saes-a-010.pdf

Previous Issue: New Next Planned Update: 26 February 2018

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Primary contact: Koleshwar, Vilas Sadashivrao on +966-3-8809478

Copyright©Saudi 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

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)

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Table of Contents (cont’d)

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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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

http://standards/docs/SAEP/PDF/SAEP-302.PDF








http://standards/docs/Saes/PDF/SAES-A-020.PDF




http://standards/docs/Saes/PDF/SAES-B-006.PDF



http://standards/docs/Saes/PDF/SAES-D-001.PDF

http://standards/docs/Saes/PDF/SAES-H-001.PDF




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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


http://standards/docs/Saes/PDF/SAES-J-005.PDF



http://standards/docs/Best_Practices/PDF/SABP-K-402.PDF

http://standards/docs/Saes/PDF/SAES-L-100.PDF

http://standards/docs/Saes/PDF/SAES-S-020.PDF

http://standards/docs/Saes/PDF/SAES-Z-003.PDF

http://standards/docs/Best_Practices/PDF/SABP-A-015.PDF







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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 (49-52º 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




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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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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,

operating and shutdown conditions per SAES-K-402.







http://standards/docs/Saes/PDF/SAES-K-402.PDF




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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&CSD’s 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 6”above 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 MOV’s (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 MOV’s (EIVs) shall

be located outside the fire hazard zone as defined by SAES-B-006 to

avoid the need of fireproofing.

http://standards/docs/Saes/PDF/SAES-D-001.PDF





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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.



http://standards/docs/Saes/PDF/SAES-L-100.PDF

http://standards/docs/Saes/PDF/SAES-Z-003.PDF






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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

saes-a-010.pdf

Documents

gas compression

shore gosp

hot oil systems

gas detection

gas conditioning

crude oil stabilization

engineering standard

existing gosp