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Previous Issue: New Next Planned Update: 26 February 2018
Page 1 of 32
Primary contact: Koleshwar, Vilas Sadashivrao on +966-3-8809478
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 5 of 32
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 (49-52º API)
AXL : Arab Extra Light (37-41º API)
AL : Arab Light (32-36º API)
AM : Arab Medium (28-32º API)
AH : Arab Heavy (26-28º 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
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 6 of 32
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
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 7 of 32
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
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 8 of 32
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
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 9 of 32
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&CSD’s 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,
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 12 of 32
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
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 16 of 32
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
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 17 of 32
- 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.
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 18 of 32
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.
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 19 of 32
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 MOV’s (EIVs) shall
be located outside the fire hazard zone as defined by SAES-B-006 to
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 22 of 32
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.
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 23 of 32
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
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 24 of 32
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
Document Responsibility: Process Engineering Standards Committee SAES-A-010
Issue Date: 26 February 2013
Next Planned Update: 26 February 2018 Gas Oil Separation Plants (GOSPs)
Page 25 of 32
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