injection of the GOSP and crude
Pipelines shall not
be combined at one injection point at the production
manifold.
Separate corrosion Inhibitor injection (Pump, flow meter and
Injection
tubing) for the crude oil leaving the GOSP to the crude Oil
pipeline
shall be provided. The Flow meter of corrosion inhibitor
injection to
the crude pipeline shall be connected to OSPAS. This is
applicable to
all GOSPs existing and new. Refer to SABP-A-015, SABP-A-018
and
SABP-A-036.
Note: To ensure good mixing the pipeline corrosion inhibitor
injection point can be upstream of the crude tie-line control Valve
or suction of the shipping pump.
8.2.11 The demulsifier injection points shall be provided at the
production
manifold and at the inlet of the dehydrator. For multiple
desalting
trains the demulsifier injection point to be located downstream
of the
common Charge pump discharge header. Mixing devices to mix
the
injected demulsifier with the wet crude shall be provided.
Note: 3-phase demulsifier mixing device will be tested at the
production manifold. Approved mixing valve at the dehydrator inlet
is available.
8.2.12 Minimum three 100% capacity demulsifier dosing pumps
shall be
provided for demulsifier injection.
Note: Refer SAEP-1663 for typical demulsifier dosage rates for
different crude grades.
8.2.13 The Demulsifier injection rate shall be automated to
optimize the
demulsifier consumption.
Note: P&CSD/Plant Engineering to be consulted for finalizing
the Algorithms for demulsifier automation.
8.2.14 Minimum one month storage capacity shall be provided for
the
demulsifier.
8.3 Hot Oil Systems
8.3.1 Specialized Hot Oil fluids including and Diesel can be
used for heating
the crude Oil in the GOSP. The selection of hot oil fluids is
based on
the auto ignition temperature, chemical degradation potential,
scale and
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coke build up tendencies besides process heating requirements.
Auto
ignition temperature of the heating media shall be at least 50C
above the max operating temperature.
8.3.2 Hot Oil Expansion vessel shall be provided. The Hot oil
Expansion
vessel shall be provided with inert gas blanket.
8.3.3 The Hot oil return shall flow into the Hot Oil Expansion
vessel.
The Hot oil circulating pumps shall take suction from the Hot
oil
expansion vessel.
8.3.4 Minimum 3 x 50% capacity Hot Oil circulation pumps shall
be
provided. The hot oil pump suction temperature shall be
connected to
the DCS.
8.3.5 The wet crude shall be flowing through the tube side and
the hot oil
through the shell side of the hot oil heat exchanger.
8.3.6 The Hot Oil fluid pressure shall be at least 50 psig
higher than the cold
process fluid (wet Crude) pressure in the hot oil heat exchanger
to
avoid chances of process fluids leaking into the hot oil
system.
8.4 Drain Systems
8.4.1 All on-Shore GOSPs shall be provided with Closed Drain
System per
SAES-A-400/SAES-A-401 and Oily Water Drain Systems per
SAES-S-020.
8.4.2 All off-shore GOSPs, Well Platforms shall be provided with
Closed
Drain Systems per SAES-A-400/SAES-A-403 and Oily Water Drain
System per SAES-S-020.
Note: For all new GOSPs, the term Closed Drain System (CDS)
shall be used instead of Pressure Sewer System and Oily Water
Drainage System(OWDS) Instead of Gravity Sewer System ( consistent
terminology). For existing GOSPs a Master Plan is ongoing to
convert existing Pressure sewer and Gravity sewer systems into CDS
and OWDS.
8.4.3 The closed drain header from the production manifold shall
be run
separately to the CDS drum and shall not be combined with other
low
pressure closed drain headers.
8.4.4 Lined Pit shall be provided outside the GOSP Fence to
collect
emergency drains.
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8.5 Instrument Air/ Plant Air systems
8.5.1 The Instrument Air system shall be designed in accordance
with
SAES-J-901.
8.5.2 The reciprocating Instrument air compressors at on-shore
GOSPs shall
be water-cooled.
8.5.3 Plant air connection shall be provided at all utility
stations besides
nitrogen, LP steam and water connections.
8.5.4 All Instrument Air Surge drums shall be internally
prepared and coated
with heat cured phenolic coating APCS-100 in accordance with
SAES-H-002.
8.6 GOSP In-Plant Piping
8.6.1 The GOSP piping system shall be designed based on
SAES-L-100.
8.6.2 The Spec breaks between two piping codes shall be
connected by
flanges. A spectacle plate shall be provided at the spec break
flange.
8.6.3 Non-slam type Check valves shall be installed at the
following
locations:
Gas outlets of all Production Separators( HPPT, IPPT, LPPT,
LPDT)
Gas slug catchers, receiving gas from satellite GOSPs
Crude Charge Pumps, Booster Pumps and Shipping Pumps
discharge
Bypass lines of Booster and Shipping Pumps
Crude oil stabilizer gas outlet
Crude oil, Gas export lines and Water disposal line exiting the
GOSP.
8.6.4 Pipe Line Leak Detection System (LDS) shall be installed
on the crude
Oil and Gas export lines of the GOSP per SAES-Z-003. The
leak
detection signal shall close the export ESD valve to the
pipeline from the
GOSP. The Plant ESD system will activate the plant shutdown on
high
trap levels on crude oil pipeline LDS. On Gas pipeline Leak
Detection,
the export ESD valve shall close resulting in GOSP Gas
flaring.
8.6.5 All wet crude, formation water and Wasia water piping
shall be coated
as per SAES-H-001 and SAES-H-002.
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8.6.6 All bypass lines of control valves, ESD valves, Relief
valves and other
similar applications shall be sloped for self-draining on both
sides.
8.6.7 The design velocities in the low pressure piping from the
Low pressure
degassing Tanks/vessels to the Spheroid compressor shall not
exceed
40 feet/sec. The selected line size shall ensure that the
minimum
velocity criteria shall be met at turn-down.
9 GOSP De-Bottlenecking
9.1 A flare and Relief system study shall be conducted to
establish the maximum
crude capacity of the GOSP at the operating and future projected
GORs of the
field.
9.2 The plant capacity to be estimated based on the Relief and
Flare system capacity
at the operating GOR.
9.3 A process study shall be conducted to establish the
equipment or pipelines
limitation at the plant capacity established by the flare and
relief system
capacity.
9.4 A Plant test shall be conducted with concurrence from
P&CSD/UPED/OPU and
P&CSD/DPED/F&RSU to confirm the equipment
limitations.
9.5 A Management of Change (MOC) process shall be completed for
any changes to
facilities including the Design Capacity of the plant.
Revision Summary
26 February 2013 New Saudi Aramco Engineering Standard.
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Appendix I Simplified Schematic of Satellite On-Shore GOSP
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Appendix II Simplified Schematic of Off-Shore GOSP
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Appendix III Simplified Schematic of Simple GOSP with Gas
Compression
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Appendix IV Simplified Schematic of Complex GOSP with Gas
Compression and Crude Stabilization
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Appendix V Simplified Schematic of Hot Oil System