offshore process reference book rev 4.pdf

Technip USA Offshore Process Reference Book PRINTED COPY IS UNCONTROLLED TPUSA-ENG-PR-PS-

Confidential C2: Do not disclose without authorization of 86 Copyright Technip USA, Inc. Issue Date: July 17, 2008

TABLE OF CONTENTS

1.0 PURPOSE...........................................................................................................................5

2.0 SCOPE................................................................................................................................5

3.0 DEFINITION OF TERMS, ABBREVIATIONS, AND ACRONYMNS ..................................5

3.1 Definitions..............................................................................................................5

3.2 Abbreviations.......................................................................................................12

4.0 RESPONSIBILITIES.........................................................................................................14

5.0 OFFSHORE FACILITIES OVERVIEW .............................................................................14

5.1 Type of Offshore Facility by Function ..................................................................14

5.2 Type of Offshore Facility by Geographical Location............................................14

6.0 TOPSIDES ........................................................................................................................15

6.1 General Data for Design Basis ............................................................................15

6.2 Process Systems Design.....................................................................................22

7.0 TOPSIDES UTILITY SYSTEMS .......................................................................................42

7.1 Closed and Open Drain Systems ........................................................................42

7.2 Chemical Injection ...............................................................................................45

7.3 Fuel Gas System.................................................................................................48

7.4 Diesel System......................................................................................................49

7.5 Hot Oil System.....................................................................................................49

7.6 Cooling Medium System......................................................................................51

7.7 Water Systems ....................................................................................................51

7.8 Utility/Instrument Air ............................................................................................53



7.9 Nitrogen ...............................................................................................................54

7.10 Flare or Vent System...........................................................................................55

8.0 P&ID DEVELOPMENT PHILOSOPHIES .........................................................................56

8.1 PH-01 — Philosophy for Line and Instrument Symbols ......................................57

8.2 PH-02 — Blinding Philosophy for Maintenance of Equipment ............................57

8.3 PH-03 — Philosophy for LO and LC Valves........................................................59

8.4 PH-04 — Philosophy for Equipment Connections to Drain and Vent ..................60

8.5 PH-05 — PSV Connections.................................................................................63

8.6 PH-06 — Philosophy for Lines Insulation ............................................................64

8.7 PH-07 — Philosophy for Failure Position of Control Valves and Line Size Automated Valves ...............................................................................................65

8.8 PH-08 — Philosophy for Control Valve Arrangement for Gas and Liquid Service.............................................................................................................................66

8.9 PH-09 — Philosophy for Control Valve Arrangement in Water and Air Service..67

8.10 PH-10 — Philosophy for Requirement and Type of Sampling Systems..............68

8.11 PH-11 — Philosophy for Providing Handwheels to the Control Valves and Automatic Isolation Valves ..................................................................................69

8.12 PH-12 — Philosophy for Instrumentation across Air Coolers..............................69

8.13 PH-13 — Philosophy for Selecting Type of Valves Used in the Facility ..............70

8.14 PH-14 — Philosophy for Designating Lines as No Pocket, Free Draining, Slope or Gravity Flow ....................................................................................................70

8.15 PH-15 — Philosophy for Piping / Instrument Arrangement on Pump Suction and Discharge Lines...................................................................................................72

8.16 PH-16 — Philosophy for Providing an Actuator on Stand Alone Valves .............73

8.17 PH-17 — Philosophy for Nitrogen Connections to Equipment and Piping ..........74

8.18 PH-18 — Philosophy for Valve Numbering on P&Ids..........................................74



8.19 PH-19 — Philosophy for Showing Instrumentation Details on the P&Ids............75

8.20 PH-20 — Philosophy for Vendor Package Equipment Information .....................75

8.21 PH-21 — Philosophy for Valve Check List ..........................................................76

8.22 PH-22 — Philosophy for Spectacle Blinds / Spacer Blinds Check List................78

8.23 PH-23 — Philosophy for Utility Connections to Piping or Equipment..................79

8.24 PH-24 — Philosophy for Instrumentation on Pig Launchers ...............................79

8.25 PH-25 — Philosophy for Blow Down Valve (BDV) Arrangement ........................80

8.26 PH-26 — Philosophy for Shut Down Valve (SDV) Arrangement.........................81

9.0 PROCESS RELATED TO OFFSHORE FACILITY TYPE ................................................82

9.1 Safety System .....................................................................................................82

9.2 Special Consideration for Design of Topside Facilities for Floating Production Systems...............................................................................................................83

10.0 TOOLS AND SOFTWARE................................................................................................85

11.0 FORMS / ATTACHMENTS...............................................................................................86

12.0 REFERENCES..................................................................................................................86

12.1 Standard and Recommended Practices..............................................................86

13.0 RECORDS ........................................................................................................................86



FIGURES

Figure 1 – Major Components of a Christmas Tree............................................................................6 Figure 2 – Typical Plots of Produced and Solution GOR Vs Reservoir Pressure...............................8 Figure 3 – Types of Offshore Platforms ............................................................................................15 Figure 4 – Typical Schematic of an Offshore Production Facility......................................................22 Figure 5 - Schematic of a Wellhead Desander Installation ...............................................................23 Figure 6 – Typical Three Phase Separator ......................................................................................26 Figure 7 - Electrostatic Desalter Electrode Configuration. ................................................................29 Figure 8 – A Typical Electrostatic Desalter .......................................................................................29 Figure 9 - Schematic of a One Stage Electrostatic Desalting System ..............................................30 Figure 10 - Schematic of a Two Stage Desalting System.................................................................30 Figure 11 – Liquid-Liquid Hydrocyclone Element .............................................................................38 Figure 12 - Solid Liquid Hydrocyclone Elements ..............................................................................38 Figure 13 – A Typical Flotation Unit..................................................................................................39 Figure 14 – A Schematic of a Typical Oil Recovery by Gas Injection. ..............................................40 Figure 15 – Spectacle blinds requirement for isolating pumps. ........................................................58 Figure 16 – Typical representation of compressor isolation with break out flanges..........................59 Figure 17 – Typical Representation of Connection to Closed Drain System ....................................62 Figure 19 - Control valves detailed arrangement:.............................................................................67 Figure 21 – A Typical Pump Representation on P&ID......................................................................73 Figure 22 – A Typical Representation of BDV on P&IDs. .................................................................80

TABLES

Table 1 – Well Data Requirements ...................................................................................................16 Table 2 – Facility Total Production rates...........................................................................................16 Table 3 – Properties of Well Fluid.....................................................................................................16 Table 4 – Wellhead Pressure Data ...................................................................................................17 Table 5 – Wellhead Temperature Data.............................................................................................17 Table 6 – Special Characteristics of Well Fluid.................................................................................17 Table 7 – Composition of Well Fluid .................................................................................................17 Table 8 – Water Analysis Data .........................................................................................................19 Table 9 – Export Oil Quality Data .....................................................................................................20 Table 10 – Export Gas Quality Data .................................................................................................20 Table 11 – Disposed Water Quality Data..........................................................................................20 Table 12 – Injection Water Quality Data ...........................................................................................21 Table 13 – Product Disposition .........................................................................................................21 Table 14 – Pipeline Battery Limit Conditions ....................................................................................21 Table 15 – Quarters Data .................................................................................................................21 Table 16 – Environmental Data ........................................................................................................21 Table 17 - Open Drains Treatment and Disposal .............................................................................44 Table 18 – Typical Injection Water Chemical Injection Rates...........................................................45 Table 19 - Typical Chemical Injection Rates for the Production facility ............................................46 Table 20 – Vent and Drain Size Requirements.................................................................................61



1.0 PURPOSE

The purpose of this book is to give the process engineer an overview of the topsides processes on the offshore production facilities.

2.0 SCOPE

This book covers the general introduction to offshore topside processes and practices. This book also guides the user to various manuals, procedures, codes, standards and recommended literature.

This book is not intended to be used as a guideline for process design of the facilities nor does it replace any of the existing guidelines and procedures. User should use it as reference material. User should contact their process lead or manager for any clarification on the contents and scope of this book.

3.0 DEFINITION OF TERMS, ABBREVIATIONS, AND ACRONYMNS

3.1 Definitions

- Associated Gas: Natural gas which is found in association with crude oil either dissolved in the oil or as a free gas cap.

- Barrels of Oil Equivalent (BOE): A unit of petroleum volume in which the gas portion is expressed in terms of its energy equivalent in barrels of oil.

- Blowout: The uncontrolled flow of gas, oil, or other fluids from a well which occurs when the pressure within the well exceeds the pressure in the borehole applied to it by the column of drilling fluid.

- Closed Drain System: Intended for draining of liquid after depressurization from vessels, piping and other equipment due to maintenance work etc. All pressure drain connections shall be equipped with a blind to avoid accidental draining of pressurized liquids/gas.

- Cell Spar: Similar in principle to other Spars, the cell Spar configuration features a deck supported by a long, buoyant cylindrical tank hull section moored to the seabed. The major difference lies in the design of the cylindrical section: instead of a long, single hard tank, or hard tank and truss section as in the truss spar, the cell spar’s hard body is made up of several smaller, identically sized cylinders wrapped around a center cylinder of the same dimensions.

- Choke Valve: A valve that lifts up and down a solid cylinder (called a "plug" or "stem") which is placed around or inside another cylinder which has holes or slots. The design of a choke valve means fluids flowing through the cage are coming



from all sides and that the streams of flow (through the holes or slots) collide with each other at the center of the cage cylinder, thereby dissipating the energy of the fluid through "flow impingement". The main advantage of choke valves is that they can be designed to be totally linear in their flow rate.

- Christmas Tree: An assembly of control valves, gauges and chokes that control oil and gas flow in a completed well. Christmas trees installed on the ocean floor are referred to as subsea, or “wet,” trees. Christmas trees installed on land or platforms are referred to as “dry” trees.

Figure 1 – Major Components of a Christmas Tree

- Deepwater: Generally defined as operations in water depths of 1,500 feet or greater.

- Design pressure: The maximum internal or external pressure to be used in determining the minimum permissible wall thickness of equipment and piping. Note that the minimum permissible wall thickness may be derived from a lower operating pressure, but higher operating temperature. Relief is usually initiated at design pressure.

- Development Well: A well drilled in a proven field to complete a pattern of production.



- Double Block & Bleed: Two barriers with a bleed between the barriers. Typical arrangement is two block valves with a bleed valve in the middle. A single valve is acceptable as double block and bleed only if the force acting on the seal faces is independent of system pressure, and if a bleed connection is provided between the two seal faces (typically a double expanding gate valve). Further, such a valve must be lockable in closed position to avoid malfunction or mal-operation.

- Downstream: in the context of the oil and gas industry, applies to the refining and marketing sectors of the industry.

- Downhole Gauge: A pressure gauge, typically run on slickline, used to measure and record downhole pressure. Downhole gauges are commonly used in assessing the downhole pressure under various flowing conditions, the basis of pressure transient analysis.

- Dry Hole: A well in which no significant reserves have been found and is therefore incapable of producing commercial quantities of oil or gas.

- Enhanced Oil Recovery (EOR): The use of any process for the displacement of oil from the reservoir other than primary recovery

- Exploratory Well: Well drilled for the purpose of discovering new reserves in unproven areas. They are used to extract geological or geophysical information about an area with a view to exploiting untapped reserves. Exploratory Wells are sometimes known as Wildcat Wells.

- Flare System: Process relief system. Also used to blow down equipment to flare header pressure.

- Float Over: Method to install topsides on top of the platform jacket. The method consists in carrying the topsides on a barge over the jacket piles and ballasting the barge tanks in order to lower the topsides onto the piles guides.

- Flow Lines: Pipework extending from the Christmas Tree to the manifold.

- Flowline Manifold: A pipe fitting with several lateral outlets for connecting flowlines from one or more wells. This connection directs flow to production separators, test separator or other devices.

- FPSO (Floating Production, Storage and Offloading) System: A system contained on a large, tanker-type vessel and moored to the seafloor. An FPSO is designed to process and store production from nearby subsea wells and to periodically offload the stored oil to a smaller shuttle tanker, which transports the oil to onshore facilities for further processing.

- FSO (Floating Storage and Offloading) System: Essentially the same as an FPSO without the production facilities.



- Gas Cap: This defines the upper part of the field reservoir filled with gas.

- Gas Field: A field with GOR greater than 20,000 cubic feet/barrel.

- Gas Lift: The process of raising or lifting fluid from a well by means of gas injected down the well through tubing or tubing casing annulus. Injected gas aerates the fluid to make it exert less pressure than the formation pressure, consequently forcing the fluid out of the wellbore.

- GOR: Gas to Oil ratio are of two types.

o Solution Gas to Oil ratio (GORs) at well saturation conditions.

o Production Gas to Oil ratio (GORp) at surface conditions.

Figure 2 – Typical Plots of Produced and Solution GOR Vs Reservoir Pressure

- Heat Tracing: Use of electrical cables, steam pipes or heating medium for heat conservation or frost protection.

- HP/HT (High Pressure/High Temperature): Refers to deepwater environments producing pressures as great as 15,000 pounds per square inch (psi) and temperatures as high as 350 degrees Fahrenheit (˚F).

- Injection Well: Well used to inject fluids (usually water) into a subsurface formation by pressure.

- Insulation: Use of a material with a low conductivity applied to equipment and piping in order to prevent energy transfer (i.e. heat, noise).

- Isolation: Isolation means a physical barrier (blind) or a tested barrier (block valve).



- Jacket: Offshore steel structure that support the topsides of a fixed platform. The jacket is usually made of 4 or more legs or piles.

- Jumpers: Connections for various subsea equipment, including tie-ins between trees, manifolds or flowline skids.

- Liquids to Gas Ratio (LGR): Ratio of total petroleum liquids (including condensate, and natural gas liquids) to gas (in barrels/million cubic feet) in a gas field.

- Manifold (Sub Sea): A subsea assembly that provides an interface between the production pipeline and flowline and the well. The manifold performs several functions, including collecting produced fluids from individual subsea wells, distributing the electrical and hydraulic systems.

- Maximum Design Temperature: Maximum temperature for the mechanical design of a given piece of equipment. It represents the most severe condition of coincident pressure and temperature.

- Maximum Design Pressure: Maximum pressure for the mechanical design of a given piece of equipment. It represents the most severe condition of coincident pressure and temperature.

- Maximum Operating Condition: Applies to Temperature as well as Pressure, flowrate, etc. There are conditions when the topside operates at conditions corresponding to the high alarm set point.

- Maximum Settle Out Pressure: The maximum settle out pressure is calculated from coincident high pressures trips on both suction and discharge side of the compressor.

- Midstream: Term often used to describe the processing, storage and transportation sectors within the oil and gas industry. Midstream defines the industry processes that occur between the upstream and downstream sectors.

- Minimum Design Temperature: Minimum temperature for the mechanical design of a given piece of equipment. It represents the most severe condition of coincident pressure and temperature.

- Minimum Design Pressure: Minimum pressure (Vacuum) for the mechanical design of a given piece of equipment. It represents the most severe condition of coincident pressure (Vacuum) and temperature.

- Minimum Operating Conditions: Apply to Temperature as well as Pressure, flowrate, etc. There are conditions when the plant operates at conditions corresponding to the low alarm set point.



- Non-associated Gas: Natural gas that is not in contact with significant quantities of crude oil in the reservoir.

- Normal Operating Condition: Apply to Temperature as well as Pressure, flowrate, etc. These are conditions when the plant operates at intended normal steady state condition, subject to normal variation in operating parameters.

- Oil Reservoir / Petroleum Reservoir: System often thought of as being an underground "lake" of oil, but it is actually composed of hydrocarbons contained in porous rock formations.

- Pig or Pipeline Inspection Gauges: Used to perform various operation on the pipeline, including but not limited to cleaning and inspection.

- Pig Receiver: A piping arrangement that allows pigs to be removed from a pipeline without stopping flow.

- Pig Launcher: A piping arrangement that allows pigs to be launched into a pipeline without stopping flow.

- Produced Water: Describes water that is produced along with the oil and gas. Produced water generally originates from water that is trapped in permeable sedimentary rocks within the wellbore. Disposal of produced water can be problematic in environmental terms due to its highly saline nature.

- Remotely Operated Vehicle (ROV): An unmanned vehicle connected to and controlled from a support platform.

- Risers: The physical link between the sea bed and the topside of offshore installations, for production, gas lift or water injection purposes. Risers can be either rigid or flexible and are critical components of these types of installations.

- SALM (Single-Anchor-Legged Mooring) System: A mooring system utilizing a single anchor base and single riser, designed to operate as an unmanned marine terminal.

- Semi-Submersible Rig: A mobile offshore drilling or production unit that floats on the water’s surface above the subsea wellhead and is held in position either by anchors or dynamic positioning. The semi-submersible rig gets its name from pontoons at its base that are empty while being towed to the drilling location and are partially filled with water to steady the rig over the well.

- Settle Out Pressure: The pressure equilibrium reached after a compressor shutdown (pressure trapped between the upstream and downstream isolation points).

- Shut-off pressure: The shut in pressure for centrifugal pumps and compressors is determined by the curves for a “no flow” situation, i.e. blocked outlet.



- Single Block & Bleed: One isolation and a bleed. The point to be isolated can be bled down by the bleeder, but there is only one barrier against the pressure side (e.g. a valve).

- Spar Platform: named for logs used as buoys in shipping and moored in place vertically, Spar production platforms have been developed as an alternative to conventional platforms. A Spar platform consists of a large-diameter, single vertical cylinder supporting a deck.

- SPM (Single-Point Mooring) System: A mooring system that allows a tanker to weathervane around a mooring point.

- Subsea Tree: A “Christmas tree” installed on the ocean floor. Also called a “wet tree.”

- Subsea System: Ranges from single or multiple subsea wells producing to a nearby platform, floating production system or TLP to multiple wells producing through a manifold and pipeline system to a distant production facility.

- Swab Valve: The topmost valve on a Christmas tree that provides vertical access to the wellbore.

- TLP (Tension-Leg Platform): An offshore drilling platform attached to the seafloor with tensioned steel tubes. The buoyancy of the platform applies tension to the tubes.

- Topside: Refers to the oil production facilities above the water, usually on a platform or production vessel, as opposed to subsea production facilities. Also refers to the above-water location of certain subsea system components, such as some control systems.

- Truss Spar Platform: This modified version of the floating production Spar features an open truss in the lower hull, which reduces weight significantly and lowers overall cost.

- Ultra-Deepwater: Usually refers to operations in water depths of 5,000 feet or greater.

- Umbilicals: Connections between topside equipment and subsea equipment. The number and type of umbilicals vary according to field requirements, and umbilicals may carry the service lines, hydraulic tubes and electric cables and/or fiber-optic lines.

- Underground Injection (also known as Deep well Injection): Process by which disposal of waste byproducts of the oil and gas industry are injected or pumped into deep underground reservoirs through a wellbore.



- Upstream: Term which describes the exploration and production sectors within the oil and gas industry.

- Vent System: System for venting of hydrocarbon gas to an atmospheric vent at a safe location. Used during maintenance before equipment is opened and normally done after blowdown of equipment to flare system.

- Wells:

o Development Well: A well drilled to a known producing formation in a previously discovered field.

o Exploratory Well: Any well drilled for the purpose of securing geological or geophysical information to be used in the exploration or development of oil, gas, geothermal, or other mineral resources, except coal and uranium, and includes what is commonly referred to in the industry as "slim hole tests," "core hole test," or "seismic holes".

o Wildcat Well: A well drilled for the purpose of discovering a new field or reservoir.

- Wellbore: The physical hole that makes up the well, and can be cased, open or a combination of both.

- Wellhead: The surface termination of a wellbore that incorporates facilities for installing casing hangers during the well construction phase. The wellhead also incorporates a means of hanging the production tubing and installing the Christmas tree and surface flow-control facilities in preparation for the production phase of the well.

- Well Killing Fluid: To stop a well from flowing or having the ability to flow into the wellbore. Kill procedures typically involve circulating reservoir fluids out of the wellbore or pumping higher density mud into the wellbore, or both.

- Wing Valve: A valve located on the side of a Christmas tree or temporary surface flow equipment, such as may be used for a drillstem test. Two wing valves are generally fitted to a Christmas tree. A flowing wing valve is used to control and isolate production, and the kill wing valve fitted on the opposite side of the Christmas tree is available for treatment or well-control purposes. The term wing valve typically is used when referring to the flowing wing.

- Winterization: Use of insulation and heat tracing, or insulation only, for frost protection.

3.2 Abbreviations

- AG Associated Gas

- BBL Barrel



- BDV Blow Down Valve

- CSO/CSC Car Seal Open/Car seal Closed

- DHSV Down hole Safety Valve

- ESDV Emergency ShutDown Valve

- FB Full Bore

- FPSO Floating Production, Storage and Offloading

- FPU Floating Production Unit

- FSO Floating, Storage and Offloading

- GBS Gravity Based structure

- HIPPS High Integrity Pressure Protection System

- HP High Pressure

- LO/LC Locked Open/Locked Closed

- LCC Life Cycle Cost

- LO Locked Open

- LP Low Pressure

- NAG Non Associated Gas

- NC Normally Closed

- NO Normally Opened

- MMSCFD Million Standard Cubic Feet per Day

- NPSH Net Positive Suction Head

- PSV Pressure Safety Valve

- RB Reduce Bore

- RO Restriction Orifice

- SDV Shut Down Valve

- SSV Surface Safety Valve (also called upper master valve)

- SSSV Sub Surface Safety Valve (also called lower master valve)

- TSO Tight Shut Off

- WHSIP Well Head Shut-In Pressure

- WHSIT Well Head Shut-In Temperature



4.0 RESPONSIBILITIES

Not Applicable

5.0 OFFSHORE FACILITIES OVERVIEW

5.1 Type of Offshore Facility by Function

Main function (From reservoir to Export)

- Drilling

- Process/Production

- Utilities

- Living Quarter

- Storage

Examples

- Wellhead platform (Drilling by a mobile rig)

- Drilling platform (drilling & work over a permanent rig)

- Production platform

- Integrated platform

- Miscellaneous (flare, manifold, transfer)

5.2 Type of Offshore Facility by Geographical Location

The adequate type of offshore facilities is defined based on offshore location:

- Country/State

- Area/Field

- Water Depth

- Related Structures in Areas

- Field sea bed architecture

Different types of offshore facilities can then be installed:

- Fixed platforms

- Floating production systems

- Subsea systems

5.2.1 Fixed Platforms



- Jacket or jack-up structure (sea water max. 200m deep)

- Compliant tower platform (sea water max. 400m deep)

The technique of topsides installation on top of the platform structure highly depends on the topsides weight. Two main topsides types can be distinguished based on installation technique:

o lifted modules (each module shall be of max. 2500 to 5000 tons weight)

o Unideck type (max acceptable weight ranges from 10000 to 20000 tons approx.)

5.2.2 Floating production systems

- Semi-submersible platforms

- TLP

- FPSO, FPU, FSI (turret and spread mooring)

Figure 3 – Types of Offshore Platforms

5.2.3 Subsea systems

The subsea system may comprise of following facilities:

- Subsea production

- Subsea wellheads

- Subsea multiphase pumping

6.0 TOPSIDES

6.1 General Data for Design Basis

This section lists the general data required to design offshore topsides facilities. This will help the process engineer gather the proper data required and understand the client’s needs. Note that the data required also depends on the nature and phase of the project.



It provides a non exhaustive checklist of data to collect before starting the design and is not intended to replace the project execution plan/ Design Basis.

6.1.1 Feed Characteristics

6.1.1.1 Maximum Individual Well Rate

Table 1 – Well Data Requirements

Oil bopd Water bwpd Gas MMSCFD Gas Oil Ratio (GOR) (1) scf/bbl Condensate bpd Water to Oil Ratio (WOR) (2) Water salinity (3) Total BS&W ppm (or mg/l)

(1) Dry gas: GOR is infinite Wet gas: GOR > 2000 Sm3/m3 Gas with condensate: 500 <GOR< 2000 Sm3/m3 Light oil: 300<GOR<500 Sm3/m3 Medium or heavy oil: GOR < 300 Sm3/m3

(2) From 0 to 99% (3) From 50 g/l to over 300 g/l (seawater = approx 35 g/l)

Note: Complete production data (total production profile and individual well production

profiles) for the fields should be obtained from client.

6.1.1.2 Facilities Production Rate

Table 2 – Facility Total Production rates

Design

Flow Rate Turndown Flow Rate

Maximum Operating Flow Rate

Oil bopd Water bwpd Gas MMSCFD Condensate bpd

6.1.1.3 Specific Gravities or Density Of Well Fluids

Table 3 – Properties of Well Fluid

Oil (2) Water=1 / APIo (1) Water Water=1 / lb/ft3 Gas Air=1 / lb/ft3 Condensate (2) Water=1/ APIo

APIo = 141.5/density – 131.5 with density = SG of oil @15C / SG of water @15C



Condensate: 40<API<80 Light Oil: 30<API<40 Medium Oil: 20<API<30 Heavy Oil: API<20

6.1.1.4 Pressure at Wellhead

Table 4 – Wellhead Pressure Data

Flowing Psig Shut-In psig

6.1.1.5 Temperature at Wellhead

Table 5 – Wellhead Temperature Data

Flowing oF Shut-In oF

6.1.1.6 Special Characteristics

Table 6 – Special Characteristics of Well Fluid

H2S Mole Percent or g/100scf CO2 Mole Percent Paraffins (waxes), asphaltens Mercaptans Mercury Slugging bbl Sand ppm (weight) Salt ppm (weight) Foaming Emulsifying Tendencies Pour Point oF Chemicals

6.1.1.7 Wellhead Analysis (Mole Percent, Dry Basis) (Note that the composition list needs to be adjusted for the specific composition given.)

Table 7 – Composition of Well Fluid

Component (Mole % / Vol% / Mass%) Well Fluid Crude Oil at Stock

Tank condition Gas

Nitrogen Carbon Dioxide Methane Ethane Propane Isobutane



Component (Mole % / Vol% / Mass%) Well Fluid Crude Oil at Stock

Tank condition Gas

n-Butane Isopentane n-Pentane Hexane Heptane Octane Nonane Decane C11 C12 C13 C14 C15 C16 C17 C18 C19 C20+ Total

Crude Oil Characteristics:

Crude oil TBP data and viscosity curves should be obtained from client.



6.1.1.8 Water Analysis Data

Table 8 – Water Analysis Data

COMPONENT mg/l me/l Cations

Sodium, Na

Potassium, K

Calcium, Ca

Magnesium, Mg

Barium, Ba

Iron, Fe (Total)

Anions

Chloride, Cl

Bicarbonate, HCO3

Carbonate, CO3

Sulfate, SO4

Bromide, Br

Iodide, I

Sulphide, S

Other Properties

Total Dissolved solids, ppm

pH value

Specific Gravity 60/600F

Resistivity (Ohm-Meter) @ 75 F

Stability Index @ 1000F

Stability Index @ 2000F % Deviation in Meq. Balance

% Deviation in TDS



6.1.2 Product specifications at export

6.1.2.1 Oil Export

Table 9 – Export Oil Quality Data

Contractual Oil production rate Quality Oil: - Basic Sediment & Water (BS&W) (1) % - Vapor Pressure or RVP (Reid Vapor Pressure) (2) psia Salt content (3) pptb

(1) 0.1 to 0.5% typical range. (2) 8 to 10 psi typical range. (3) Around 20 pptb (60 mg/l) typical figures.

6.1.2.2 Gas Export

Table 10 – Export Gas Quality Data

Contractual Gas production rate Quality Gas: - Water Content lb H2O/MMSCF Gas - Water Dew Point (1) oF - Hydrocarbon Dew Point (2) oF Wobbe index (3) MJ/Sm3 H2S content (4)

Nitrogen content

CO2 content

Methanol content

Other contaminants content

(1) -10C @70 barg typical figure (2) -2C typical figure (3) 50 MJ/Sm3 typical figure (4) 1 to 4 ppm wt typical figure

6.1.3 Water disposal

Table 11 – Disposed Water Quality Data

HC Content (1) ppmv

(1) 15-40 ppmv typical range.



6.1.4 Water Injection

Table 12 – Injection Water Quality Data

Quality Water: - Filtration (Oil + Solids) (1) Micron - O2 content (2) ppb

(1) 2-10 micron typical range (2) 5-20 ppb typical range

6.1.5 Product Disposition Method

Table 13 – Product Disposition

Tanker Loading Pipeline Offloading Storage

6.1.6 Pipeline

Table 14 – Pipeline Battery Limit Conditions

Pressure/Temperature Operating Conditions (1) Psig/oF Code / Pipeline Spec. (1) Diameter (ID) (1) in Pressure/Temperature Design Conditions (1) Psig/oF Termination Point or Battery limit location (1)

(1) Provide information for each pipeline entering or exiting the facility.

6.1.7 Quarters

Table 15 – Quarters Data

Number of Men Men Special Features

6.1.8 Environmental Data

Table 16 – Environmental Data

Air Temperature (Summer/Winter/Wet&Dry Bulb) oF Wind Direction Sea Water Temperature (Max/Min/Design) @: - Surface oF - Bottom oF

Water depth ft



6.1.9 Utilities

For a revamp jobs the availability of various utilities should be established very early in the project. The battery limit conditions for each utility such as minimum & maximum operating pressure, minimum & maximum operating temperature, design pressure, design temperature and piping specification used for the concerned system should be well defined.

For the grass root projects the utility requirements should be established based on the overall process scheme.

6.2 Process Systems Design

Figure 4 – Typical Schematic of an Offshore Production Facility

6.2.1 Wellheads

6.2.1.1 Wellhead Design

Wellhead design is normally carried out by third party contractor. The scope boundary limits should be well defined for the topsides facility at start of the project. Usually the topside design scope should start from downstream of choke valves for individual flowlines. The scope break should be clearly shown on the concerned P&IDs. Anything upstream of choke valve including choke valves will fall in the well head contractor’s scope. Generally the wellhead control panel design is the responsibility of the same contractor and shall be clearly mentioned on concerned P&IDs in notes section.



6.2.1.2 Desanding

Production of sand from oil & gas wells is a common difficulty for processing facilities and is often caused by unconsolidated reservoirs, high production rates or the failure of gravel packs and other sand control measures.

To prevent abrasion, sand should be removed.

This can be done either upstream the production choke (Wellhead desanders) or downstream the production choke (Well stream desanders) or even within the 1st separator as long as upstream piping is designed considering erosion due to sand.

Figure 5 - Schematic of a Wellhead Desander Installation

Operating Principle

A complete solid handling system can be easily derived utilizing a five step methodology.

1) Separate: The solids must first be removed from the well or process fluid stream. This can be accomplished using Multiphase/Standard desanding hydrocyclones, vessel drainage, or settled tank bottoms.



2) Collect: To facilitate simple system design, all collected or removed solids must be gathered into one central location. Collection can be as simple as a desander accumulator vessel or a dedicated sump tank.

3) Clean: In many cases the sand may require cleaning for oil or chemical removal prior to further handling.

4) Dewater: The total volume of sand slurry to be disposed can be greatly reduced by a dewatering step.

5) Haulage: Haulage is a simple term used to define removal, hauling and disposal of the solids. The design of the haulage system will be dependent upon the disposal requirements (i.e. disposal well, overboard, etc.).

Average Performance Requirement

Sand separation systems can usually remove up to 100% of solids from a liquid phase or multiphase stream at any location in the processing facility.

Containment and collection systems can be designed to collect solids from desanders, filters, sand jet systems and tank bottoms.

Sand cleaning systems can be designed to treat up to 1000 kg/d solids to a level below 1% by weight oil on sand.

Dewatering systems can reduce the slurry volume by up to 90%.

Complete process facilities can be designed to treat up to 60,000 BPD sand slurry (10% by weight).

Desander is to be designed by Supplier specialist with help of process input and according to performance requirement. The requirement of having an online continuous desanding system should be established for the project.

6.2.2 Well Clean-Up

During completion or work-over of an oil well, it is necessary to clean out the well bore before it can be used to carry oil or gas up to the well head. For example, after drilling, perforating, or cementing operations, a large amount of particulate matter removed from the sides of the well bore during such operations, remains in the well bore, and it is desirable to remove such particulate matter from inside the well bore prior to production.

6.2.2.1 Well Clean-Up Method

A typical method of removing particulate matter from a well bore is to circulate a liquid, referred to as a completion fluid, through the well bore to carry the particulate matter to the surface. A completion fluid commonly comprises of an aqueous saline solution, such as sea water or man-made brine. The drag force acting on particulate matter suspended



in a well bore increases with the square of the particle size, and an increased drag force increases the sweeping efficiency of the completion fluid, i.e., the ability of the completion fluid to remove particles from the well.

A polymeric flocculant is mixed with the contaminants in the well bore to form a floc containing the contaminants. The floc can then be flushed from the well bore to effectively remove the contaminants.

A dedicated flowline and discharge (burner pit) system is usually installed for flushing purpose. Design of Well clean-up system is made on a case by case basis in line with Client requirement. This system is generally in the scope of drilling contractor.

6.2.3 Well Production Gathering Systems

6.2.3.1 Flowlines

The maximum individual well production rate can be used for the flowline sizing if there is no basis established for the design. The flowlines should be sized based on maximum permissible velocity criteria as per API RP 14E ref. [2] for the flowline sizing. Take into account the presence of sand while determining the erosional velocity. Although the peak flowrate should be used to determine the size of the flowline, however, the production profile of the individual wells should be carefully evaluated to check the peak flowrate versus the time period for which it occurs. The sizing basis may be optimized if the peak flow occurs for a relatively short period of time based on the erosion and corrosion rates calculated for the flowlines. The reduction in thickness of the flowlines over the years should be calculated due to erosion and corrosion. The flowline sizing basis should be agreed with the client for such cases.

The design pressure of the flowlines downstream of choke valve should be determined based on the shut in tubing pressure (SITP). If the design pressure is chosen less than the SITP then pressure safety valves are generally provided to protect the flowlines in case of blocked outlet. Normally the design pressure for the flowlines is kept at or above the SITP to avoid having pressure safety valves. The decision to choose one design over the other should be made based on economic evaluation.

6.2.3.2 Production Header

The production header should be sized based on the total production profiles from all the wells provided by the client. API RP 14E ref. [2] should be followed for calculating the maximum velocity allowable in the header.

6.2.3.3 Test Header

The test header should be sized based on the maximum individual well production rates provided by the client. API RP 14E ref. [2] should be followed for calculating the maximum velocity allowable in the header.



6.2.3.4 Vent/Drain Header

Vent and drain headers are generally provided to vent and drain the well fluid blocked in the test & production header and flow lines.

6.2.4 Inlet Cooling/Heating

The separation temperatures will determine the separation efficiency and heating or cooling requirement upstream of the separator. It should be noted that the maximum production temperature downstream of the choke valve should be well established during the start of the project. In case of subsea flowlines, the arrival temperature at the platform should be established in consultation with the flow assurance group.

6.2.5 Test Separator

The requirement of test separator should be confirmed by the client. Sometimes multiphase flow meter could be more economical than the test separator. It may be noted that the test separator is sometimes used for various other functions such as a standby production separator etc therefore the basis for providing and sizing the test separator should be discussed with the client.

The test separator shall be sized as per Technip Data book, ref. [9].

6.2.6 Inlet Separation

The number of the separation stages is defined in order to get the maximum oil recuperation while satisfying the oil export quality specification.

The pressure on the separation different stages is also chosen such as to get the maximum oil recuperation while satisfying the oil export quality specification.

Figure 6 – Typical Three Phase Separator

The separators may be 2 or 3 phases. Residence requirement may vary between 3 to 10 minutes depending on the oil disposal (pumping, etc).



Other vessel sizing criteria are same as Onshore design, refer to Technip Databook, ref. [9].

The design of two phase separator is performed by Technip Process engineer.

For the design of internals, it is recommended to get the information from the vendors for specialized internals.

The three phase separators are generally designed by supplier’s process specialists and validated by Technip Process department.

Surge Volume for Liquids

If the vessel is sized to receive a liquid slug during normal operation, that liquid shall be handled between normal operating liquid level (NLL) and High operating liquid level (HLL).

Slug Catcher

In the case of a slug catcher, if the slug is due to planned pigging operations, the normal liquid level can be lowered down to the LLL and slug is handled between the LAL and the LAH at up to 70-80% of the vessel diameter with reduced gas flowrate. However the basis of design for the slug catcher should be established at onset of the project.

6.2.6.1 Stabilization

The most common method of removing dissolved volatile hydrocarbons is by phase separation in series of flash drums. The operating pressure of the first separator is fixed by reservoir conditions and fluid flow characteristics in inlet gathering manifolds and flow lines. The pressure of the final stage is fixed by pipeline transport. The number of stages is optimized to get maximum production of crude oil.

Stabilization column can be used instead of different separators used in multi stage separation. Depending upon the proposed scheme stabilizer can replace all the separators downstream of primary separator.

- Some advantages of stabilizer column are:

- Increase the crude oil production rate at constant RVP and increase the API gravity of the crude oil.

- Reduces the gas hydrocarbon dew point

- Can operate at higher pressure with good quality crude oil thus lowering the compression energy requirements.

- Allows the crude oil specification of 50 – 60 ppmw of H2S content

- Some disadvantages of stabilizer column are:



- Height of the column may impose construction logistic cost increase.

- Source of heat at high temperature for reboiling.

- The relatively dirty service limits the type of trays which can be used.

- Accumulation of salts and other solids in distillation column. Desalter is required upstream of the column.

- Production water slugs may disturb the column operation.

- Cannot handle varying gas to oil ratio.

6.2.6.2 Desalting

Crude oil contains salt dissolved in the entrained water droplets. Salts, mainly metal salts including metal halides such as magnesium chloride, sodium chloride, and calcium chloride, and other metals salts, are among impurities which can pollute crude oil. Those salts contribute to corrosion, plugging, and to decrease heat transfer efficiency by fouling heat exchangers.

The desalting process works by washing the crude with clean water and then removing the water to leave dry, low salt crude oil. Separation of water from oil is a physical process governed by Stoke's Law.

The two most typical methods of crude-oil desalting are chemical and electrostatic separations, using water as the extraction agent.

In chemical desalting, water and chemical surfactant (demulsifiers) is added to heated crude. Heated crude or heated crude & water help impurities dissolving into water or attaching to water. The emulsion is held in a tank where they settle out by Stoke’s Law.

Electrical desalting is the application of high-voltage electrostatic charges to concentrate suspended water globules in the bottom of the settling tank to enhance coalescence.

Surfactants are added only when the crude has a large amount of suspended solids.



Figure 7 - Electrostatic Desalter Electrode Configuration.

Figure 8 – A Typical Electrostatic Desalter



Figure 9 - Schematic of a One Stage Electrostatic Desalting System

Usually the feedstock crude oil is heated to between 150° F and 350°F to reduce viscosity and surface tension to ease mixing and then separation with the water. The temperature is limited by the vapor pressure of the crude-oil feedstock. In both methods other chemicals may be added. Ammonia is often used to reduce corrosion. Caustic or acid may be added to adjust the pH of the water wash. Wastewater and contaminants are discharged from the bottom of the settling tank to the wastewater treatment facility. The desalted crude is skimmed at the top of the tank.

Different crude oils can display markedly different behaviors in a desalter, depending on their composition and physical properties. For a given crude type and vessel size, factors affecting desalter efficiency include mixing efficiency, inlet header design and location, electrostatic field type and intensity, and electrode design & configuration.

Figure 10 - Schematic of a Two Stage Desalting System

Generally about 90% or more of the salt content can be reduced in a one-stage desalting process as described above. Overall desalting efficiency can be increased by

(ALTERNATE) DISCHARGE

DEHYDRATOR DESALTER

FRESH WATER /SEA WATER

1ST STAGE WATER

DISCHARGE

RECYCLE PUMP

(Desalted Crude)



introducing a multi-stage process (with recycle) (See figure 10) and a few more percent of salt content in crude oil can be removed. However, it was observed in many different fields that crude oil recovered in a two-stage desalting process, still cause corrosion to downstream equipment. Such corrosion is believed to be caused by hard-to-extract salts originally present in crude oil. Corrosion to downstream equipment adds manufacturing costs to final products. There is therefore an ever-increasing need to develop a process to further remove the hard-to-extract salts. Because of the large volume of refined products, a seemingly small improvement can translate into a huge savings to consumers.

Desalting units Suppliers (e.g. Natco) have developed different technologies to enhance desalting procedure.

In offshore operations, fresh water supply is critical. Thus, fresh water might be mixed with seawater.

Technip Process defines desalting system and run salt balance to prepare specification for Supplier. Detailed design is performed by Supplier.

Acceptable salt content is usually about 10 pptb (pounds per thousand barrels of oil).

6.2.6.3 Oil Production

Oil storage

- FPSO

- FSO

- GBS (Gravity Based structure)

Oil export

- Pipeline

- Buoy

- Tandem offloading

6.2.6.4 Emulsion Treating

Emulsion is the combination of two immiscible liquids in which fine drop of one liquid is dispersed in another liquid.

Emulsion formation prevents water from settling out in the separators. With severe emulsion oil-water separation and level controls is difficult leading to carryover of water in the crude oil and carry through of crude oil in water.



A demulsifier neutralizes the emulsifying agent. Demulsifier chemicals must be added continuously at the rate determined by bottle test and by field trials. They are usually between 10 – 60 ppm by vol.

6.2.7 Gas Processing

6.2.7.1 CO2 & H2S Removal: Gas Sweetening Process

Technologies used for recycled hydrogen sweetening in the oil refining field are the same as the ones developed since 1930 for natural gas sweetening, which themselves followed the ones used for sweetening coal gas since the middle of the 19th Century.

There is a lot of gas sweetening technologies, from the older one, the now obsolete iron sponge process to the more recent, the membrane process, which encounters a real success. Some of these technologies are listed below:

• Membrane technologies.

• Technologies based on adsorption on solids :

o physical adsorption (on molecular sieves or on activated carbon) ;

o chemical adsorption :

with formation of metal sulfides (on iron sponge or on zinc oxide),

with formation of sulfur (on impregnated activated carbon).

• Technologies based on direct conversion into sulfur through Claus reaction :

o on a solid catalyst bed (like the Selectox process) ;

o in liquid phase (like the Clauspol process).

• Technologies based on direct oxidation into sulfur in liquid phase (like the Giammarco-Vertrocoke process, or the Stretford process, or the various iron-based redox systems).

• Technologies based on reversible absorption in a liquid medium, which deliver a concentrated hydrogen sulfide stream, to be transformed into sulfur in a Claus-based sulfur recovery unit :

o physical absorption only (like the Rectisol process or the Selexol process) ;

o chemical absorption mainly (like the hot potassium carbonate technologies, or the amine technologies) ;

o physical and chemical absorption (like the Sulfinol process).



The implemented technology depends upon the composition, pressure and flowrate of the acid gas to be treated and also upon the configuration of the plant where it is generated. But, the main technology remains the reversible absorption by amines.

It is recommended to refer to GPSA Volume II for further information.

6.2.7.2 Water Removal: Dehydration

Dehydration is the process used to remove water from the natural gas and natural gas liquids (NGL). Dehydration is required to:

• Prevent formation of hydrates and condensation of free water in processing and transportation facilities,

• Meet a water content specification in the product,

• Prevent corrosion.

Techniques for dehydrating natural gas, associated gas condensate and NGLs include:

• Absorption using liquid desiccants,

• Adsorption using solid desiccants,

• Dehydration by refrigeration,

• Dehydration by membranes,

• Dehydration by gas stripping,

• Dehydration by distillation,

• Dehydration with CaCl2

Glycol dehydration with diethylene glycol (DEG) or triethylene glycol (TEG) is the most widely used method of removing water from natural gas. The process works on the basis of glycol’s high affinity for water.

Glycol contactor and glycol regeneration system are usually treated as a package and designed by Supplier specialist.

It is recommended to refer to GPSA Volume II for further information.

6.2.8 Gas compression

The gas compression systems generally collect the gas from the different stages of separation, cool it, remove condensed liquids and compress the gas to a pressure suitable for export and or re-injection.



The system is generally designed to be capable of handling the variations in capacity and gas compositions resulting from operations over the life of the field at the required delivery pressure. Rewheeling of compressors may be required to achieve variation in production profile. If installation of new equipment is required later in field life, tie-in points and space may be provided, and utility and support system requirements can be designed for handling future needs. The design of facilities to cover future requirements should be in agreement with the client. Some margin with respect to flow, temperature and mol. weight are generally included.

If dry gas seals are used, the hydrocarbon seal gas is generally dehydrated, dewpoint controlled or superheated to prevent condensation or hydrate formation. For start-up purpose, use of nitrogen can be evaluated as a mean to avoid liquid drop out.

Compressor driver selection study is generally performed to determine the type of driver suitable for the service. e.g electric motor driven Vs gas turbine driven, fixed speed or variable speed motors etc.

API 617 specifies that the margin between the greatest power required by the compressor and the rating of a steam turbine or electric motor should be at least 10%.

The power margin for the gas turbine must be sufficient to cover the following contingencies:

A 2% tolerance on compressor power during testing compared with the guaranteed value.

An average compressor deterioration and power reduction of 3% is generally appropriate for a 'normal' compressor.

Gas turbine performance deterioration. The power reduction is estimated to be 7% for an aero derivative type gas turbine, between the new condition and the point where the turbine is withdrawn for overhaul.

A minimum margin of 12% (=2+3+7) for aero derivative gas turbines is generally required between compressor rated power and the gas turbine site rating to allow for normal service deterioration. This should be established for the project in agreement with the client.

6.2.9 Produced Water Treatment

Produced water is the aqueous liquid phase that is co-produced from a producing well along with the oil and/or gas phases during normal production operations. Usually, the fluids that are removed from the reservoir by the producing well are brought to the surface and separated into an oil stream, a gas stream and a water stream. The main components of the water stream that is separated are:



- Water

- Suspended oil

- Dissolved oil

- Suspended solids (scale, corrosion products, sand, etc.)

- Dissolved solids

- Dissolved Gases (CO2, H2S, O2)

- Bacteriological matter

- Added materials (treating chemicals, kill fluids, acids, etc.)

Once the decision is made to inject produced water into a subsurface formation for either disposal purposes or for enhanced oil recovery purposes, it then becomes necessary to give consideration to the produced water treating requirements apart from normal treatment required for water disposal to sea. Injection water treatment is necessary due to the potential negative impacts that produced water may have on the formation. In general, produced water will have five main categories of “contaminants” from a produced water injection point of view:

Suspended Solids

Suspended solids in produced water may originate from formation fines, scale deposits, corrosion products or bacterial activity. Depending on such factors as size, shape and concentration, particulate matter in the injection water may have a tendency to cause plugging in the formation. In turn, the plugging will result in higher injection pressures and, possibly, lower injection flow rates.

Suspended Oil

The oil in the injection water may cause damage to the formation by sealing off the pore throat and pore filling. The oily water injections can cause significant amount of injectivity reduction. Hence, the oil content of the injection fluid must be reduced to a suitable level for use. Secondly, the oil that is recovered from the produced water is routed to the oil sales meter to generate cash for the operation.

Scales that form when dissolved solids precipitate

As the concentration of dissolved solids increases, the potential for the dissolved solids to precipitate and form scales deposits in the surface piping and equipment or in the formation also increases. Various types of analyses can be performed to determine the scaling tendency of the injection water. If there is a high scaling tendency, then consideration should be given to injecting scale inhibitor chemicals.



Bacteriological Matter

Microbial growth in oil field water systems may be either bacterial or fungal in nature. These micro- organisms are of concern because as they multiply they can cause or enhance corrosion of pipes and vessels, plugging of injection wells, and degradation of chemicals used in enhanced recovery operations.

Corrosive dissolved gases (CO2, H2S, O2)

Produced water from sour formations may contain some amount of dissolved H2S

and/or CO2. These gases form corrosive acids when dissolved in water. The effects of these gases can be mitigated by removing the gas from solution or by use of corrosion inhibitor chemical additives.

Oxygen scavenger may also be required to control the oxygen content in the produced water.

Therefore, the objective of the produced water treating system is to remove or reduce these contaminants to a level that makes the produced water suitable for use. Furthermore, the system should be designed to optimize the capital and operating life-cycle costs.

Produced water for injection may also require treatment for the following:

- Reverse demulsifier to resolve oil-in-water emulsions

- Chemical filtration aids (polyelectrolyte, coagulant) for filtration performance

- Surfactant chemical to assist in backwash of granular media

In view of the importance that chemical treatment has in production operations, the following are a few of the important critical factors for achieving proper and effective chemical dosing:

1) Proper analysis of the chemical and physical properties of a representative water sample as the basis for treatment

2) Proper assessment of any incompatibilities or interactions between the injected chemical and other species in the produced water (including compatibility with other chemicals in use, mixing water compatibility analysis and scale prediction techniques)

3) Proper location of chemical injection points

4) Proper chemical concentration

5) Proper hydration or mixing of chemical, if required



6) Consideration of variations in flow (system surges) to minimize the occurrence of over- treating or under-treating of chemical

6.2.9.1 Gravity Settlers

Large and relatively dense particles will be easiest to remove. The separation of relatively large, high-density solids can be accomplished by simply allowing enough time for the solids to settle by gravity to the bottom of a tank or vessel. This is termed gravitational settling. This is the most simple and least costly solution to solids removal. Gravitational settling can be accomplished by using settling tanks or skimmer tanks. These types of tanks are commonly installed at land-based operational facilities due to the fact that space and weight constraints are not very stringent and the installed cost is relatively low.

The speed of solids removal via gravitational settling can be greatly enhanced by use of inclined parallel plates. A section of closely spaced, inclined parallel plates can be placed in a rectangular tank or in a cylindrical vessel through which a produced water stream containing suspended solids flows. Equipment designed on this principle is termed a parallel plate interceptor (PPI) or a corrugated plate interceptor (CPI). The plate pack accomplishes two things: 1) it shortens the distance that a solid particle must travel before it reaches a settling surface; and 2) it provides plenty of surface area for solids to settle out of the water stream. Hence, not only is the settling process faster but the equipment required is smaller and lighter. However, the capital cost of the equipment may be more than a simple skim tank.

6.2.9.2 Hydrocyclones

Hydrocyclone technology can be used to separate suspended oil from produced water. Hydrocyclones work by converting pressure energy to centrifugal motion in order to multiply the gravitational force field. Multiplication of the gravitational force increases the settling rate of the oil droplets and therefore results in smaller, lighter equipment. In addition, the separation process itself is more efficient, in terms of the smallest droplet that can be removed.



Figure 11 – Liquid-Liquid Hydrocyclone Element

Figure 12 - Solid Liquid Hydrocyclone Elements

6.2.9.3 Degassing and Flotation

Flotation technology is also used as a polishing step for removing residual amounts of small oil droplets and oil-coated solids from produced water. Flotation, as the name implies, is a technique whereby the contaminants in the produced water are made to “float” to the surface much faster. This is accomplished by introducing natural gas bubbles (or air bubbles) into the produced water stream. These bubbles then attach themselves to either oil droplets or oil-coated solids and “float” these contaminants to the surface for removal. Chemicals having a high charge density are used to promote the



attachment of gas bubbles to the oil and solids contaminant substances. Many land-based flotation devices incorporate cylindrical vessels divided into four active cells, or compartments and one collection cell. The produced water flows sequentially from cell to cell. Gas is injected into each active cell so that an incremental amount of oil and oil-coated solids are removed in each cell. Finally, the clean treated water enters the final chamber for collection and disposal.

Figure 13 – A Typical Flotation Unit

6.2.10 Water Injection

Water injection is expected to improve the oil recovery factor as an alternative to gas injection.

Water can be taken from produced water as well as treated sea water.

Injected water quality specification shall be a basis to design this system.

Injection water will have following typical specification:

- Suspended solids, oil droplets and particles < 25 micron nominal

- Oxygen (O2) < 5 ppb.

6.2.11 Gas Injection / lift

Gas injection is used for reservoir maintenance or as secondary recovery method to supplement the pressure in an oil reservoir or field. In most cases, a field will incorporate a planned distribution of gas-injection wells to maintain reservoir pressure and effect an efficient sweep of recoverable liquids.



Gas Lift recovery process utilizes the buoyancy of high-pressure to physically lift oil from the depths of the well. Gas is injected into the annulus between the casing and the tubing.

The gas travels down the annulus until it reaches the packer which acts as a seal between the oil producing formation, the casing and the tubing to prevent gas from entering the producing zone. The packer forces the gas through the gas lift valve into a column of oil. The high pressure gas rises up through the tubing in solution with the oil towards the surface.

Gas lift requires a head of pressure in excess of the bottom hole well pressure and therefore is an application ideally served by barrel compressors.

Gas Injection

There comes a point in the life-cycle of any oil reserve when primary recovery can no longer be undertaken due to natural gas depletion. Extra compression is required to force the oil to the surface in a process known as secondary recovery. Gas injection is one such form of secondary (or tertiary) recovery. Two or more wells are employed where at least one is required for the sole purpose of injecting gas into the reservoir.

Denser oil from the depths of the reservoir is displaced towards the bores of the producing wells. The process can occur thousands of feet underground and therefore requires the tremendous head of pressure that a barrel compressor can generate.

Figure 14 – A Schematic of a Typical Oil Recovery by Gas Injection.



6.2.12 Flowlines/ Gas/Oil Export Pipelines/Pipeline risers/Pig receiving or launching Facilities

Particular attention must be paid to transient phase such as start-up and shutdown as well as water-hammer, etc. when dealing with import or export, gas or oil pipelines.

Dynamic simulations are commonly run for these transient phases by the flow assurance group. Process engineer should co-ordinate the required information with the flow assurance group to establish the basis of design for the topside facilities.

6.2.12.1 Pigging

Pigging refers to the practice of using pipeline inspection gauges or 'pigs' to perform various operations on a pipeline. These operations include but are not limited to cleaning and inspection of the pipeline.

This is accomplished by inserting the pig into a 'pig launcher' - a funnel shaped Y section in the pipeline. The launcher is then closed and the pressure of the product in the pipeline is used to push it along down the pipe until it reaches the receiving trap - the 'pig receiver'.

Generally Ball valves are used in pipelines because the diameter of the ball can be same as that of the pipe causing the smooth transition of pig through the valve.

Pigging can be done both ways of the pipeline. Thus corresponding pig trap must be designed for both launching and receiving.

6.2.12.1.1 Intelligent Pigging

Some pigging systems are highly sophisticated sets of equipment that consist of a standard 5-6 finned pig with an intelligent transmitter that has a global positioning system fixed on it to tell the exact location of the pig inside the pipeline while it is on the move. Along with the GPS positioner there are a host of other instruments like the internal camera that takes live video of the pipe condition inside while the pig is moving, the thickness gauge that constantly measures the thickness.This data is compiled and used for post pigging analysis about the condition of the pipeline from inside.

6.2.12.1.2 Choice of Pig

Pigs are used for cleaning, dewatering, gauging, isolating etc. and more than 350 different types are available. The use of the correct pig with the correct procedures can make a very significant contribution to long term asset value.

For example, for optimum performance the bristles on a brush pig must be the correct stiffness for the pipeline. If they are too stiff they will take on a permanent deformation in



bends and will not touch the wall in straight pipe. If they are not stiff enough they will not displace debris from the pipe wall.

Dewatering pipelines can be expensive and time consuming. Inappropriate pigs and procedures can leave water in the line which has to be removed by drying. Swabbing lines that are already dry can cause pigs to wear out and become lodged.

Dynamic simulations of pigging operation might be run (if required by Client) to help designing topside receiving facilities. These simulations are done by flow assurance group.

6.2.12.1.3 Pig Launcher/Receiver Sizing

Depending on pig type and pigging operation, pig size may be completely different from one project to another one. This guideline is generally available from client.

7.0 TOPSIDES UTILITY SYSTEMS

7.1 Closed and Open Drain Systems

The networks collecting closed drains and open drains shall be independent.

7.1.1 Closed Drain System

7.1.1.1 System Pressure

Some companies require that the drain pipe down to the connection on the closed drain should be designed for the same pressure as the systems to be drained whichever is the highest. In that case, there could be one header and one connection to closed drain drum per pressure rating. This should be studied in detail for multiple drain system.

7.1.1.2 System Temperature

The simultaneous occurrence of the lowest temperature and the highest pressure can be considered for design for drains which are not positively isolated (i.e. no spectacle blind).

7.1.1.3 Closed Drain Drum

Closed drains shall discharge in a flash drum called closed drain drum. The closed drain drum is generally sized to accommodate the total volume of fluid contained in the largest vessel of the facility.

The drum shall be connected to LP vent or flare. Closed drain drum design pressure should be chosen in compliance with API STD 521, ref. [4].

After collection, closed drain liquids should then be pumped back to the process or export pipeline if possible.



7.1.2 Open Drain System

7.1.2.1 Open Drain System Discharge Cases

Open drains shall be split in Hazardous and Non Hazardous drains, which should be independent networks.

Open drains mainly collects: Rain water, Fire fighting, wash down water and effluents.

1) Rainwater

If not exceeded by rainfalls figure (given by project environmental study data) a minimum rainwater rate of 0.05 l/s.m2 can be considered in consultation with the client and civil & structural group.

Surface to consider is: total surface of highest deck + lower deck surfaces reached by a rain of 450 angle.

2) Fire fighting water

Fire fighting water rate is calculated by Safety department.

Only one fire zone should be considered discharging at one time.

3) Washdown Water

A minimum rate of 2000 ft3/h (50m3/h) should be considered (water wash hose capacity + contingencies).

4) Effluents

Effluents rate is to be evaluated on a case by case basis.

7.1.2.2 Open Drain Headers

Piping diameter size

Minimum recommended header diameter is 3”.

Minimum Velocity Criteria

A minimum of 2.5 ft/s or even 4 ft/s (for places where heavy amount of sand or other solids may be present) is generally required to flow through open drain system at least 6 times per year to allow self cleansing of the system.

Maximum Velocity Criteria

To avoid erosion, velocity of 5ft/s maximum should be considered.

Slope

Headers shall slope continuously and do not have any pockets.



For new offshore installations, slope should be 1% minimum for pipes 3” and above.

Connection of branches or sub-headers to headers shall be 450 or 600 in the direction of the stream to avoid turbulence.

Maintenance

Rodding points should be installed at each header or sub-header end to allow cleaning of the line.

Venting

Seal pots shall collect drain for each hazardous area drain sub-header to allow any gases dissolved to vent.

Recommendations

• Open drain horizontal headers are generally designed such as not to get filled with liquid more than 75% of pipe diameter.

• Horizontal sub-headers shall connect to vertical main headers.

• Restrictions shall be generally avoided.

7.1.2.3 Open Drains Treatment and Disposal

Table 17 - Open Drains Treatment and Disposal

Hazardous Non Hazardous Non hazardous Oil contaminated Oil contaminated Clean water Treatment Open drain drum or tank

(Note 1) (Note 2) No

Disposal Disposal tube or caisson Disposal tube or caisson

Direct to Sea

Note 1: Depending upon client’s preference. Note 2: Some local regulations may ask for treatment before disposal.

Open Drain Drum or Tank

The open drain drum is generally atmospheric vessel designed as gravity settler water-oil separator to treat the oily water and is generally sized based on the washdown case. Firefighting and rain water may be directly diverted to sea if agreed by client.



Any oil captured in drum or tank shall be pumped back to the closed drain drum. A minimum 3 ft dip pipe permanently submerged in liquid in the closed drain drum shall be installed to operate as a seal between the two systems.

Disposal Tube or Caisson

The disposal tube or caisson shall be open to atmosphere on the top and open to sea on the bottom.

Any oil skimmed in the caisson shall be pumped back to the open drain drum or tank or to the closed drain drum if the open drain drum does not exist.

7.2 Chemical Injection

Chemical injection package is designed in consultation with production chemist in flow assurance group with help of process input. Some typical chemicals used and the injection rates have been provided in section 7.2.1. These figures should only be used for preliminary calculations and proposal purposes. The exact chemical injection requirements and the dosage rates for each chemical is project specific and should be calculated by specialist. The dosage rates should be provided by client based on field tests.

7.2.1 Typical Chemical Injection Rates

Table 18 – Typical Injection Water Chemical Injection Rates

Chemical

Typical Dosage (ppmv)

Typical Locations Injection Points

Calcium Nitrate (Souring Mitigation) To WI:57 To PW: 163

- Injection points are generally provided upstream of the deaerators and upstream of the produced water pumps

Oxygen Scavenger (Water Injection) 5-10 - Deaerator system recycle loop Scale Inhibitor 30 - Suction of each water injection pump Antifoam 1-2 - Inlet of deaerator Biocide 500 - Inlet of deaerator

- Exit of deaerator - Batch dosed for 6 hours per week

(period treatment) Corrosion Inhibitor 30 - Suction of each water injection pump



Table 19 - Typical Chemical Injection Rates for the Production facility

Chemical Typical Dosage

(ppmv) Typical Locations Injection Points

Solubility Portion

Anti-foam 3-5 - Production manifold - Inlet production separator - Inlet test separator

Oil

Demulsifier 20 - Production manifold - Inlet production separator - Inlet test separator

Oil

Scale Inhibitor Wellhead: 20 Waterlines: 30

- Individual wellheads; and - Water outlet from production

separator

Oil

Reverse Demulsifier 10-20 - Water outlet from production separator; and

- Water outlet of test separator

Produced Water

Corrosion Inhibitor (Oil) 30 - Suction of crude oil booster pump

Oil

Corrosion Inhibitor (Gas) 1 litre / MMSCF - Gas export line Gas Corrosion Inhibitor (Produced Water)

30 - Suction of produced water pump

Produced Water

Biocide 500 - Inlet of produced water degasser

Water

Methanol Flowing 50 litre / MMSCF

- Flowing gas export line; and - Individual production

wellheads

Oil / Gas

Oxygen Scavenger (Utility)

150 ppmv Seawater

7.2.2 Hydrates Inhibitor

Natural gas hydrates are solids that form from a combination of water and one or more hydrocarbon or non-hydrocarbon gases. In physical appearance, gas hydrates resemble packed snow or ice.

To prevent hydrates formation, following three methods can be used:

1) Adjusting temperature and pressure to get out of hydrate formation zone.

2) Dehydrating the gas stream to prevent a free water phase.

3) Inhibiting hydrate formation in free water phase.

In order to effectively deal with the hydrate formation problem the first step is to determine the potential for hydrate formation of the different systems composing the



topside facilities and second step is to evaluate, whenever needed, the hydrate inhibitor requirements.

First Step: Hydrate Formation Study

Study is performed at different operation modes, i.e.: Normal operation, Start-up, Shutdown, Intermittent, Blowdown.

The process streams across the entire process system are investigated to identify any point at which hydrate formation may occur.

The pressure let down across a valve is simulated using upstream conditions corresponding to the system operating pressure/temperature and downstream pressure varying from atmospheric to operating pressure. This is repeated for upstream conditions corresponding to the system operating pressure at minimum ambient temperature. The temperature-pressure data generated from the simulation is plotted to analyze each scenario. The difference between the operating temperature and hydrate formation temperature is then used as a basis for estimating hydrate inhibition requirements.

Generally a safety margin of 3°C is allowed for the calculation of the temperature difference between the operating (for each operation mode) temperature and the Hydrate Formation Temperature (HFT) to assess the potential for hydrate formation and to calculate the necessary hydrate inhibitor concentration.

The 3°C margin is however only applied to operating temperatures that may vary (estimated or calculated) or where bulk fluid temperature might be significantly different from fluid wall temperature. Well known temperatures (for example the minimum ambient air temperature) are used without margin.

It should be noted that usually the calculated HFT is higher than the actual HFT. Calculated HFT is the Hydrate Formation Temperature given by process software (HYSIS). It does not correspond to the true temperature of hydrate formation but to the temperature at which hydrates melt (dissociation temperature). The actual temperature at which hydrates form is lower. Therefore, the actual HFT is lower than the calculated HFT.

Second Step: Hydrate Inhibitor Injection

Whenever a potential for hydrate formation is identified, one mitigation measure is chemical inhibitor injection (usually methanol or glycol) at appropriate locations.

Calculations are performed following the GPSA guideline, ref [8].



When inhibitor is injected, the minimum concentration in the free water phase is calculated using the Hammerschmidt equation. The loss of inhibitor in vapor phase and oil phase is also estimated using the method described in GPSA, ref [8].

Hammerschmidt Equation

For a given inhibitor concentration in the free water phase, the equation calculates the resulting temperature depression for hydrate formation. The equation was found to be valid for methanol concentrations less than 0.2-0.25 mol% and glycol concentration less than 0.6-0.7 mol%.

d = KH x I / (100-I)/ MWI Where: KH = 2335 for Methanol, 2335 to 4000 for glycol (EG, DEG or TEG) d = hydrate temperature I = Weight percent inhibitor in the liquid phase MWI = Molecular weight of the inhibitor

The location and the type of the injection points are defined according to the operation phases and type of equipment to be protected.

7.3 Fuel Gas System

Fuel gas system should be designed based on the specific requirements of the project and the proposed process scheme.

Generally as a minimum the low pressure fuel gas is required for flare header purging, flare pilot and flare purge. No specific treatment is required except for the removal of liquid droplets from the gas by means of a vapor liquid separator.

A high pressure fuel gas system is required if the process scheme includes facilities like gas turbine for power generation or as a driver for compressors. Gas turbine vendor should be contacted early in the project to get the fuel gas requirements in terms of fuel gas quality / specification, minimum / maximum supply pressure & temperature at the gas turbine battery limits and the required maximum flowrate.

A typical fuel gas specification has been provided below:

- Fuel gas filter separator shall remove 99% of 1 micron and larger solid contaminants and entrained liquid droplets.

- Liquid carryover of free liquid in the exit gas from the filter separator shall be less than 0.01 gal/mmscf.

- Normally fuel gas is required to be supplied at 50oF above the dew point of the gas for gas turbines.



7.4 Diesel System

The diesel system is generally designed to provide the diesel fuel to the following systems:

1) Pedestal crane

2) Fire water pumps

3) Essential generator

4) Emergency Capsule

The diesel fuel system generally consists of diesel fuel storage most likely in crane pedestal otherwise in storage tank. The total diesel storage requirements shall be calculated based on client’s requirements. Generally it is calculated based on 15 days of continuous crane operation, 24 hours a day at 50% of the maximum crane load.

The Diesel Transfer Skid generally have 2x100% diesel unloading filters, 2x100% diesel fuel filters and 2X100% diesel transfer pumps (one operating and one standby). Pump flow rate should be based on 2 hours time to fill biggest day tank or 50 GPM. The diesel filters generally allow removal of 99% of solid particles 5 microns and above. A centrifuge may be employed to remove water from the diesel depending upon the quality of diesel required by the users.

Pedestal crane day tank shall be sized for 24 hours autonomy, fire water pump day tank shall be sized for 8 hours autonomy, and the Essential Generator day tank shall be sized for 8 hours autonomy.

Diesel may also be required for other users such as dual fired gas turbines etc.

7.5 Hot Oil System

The heating medium system provides required heat load to process and utility equipment. Heat energy is transferred by heating medium, circulating in a closed loop. The heat is usually supplied by means of waste heat recovery from turbines.

Where heat is required before start up of turbines, a start up heater is required.

The heating medium is normally water/glycol (TEG) or hot-oil depending on temperatures required. The danger connected with use of flammable heat medium should be evaluated.

The maximum operating pressure for the system shall cater for pressure surges and temperature variations in the system (start-up/shutdown and normal operation).

Some design requirements which are generally considered in hot oil system design are:

o If waste heat recovery unit is employed then a bypass to the waste heat



recovery tube bundle is generally provided for bypassing the exhaust gas. This is important to avoid boiling or decomposition of heating medium within the heating coil. The exhaust bypass can be used as heating medium temperature control.

o For waste heat recovery units, the minimum operating temperature for the exhaust gas is generally 120 °C, as stainless steel subjected to saline atmosphere, suffers from pitting corrosion at temperatures below this.

o Minimum flow through heating coils in standby units is generally considered for waste heat recovery units.

o Pumps and motor are generally sized for maximum viscosity of heating medium, i.e. cold state. To ensure NPSH it can be assumed that water based heating medium is at boiling point in the expansion tank.

o As a minimum a filter is generally provided and sized to take a slip stream to clean the heating medium. For heating medium system with printed circuit heat exchangers (PCHE), vendor is consulted regarding filtration grade.

o Fired or electric heaters may be required as start up heater or for permanent heating, where enough waste heat is not available.

o The heating medium expansion tank is generally blanketed with inert gas with spill off to flare. The back pressure during flaring can be considered when selecting design pressure. The tank as a minimum is sized to cater for the volumetric expansion of the heating medium within the 25% and 75% liquid range (for temperatures between minimum ambient and maximum operating).

o The heating medium circulation pumps generally stop on low level in heating medium expansion tank, provided the exhaust has been bypassed around the waste heat recovery unit.

o Waste heat recovery/standby heater units are protected against overpressure in case the units are blocked in. Tube rupture in waste heat exchanger piping, resulting in heating medium leaking into exhaust/burner stack, can be considered and accounted for in design.

o Tube rupture in consumer heat exchangers is generally considered during design.

o The use of flanges and connections are generally limited, as the high temperature tends to create leaks due to expansion/contraction. Avoid insulation of flanges in systems using hot oil as heating medium.

o The selected heating medium shall have a flame point above the highest operating temperature if parts of the system are located in non classified areas. Leakage combined with an ignition source can result in fire if the flame point of the heating medium is lower than the maximum operating temperature.

o Heating medium is generally drained to separate tanks for reuse after draining of equipment. Filling and drain lines to be permanently installed.



7.6 Cooling Medium System

The cooling medium system is provided to remove heat from process and utility systems where direct seawater cooling and air cooling is not applicable.

To avoid freezing in a liquid filled cooling medium system, the following two options are possible:

o The cooling medium shall have a freezing point equal to or below the minimum ambient temperature.

o Cooling medium with freezing point above minimum ambient conditions may only be selected when accepted by company. An evaluation of consequences (operating and maintenance of a large number of heat trace circuits, filling and drainage requirements, use of corrosion inhibitor and other chemicals in the cooling circuit) can be performed.

Following design considerations are generally made for the system design.

o Cooling medium is generally maintained at a higher pressure than the seawater in the cooling medium cooler to:

o prevent seawater (chloride) migration into the cooling medium.

o ensure that the cooling medium does not boil during low flow or turndown conditions, that is, keep the coolant pressure high enough so that it would not boil even if stagnant. The cooling medium vapour pressure at maximum normal hot side temperature in the exchanger, is generally used.

o The expansion tank shall have capacity to control volume expansion from temperature variation (between minimum ambient and maximum operating) within the 25% and 75% liquid level range. Hydrocarbon monitoring shall be installed enabling detection of leakage.

o Fill-up line can be permanently installed. System can be gravity drained to tank or boat.

o Expansion tank is generally nitrogen blanketed.

o Injection of corrosion inhibitor/PH stabiliser upstream of pumps is generally provided.

o Emergency or essential power is made available for one pump. 7.7 Water Systems

7.7.1 Sea Water

Sea water is mostly used for water injection and/or utility water, potable water making and fire water ring main back-up pressurization. The system is designed to lift and filter seawater for distribution to the various platform users.

Some general design considerations for seawater system:



o System capacity is calculated as design load of continuous consumers plus peak load from intermittent consumer (if relevant). Design seawater supply temperature to be evaluated against running spare pump(s) during summer periods.

o Pumps to be selected to keep discharge pipe design pressure low and minimise variations in system pressure. Fixed speed pumps shall have minimum flow recirculation line.

o If the sea water pump has a high non-filled riser (at not running condition), the riser is generally equipped with vent valve to avoid vacuum when the pump is stopped.

o A coarse filter is generally located downstream the pumps to avoid larger particles to enter the system (typical filtration requirement 2 mm or less). The filters can be equipped with an automatic backwash facility.

o In the cases where seawater is routed direct from sea chest to the pump, a strainer may be located upstream of the pump to prevent large particles to enter and damage the pumps.

o Generally injection points for chlorine to prevent marine growth in the pipe work. The chlorine injection shall be stopped when the pump is stopped. The maximum residual chlorine content is 0.5 ppm.

o The chlorination system shall generate or receive, store and inject hypochlorite into systems containing seawater.

o Feed to the hypochlorite generator is generally from downstream of the seawater filters. The system operates continuously and produces hypochlorite at a stable rate at the required concentration.

o To reduce the concentration of hypochlorite discharge to sea, it is possible to install a combined hypochlorite-copper ion system. Copper ion in combination with hypochlorite is more efficient than hypochlorite alone. The overall pollution to sea will normally be reduced with such a system.

o The electrolysis cells in the chlorination system generally operate at a pressure set by the supplier which will lie between the seawater lift pump discharge pressure and atmospheric pressure.

o The seawater flowrate to the electrolysis cells shall be at a sufficient rate to remove the generated heat at an adequate rate. Operation of the cells shall be such that solids deposition on the electrodes does not occur.

o The electrolysis cells transformer / rectifier generally have the facility to adjust the current in order to adjust the hypochlorite concentration.

o The hypochlorite head tank shall be sized for a residence time of 20 minutes at maximum volumetric hypochlorite production. The hypochlorite head tank shall operate at near atmospheric pressure.

o The air blower for hypochlorite generation system generally has a minimum capacity of 100 times the volumetric rate of hydrogen production.



o Provision for sampling from the electrolysis cell inlet and outlet lines shall be installed.

o The operation of the blower is interlocked to the cells such that loss of the blower will shut down the power supply to the cells. Upon a shutdown the blower generally continues to operate for a period to ensure a hydrogen free system.

7.7.2 Utility water

Fresh water maker technology mostly used offshore is the reverse osmosis or the progressive distillation (under vacuum).

The system generally produces and/or receives, store and distribute fresh water to all users on the facility.

Potable water is generated by UV sterilization of fresh water and by hypochlorite dosing and UV sterilization of imported fresh water. Provision should also be made for hypochlorite dosing into generated fresh water upstream of the potable water tanks.

Separate storage tanks are generally provided for potable and service fresh water, and each shall be equipped with dedicated pumps and a dedicated distribution system.

The system is designed to eliminate the risk of contamination. Facilities can be provided at each user to prevent backflow to the distribution system.

Typical fresh water quality:

Electrical conductivity (max) 75 mS/m at 25oC

pH 6.5 - 9.0

7.8 Utility/Instrument Air

The compressed air system shall provide compressed air at a defined quality and pressure to instrument air consumers and to plant air consumers.

A compressed air system may include facilities to provide:

o instrument air.

o plant air.

o topping air.

o black start air. Instrument air is the motive force for all pneumatic controllers and valve actuators and is used for purging of electrical motors and panels.

Plant air is used for air hoists/winches, air motors, sand blasting, spray painting, air tools, motor purging and transport of dry substance (e.g. cement, barite).

Blackstart air compressor typically charge the start air vessel/bottles for the emergency generators and fire water pumps.



Topping up compressor typically maintains the pressure in the start air vessels/bottles during normal operation.

The instrument air system generally consist of two 100% capacity heatless type air dryers with automatic regeneration. Instrument air dryer units are generally standard packages equipped with coalescent pre-filters and, air after-filters.

The air is cooled as much as possible before water knock out to minimize requirement for dehydration. In design it is generally assumed that the air is at 100% humidity at maximum ambient temperature. Air is generally dried to a dew point corresponding to -40 oF at max operating pressure. Specific requirement of client and project should be considered while specifying the instrument air dryers.

Instrument air receivers are generally sized for at least 15 minutes of air autonomy at full consumption rate.

The instrument air quality is generally less than 2 ppmw of oil and less than 1 micron of particle size carryover. Client specific requirements and project basis should be followed if available.

7.9 Nitrogen

Nitrogen is generally required as a blanketing gas or for use as a buffer gas in the compressor seals and for startup / maintenance purposes. The purity & quality of the N2 should be confirmed from the compressor vendor. Vendor should also provide the maximum and minimum pressure and temperature of N2 supply at the compressor battery limits along with the maximum consumption rates.

Liquid nitrogen storage with vaporizer or membrane type nitrogen generation units can be used as per requirement and preference of the client.

Nitrogen receiver is generally designed for at least 30 minutes of hold up of compressor buffer gas requirement. Any specific client needs and specification should be followed for the criteria.

The nitrogen typical specifications are provided below:

Water dew point -40 oF

Maximum size of solid particles < 1 micron

Nitrogen purity: 97% minimum by volume

Nitrogen unit may contain dedicated air compressors if the unit size is large. Otherwise for small units instrument air can be used for membrane units to generate nitrogen.



7.10 Flare or Vent System

7.10.1 Relief cases

Refer to API RP520/ STD 521 (ref. [3]-[4]).

7.10.2 Emergency Depressurization (EDP)

Installation of an Emergency depressurization system is mandatory for a normally manned platform. On normally unmanned platform, installation of an EDP may be discussed. EDP is considered for piping and equipment both isolated and exposed to fire provided the operating pressure and hydrocarbon inventory is sufficient to justify it.

Refer to API STD 521 (ref. [4]), for details regarding depressuring time and final pressure criteria. The depressuring time, operating pressure limits and inventory criteria for providing EDP should be established with client.

Sequencing and staging of blowdown of the facilities to reduce the flare loads should be done in compliance with the owner’s operating and safety philosophies.

7.10.3 Flare or Vent Knock Out (K.O.) Drum

Refer to API STD 521 (ref. [4]) for sizing flare or vent K.O. drum.

In the absence of more stringent requirements imposed by local authorities, the size of liquid droplets outgoing the K.O. drum generally is as follows:

Vertical stack 150 micron Tilted stack > 45o 150 micron Tilted stack <= 45o 400 micron Remote stack 600 micron

7.10.4 Riser and Tip

Size, features and type is generally decided by Supplier according to Process specifications.

The preliminary sizing of riser diameter can be calculated following the piping sizing rules for Flare or Vent systems. This should be confirmed by the flare package supplier.

The preliminary height is determined from the radiation calculation (By FLARESIM) and defined in order to meet radiation limits (as per API STD 521) at exposed topsides platform point. This should be confirmed by the flare package supplier.

Purge gas

Estimated purge gas rate can be calculated. Refer to API STD 521 (ref. [4]). The final purge gas requirements will be determined by the flare package supplier.



Flash back or internal ignition shall only be precluded by avoiding air ingress in the flare system. The primary protection method against flashback is the use of continuous purge gas flow.

Refer to API STD 521 (ref. [4]) for purge gas rate determination.

Many Oil companies policy is to have smokeless flares. This should be discussed with client while preparing the process design basis.

Distances to impacted area, restricted area and units shall be determined around flares, and cold vents considering the effects they can generate under the following circumstances:

- Maximum continuous flaring: Includes all accepted modes of sustained flaring as defined in the Operating Philosophy.

- Emergency flaring: Is here defined as the modes for flaring occurring in case of a process upset, blocked outlet, emergency depressurization, or failure of equipment.

7.10.5 Radiations

Tip supplier should perform radiation calculations. Technip process engineer should validate the flare tip supplier’s radiation calculations with the software FLARESIM.

Flaresim software can be used to calculate the radiations emitted by a flare or an accidentally ignited cold vent.

The methodology to define the radiation level shall comply with the following principles:

- All radiation limit criteria inclusive of sun radiation.

- Allowable radiation levels as per API STD 521 or client’s specific requirements.

For a given flare boom height, radiation levels are calculated at different exposed points on the topsides.

An optimum flare boom length/ height is determined.

Special care must be taken in the determination of the emissivity value to be used in FLARESIM.

7.10.6 Gas Dispersion

Gas dispersion calculations are performed by environmental specialist.

8.0 P&ID DEVELOPMENT PHILOSOPHIES

This section of the reference guide describes the philosophies to be used for development of Piping and Instrumentation Diagrams for the offshore projects. The



scope of the P&ID philosophy is to define the level of details that shall be shown on the Piping and Instrumentation Diagrams (P&ID).

This philosophy is general in nature and all effort is made to describe exceptions. However, there may be some exceptions in vendor interface and due to specific operational requirements.

Process engineer should use these philosophies as a reference for P&ID development. The project specific requirements and the client’s specifications should ultimately be the criteria for developing P&IDs. The valve types selected for particular use shall be in accordance with the project piping specifications. These philosophies provide the typical representation of the system components on the P&IDs. Based on these philosophies every project should prepare a P&ID philosophy to be followed for the particular project. Any conflict between this document and the project specific P&ID philosophy should be clarified with the project process lead or the offshore process manager.

8.1 PH-01 — Philosophy for Line and Instrument Symbols

I. Objective

The purpose of this philosophy is to define the symbols and nomenclature to be used on the P&IDs.

II. Philosophy

For general line, equipment and valve symbols, abbreviations, instrument identification and location, insulation code, and logic symbols, process engineers should refer to the legend sheet developed for the specific project as per client’s standards.

8.2 PH-02 — Blinding Philosophy for Maintenance of Equipment

I. Objective

The purpose of this philosophy is to define the requirement of permanent blinds around equipment for the purpose of maintenance.

II. Hardware

i) Spacer blinds / Ring spacers

ii) Spectacle blinds

iii) Blind flanges

III. Sizes

i) All sizes, no size or pipe spec limitations.



ii) Up to and including 8’’ size, spectacle blind is generally provided.

iii) Beyond 8” size, ring spacer can be provided.

iv) All blinds are generally rated blinds.

v) Note is generally added to provide warehouse blind with spacers.

IV. Philosophy

General

i) All equipment in hydrocarbon service are generally provided with blinds for maintenance.

ii) Equipment in non hydrocarbon systems may not be provided with blinds.

iii) When blinds are required for a piece of equipment, they are generally provided in all lines to the equipment regardless of size of line.

Vessels

PH 02a Vessels are generally provided with blinds on all the nozzles except for the service noted below:

Blinds are not required on instrument nozzles, spare nozzles, drain nozzles, vent nozzles, purge nozzles, PSV nozzles and standpipes.

Pumps

PH 02b Hydrocarbon pumps can be provided with spectacle blinds on all the connections without exception as shown below in the sketch.

Figure 15 – Spectacle blinds requirement for isolating pumps.

Note 1

Note 1: Vessel isolation to be as per PH 02a



Exchangers

PH 02c Blinds are generally provided on the Tube side nozzles of the exchangers. Spacers may be provided for nozzle sizes greater than 8”.

Compressors

PH 02d Compressor suction should not be blinded, as the inlet strainer are normally dropped during maintenance.

PH 02e Maintenance break-out flanges (BF) can be provided in suction and discharge lines of the compressors as shown in the sketch below.

Figure 16 – Typical representation of compressor isolation with break out flanges.

Note 1

Note 1: Break-out flanges Note 2: Removable Strainer

Compressors

8.3 PH-03 — Philosophy for LO and LC Valves

I. Objective

The purpose of this philosophy is to define the requirement for LO (Locked Open) or LC (Locked Closed) isolation valves. These valves will be under administrative control of the owner.

II. Sizes

All sizes

III. Philosophy



LO VALVES

General

PH 03a All valves at the inlet and outlet of PSV’s or at the outlet of Vacuum Relief Valves.

PH 03b Downstream isolation valves of all pump minimum flow control valve (no isolation provided upstream).

PH 03c Bypasses of the check and block valves and other valves required for continuous cool down of rotating machines. These valves are generally trimmed and locked open in position.

PH 03d Block valves on the fire water distribution header and local foam distribution systems.

LC VALVES

General

PH 03f Bypass valves of PSV’s.

PH 03g First isolation valve on the closed drain line.

8.4 PH-04 — Philosophy for Equipment Connections to Drain and Vent

I. Objective

This philosophy defines the connections and routing for the equipments which are drained by hard pipe connection.

II. Types of Equipment

i) Vessels

ii) Exchangers

iii) Pumps

iv) Compressors

III. Drain and Vent Philosophy

The drain and vent philosophy for these types of equipment can be as follows:



Vessel

PH04a For maintenance and test purposes, all pressure vessels are generally provided with vent and drain provisions discharging to the atmosphere.

PH04b Non operating vents are located on top of the vessel with blinded valve, while drains are installed on the low point of the bottom outlet piping or the bottom of the vessel.

PH04c Drain and vent sizing criteria:

The drain nozzles of the vessel are generally connected:

• To the outlet line at low point for vertical vessel and directly on the vessel for horizontal vessels.

• For horizontal vessels having a length greater than 20 ft, additional drain connections are required with a maximum distance of 10 ft between each drain connection.

• For vessels equipped with internals (baffle), a drain connection is required on each compartment.

• Overflow connections: For vessels equipped with overflow connections, the overflow nozzle and line size is generally one size greater than the inlet/outlet nozzle (whichever is greater).

• Vent and drain connections for vessels are sized as follows:

Table 20 – Vent and Drain Size Requirements

Minimum Minimum

Volume or diameter of vessel Vent diameter Drain diameter

(m3 or mm)

V ≤ 15 or D ≤ 2500 2" 2"

15 < V ≤ 75 or 2500 < D ≤ 4500 2" 3"

75 < V ≤ 220 or 4500 < D ≤ 6000 3" 4"

220 < V ≤ 420 or D > 6000 4" 4"

V > 420 6" 4"

PH04d Utility connections (2” minimum) are sized as follows:

• Drums and heat exchangers (when applicable): 2" • For large vertical drums, two 2” connections are provided for

diameter > 15 ft



• For horizontal vessel with a length > 20 ft and operating in toxic service, two 2” connections are provided.

PH04e Pressure vessels handling flammable and highly corrosive fluids can be provided with additional vent and drain valves enabling depressurization and disposal of contained fluid. Vents shall go to the flare system and liquid shall go to closed drain system.

PH04f For connection to closed drain, consider double valve or as an alternative, consider second isolation valve for common equipment: one block valve near the equipment and one block valve near the closed drain header. A check valve is installed between the two block valves with spectacle blind upstream the last block valve. Refer to the sketch below:

Figure 17 – Typical Representation of Connection to Closed Drain System

PH 04g Drain and vent connections on pumps casing are generally plugged.

PH 04h Compressors shall be provided with vent and drain as per Vendor standard.

PH 04i 6” Clean out nozzles are generally provided on the test separator and the production separator. Number of nozzles may vary depending on the size of the separator.

PH 04j 3” sand jetting manifold is generally provided in test separator and production separator that may see sand during operation.



8.5 PH-05 — PSV Connections

I. Objective

The purpose of this philosophy is to define the arrangement of valves in inlet / outlet and bypass of PSV’s.

II. Sizes

All sizes, no size or pipe spec limitations.

III. Philosophy

PSVs shall be identified on P&IDs with the case for which the PSV has been sized, tag number, orifice designation, inlet and outlet size set pressure rating of flange if different from piping class.

PSV valve arrangement is generally as follows:

PH05a Upstream and downstream isolation valves should be provided on both inlets and outlets of PSVs. (except for air).

PH05b Isolation valves that need to be open, shall be locked open (LO). The P&IDs shall be marked LO for locked open and LC for locked closed valves. In general all the downstream valves shall be locked open (LO).

PH05c All isolation valves for relief valves shall be full bore type and shall be equipped with locking devices. When gate valves are used, they should be installed with stems oriented horizontally or if this is not feasible then the stem should be oriented downward to a maximum of 45 deg to the horizontal.

PH05d A bleed valve should be provided upstream and downstream between isolation valves and the PSV.

PH05e When there is no bypass, both the upstream and downstream valves are in LO position. When there is a bypass, the upstream valve in the bypass is in LC position.

PH05f Free drain symbols should be shown before upstream valve and after downstream valves.

PH05g 2” Bypass line should be provided to the PSV’s. Bypass line is generally not be provided for PSV’s sized for liquid thermal relief.



Figure 18 - A typical PSV arrangement.

8.6 PH-06 — Philosophy for Lines Insulation

I. Objective

The purpose of this philosophy is to define the requirement of line and equipment insulation.

II. Sizes

All sizes, no pipe specification limitation.

All equipment, no size or service limitation.

III. Philosophy

The services for which insulation is generally used on projects are:

i) Heat Conservation

ii) Personnel Protection

iii) Electric heat tracing

iv) Freeze protection

v) Cold conservation

vi) Anti-condensation and anti-sweat

vii) Acoustical

Insulation are generally used in the following cases:

PSV

LO

LO

LO

LC

PSV



PH 06a All piping, valves and equipment operating in services where heat loss to the surroundings is to be minimized must be insulated for heat conservation.

PH 06b PSV outlet lines discharging to the relief header or atmosphere are generally not provided with any insulation.

PH 06c The outlet piping of all PSVs that discharge back to the system, such as thermal relief valves, can be insulated if applicable. Pipe insulation is generally installed at a minimum distance of 6” from the PSV outlet flange up to the connection point of the line.

PH 06d Blowdown line, if required can be insulated starting at the equipment or line up to the first isolation valve. The line downstream the isolation valve may not be insulated.

PH 06e Personnel protection is generally provided for lines and equipment operating above 140 oF and accessible to the operating personnel.

PH 06f Cellular glass insulation may be used for all the purposes. Please refer to the project specific requirements and design basis.

8.7 PH-07 — Philosophy for Failure Position of Control Valves and Line Size Automated Valves

I. Objective

The purpose of this philosophy is to define the failure position (FO/FC/FL) of control valves and automated valves.

II. Sizes

All sizes, no pipe specification limitations.

III. Philosophy

The required failure position of each control valve or automated valve shall be carefully reviewed to ensure the safety of personnel and the facilities in the event of failure of the air or hydraulic supply to the actuator.

General

PH 07a As a general rule, all the control valves and automated valves by default are fail closed type (FC) except for the cases listed below, which are generally fail open (FO):

a) Pump minimum flow bypass.



b) Compressor anti-surge line.

c) System depressurization valves as applicable.

PH 07b Some critical valves may be considered for fail last (FL) position. These valves are identified in detailed engineering.

8.8 PH-08 — Philosophy for Control Valve Arrangement for Gas and Liquid Service

I. Objective

The purpose of this philosophy is to define the requirement of upstream and downstream isolation and bypass valve arrangement for control valve stations provided for gas, crude oil and condensate service.

II. Types of valves

It covers all types of control valve stations in gas, crude oil and condensate service.

III. Philosophy

General

PH 08a Isolation/bypass valves are generally not provided for control valves installed on spare equipment. Equipment isolation can be used for servicing these valves.

PH 08b Bypass may not be provided on spared control valves, only isolation valves can be provided.

PH 08c If control valve is installed on non spared equipment, single isolation valves can be provided upstream and downstream of control valves irrespective of the rating of the control valve.

PH 08d Double bypass valves (one ball valve and other globe valve) is generally provided for control valves with operating differential pressure greater than 150 psi.

PH 08e The size for isolation valves will be the same as the inlet or outlet line size to/from control valve.

PH 08f Ball valves are generally used as isolation valves for line size up to 12”. Above 12” butterfly valves can be used. Please refer to project piping specification.



PH 08g Bypass line for compressor surge control valves is generally not provided. Moreover isolation valves is also not required for these control valves.

PH 08h Size of bypass valves can be same as control valve size.

PH 08i Globe valves shall be used as bypass valves.

Figure 19 - Control valves detailed arrangement:

Control valve details arrangement may be shown as per sketch below:

Note 1: Number of bypass valves to be determined based on PH 08d.

Note 2: Type of valves to be determined based on PH 08f.

8.9 PH-09 — Philosophy for Control Valve Arrangement in Water and Air Service

I. Objective

The purpose of this philosophy is to define the requirement of upstream and downstream isolation and bypass valve arrangement for Control Valve stations provided in Water and Air service.

II. Types of valves

It covers all types of control valve stations in Water and Air service.

III. Philosophy for Water control valves

PH 09a No isolation/bypass valves are provided for control valves installed on spare equipment. Equipment isolation valves are used for maintenance of these valves.

PH 09b Bypass line / valves are generally installed for water control valves.



PH 09c For lines above 2”, 1” bleed valve is provided upstream of all control valve with isolation valves. For lines 2” and below, ¾” bleed valve can be provided.

PH 09d Size for upstream and downstream isolation valves is generally same as the line size.

PH 09e Globe valves are used as bypass valves.

PH 09f Bypass valves size are generally kept same as control valve size.

IV. Philosophy for Air control valves

PH 09g All control valves in Air service are provided with upstream and downstream isolation valves and upstream bleed valve.

PH 09h Bypass line is not provided for instrument air control valves.

PH 09i The isolation valve type should be selected per philosophy PH-13.

8.10 PH-10 — Philosophy for Requirement and Type of Sampling Systems

I. Objective

The purpose of this document is to define the requirement and type of sampling.

II. Type of service

It covers all types of services.

III. Philosophy

General

i) Sampling connection on piping is usually not less than ¾”. A block valve shall be provided as close to the header as possible. It is followed by a globe or needle valve. The distance between these valves is kept as short as possible.

ii) Where sampling of hazardous fluids is required, the sample outlet shall be connected to the process line or flare system.

iii) The sampling shall not be located at dead legs of the process line.

iv) Sample outlet is located at grade or accessible platform.

v) Cooling requirements for sample points should be discussed with the client.



vi) Sampling connection tags should clearly show where the purge is to be routed to (drain, flare).

vii) Sampling arrangement should be detailed in the P&IDs as per clients standards.

8.11 PH-11 — Philosophy for Providing Handwheels to the Control Valves and Automatic Isolation Valves

I. Objective

The purpose of this document is to define the requirement of hand wheels for control valves and automatic isolation valves.

II. Types of valves

It covers all types of control valves and automatic isolation valves.

III. Philosophy

PH 11a Hand wheels are not provided on control valve or automated isolation valve which is linked with an Interlock and or an emergency function.

PH 11b Hand wheels are generally not provided to control valves on spared equipment which can be isolated.

PH 11c Hand wheels are generally not provided to control valves which have redundant control valves.

PH 11d Hand wheels are generally not provided to control valves with isolation valves and a bypass.

PH 11e Hand wheel is generally provided to control valves without bypass or redundant control valves except if they are used in shutdown or automatic emergency.

8.12 PH-12 — Philosophy for Instrumentation across Air Coolers

I. Objective

The purpose of this document is to define the requirement of instruments across air coolers

II. Philosophy

PH 12a Minimum provision of two temperature instruments is generally given for streams outlet of air cooler. The selection of thermowell, TE or TT is as per individual equipment.



PH 12b For spared equipment one temperature element is generally provided to exchanger but one additional temperature element can be placed on the common line.

PH 12c Pressure gages may not be provided on inlet / outlet lines of air coolers.

8.13 PH-13 — Philosophy for Selecting Type of Valves Used in the Facility

I. Objective

The purpose of this philosophy is to define the type of valves to be used for gas, oil, water and air service. This specification also covers shutdown valves.

II. Type of Valves

Ball, Gate, butterfly and Globe valves shall be used for the facility. Process engineers should follow the piping specification (project specific) for the type of valves that can be used for the piping class.

III. Philosophy

PH 13a Ball valves are generally used for gas service lines.

PH 13b Globe valves are used for bypass and regulating service.

PH 13c All the bleed valves (drains and vents) are generally not flanged instead a threaded cap is provided. Care should be taken to refer to the piping specification especially for the high pressure services where a flange connection may be required.

IV. Exceptions

i) Valve type for control valves is not covered in this philosophy.

8.14 PH-14 — Philosophy for Designating Lines as No Pocket, Free Draining, Slope or Gravity Flow

I. Objective

The purpose of this philosophy is to define various terms shown on P&IDs and the services for which such terms will be applicable.

II. Sizes

All sizes



III. Definitions

Gravity Flow: Elevations downstream never exceed elevations upstream. Line may contain low pockets.

Symbol / P&ID representation:

Slope: Elevation changes are constantly downwards only. No pockets are permitted. Specific slope requirements are shown on the line with a slope symbol. Flare lines will have a slope of 1:200.


1:200

Free Draining to:Elevation changes are downward only. No pockets are permitted.


No Pockets: It means that the line shall be installed without any pockets. When only low pockets are not allowed, “no low pocket” is to be written. When no high pocket is allowed, “no high pocket” is to be marked on P&ID. Equipment will not be considered part of pocket.

No Pockets

IV. Philosophy

PH 14a All pump suction lines is generally free draining to the pump suction.

PH 14a All closed drainage piping shall be free draining towards the closed drain drum.

PH 14a The compressor suction lines should not have pockets.

PH 14a The PSV outlets lines should free drain to relief header. PSV inlet should free drain towards vessel / line.



PH 14a PSV lines routed to atmosphere generally do not have pocket.

8.15 PH-15 — Philosophy for Piping / Instrument Arrangement on Pump Suction and Discharge Lines

I. Objective

The purpose of this philosophy is to define the piping/instrument arrangement at the pump suction and discharge lines.

II. Type of Equipment

i) Centrifugal pumps

ii) Reciprocating pumps

III. Philosophy

PH 15a The size of the suction and discharge valves are generally the same as the line size.

PH 15b Recycle lines, if required, are preferably connected back to the suction vessel.

PH 15c Temporary strainers are installed on suction side of all pumps unless permanent strainers are specified.

PH 15d General rules for piping arrangement in centrifugal and reciprocating pumps:

Suction Line

The following fittings/valves shall be installed on the suction line:

o The piping fittings shall be as per the fig below.

o Suction strainer with local PDI across the strainer. A PDIT may be considered if in critical service.

o Pressure gauge is not generally provided in pumps taking suction from atmospheric tanks.

o Drain valve to grade.

Discharge Line

The following fittings/valves is generally installed on the discharge line:

o Local pressure gage, check valve and manual block valve.

o A vent installed between the pump and the discharge line check valve.



o Minimum flow by-pass line (for centrifugal pumps).

o A bleed valve, installed between the pump discharge and the check valve.

o A bleed valve, installed between the check valve and the discharge block valve.

o Typical pump representation on P&ID is shown below:

Figure 21 – A Typical Pump Representation on P&ID

PDT

PI

PI

8.16 PH-16 — Philosophy for Providing an Actuator on Stand Alone Valves

I. Objective

The purpose of this document is to define the criteria for providing an actuator for a valve which is not connected to any regular plant operation or control / Interlock.

II. Type

All sizes

III. Philosophy

General

PH 16a All valves 8’’ and above generally have an actuator to ease operability of the valve.

PH 16b Automatic actuator may not be provided for the following conditions:

a) Locked open (LO) and Locked closed (LC) valves will not have actuator.

b) Upstream or downstream isolation valves of control valves, bypass valves of control valves and XV’s.



c) Upstream and downstream isolation valves of pumps, strainers, filters, exchangers, etc., requiring infrequent operation.

8.17 PH-17 — Philosophy for Nitrogen Connections to Equipment and Piping

I. Objective

The purpose of this philosophy is to define the valves arrangement required on Nitrogen connections to equipment/ piping.

II. Type of service

All Nitrogen connections.

III. Philosophy

N2 Connection is usually provided with one globe valve, one check valve, a spectacle blind, and a ball valve.

Each HC/Hazardous service compressor stage generally have a nitrogen purge connection just inside the suction block valve. The purge connection shall be supplied by piped nitrogen installed with a block valve immediately adjacent to the compressor suction line, check valve, drain valve, hamer type blind and a nitrogen line block valve.

8.18 PH-18 — Philosophy for Valve Numbering on P&Ids

I. Objective

The purpose of this philosophy is to define the basis for valve numbering on the P&IDs.

II. Type of Valves

Control valves, pressure safety valves and valves with automatic operator.

III. Philosophy

PH 18a All control valves and pressure safety valves (PSV) are usually numbered and shown on individual P&IDs. Control valve details and PSV details will be shown on individual P&IDs.

PH 18b All valves with automatic operation are numbered and generally shown on individual P&IDs.

PH 18c The valves that are part of the package vendor scope are normally numbered by Vendor, following the guidelines provided by instrumentation.



PH 18d Root valves for pressure taps and level bridles are generally not numbered.

PH 18e Manual valves are not numbered during FEED phase of the project. These are usually numbered during detailed engineering phase.

8.19 PH-19 — Philosophy for Showing Instrumentation Details on the P&Ids

I. Objective

The purpose of this philosophy is to define the philosophy for showing instrumentation details on the P&IDs.

II. Types of Instruments

All instruments

III. Philosophy

During the FEED stage of the project, root valves and bleed valves for inline instruments are generally not shown on individual P&IDs.

PH 19a Details for level bridles should be shown on individual P&IDs.

8.20 PH-20 — Philosophy for Vendor Package Equipment Information

I. Objective

The purpose of this philosophy is to provide a guideline about the equipment vendor information to be shown on P&IDs.

II. Types of Equipment

i) Dehydration Unit

ii) Process compressor and gas turbine package

iii) Air Compressors

iv) Instrument Air Dryers

v) Nitrogen generation

vi) Other Miscellaneous Utility Packages

III. Philosophy

General

PH 20a Details of Vendor package equipment are shown on vendor P&IDs supplied by Vendor. Project P&IDs should provide clear reference to vendor P&ID numbers.



PH 20b Instrument signals confined within a vendor package are not shown on project P&IDs. Common trip/alarm from vendor package to DCS are generally indicated on project P&IDs..

PH 20c The vendor package should be shown as a blank box on P&IDs with scope break lines.

PH 20d The information for package equipment to be normally provided on P&IDs is as follows:

Dehydration Unit

i) Gas Capacity.

ii) Main process and utility interface connections.

iii) Only vendor instrumentation signals which interface with the main Distributed Control System (DCS) or Emergency Shutdown System.

Compressor and gas turbine

i) Duty.

ii) Major process equipment with major controls.

iii) Main process and utility interface connections.

iv) Only vendor instrumentation signals which interface with the main Distributed Control System (DCS) or Emergency Shutdown System.

Air Compressors / Instrument Air Dryers / Other Utility Packages

i) Capacity

ii) Process and utility connections (relief connections, vents, drains routed outside of the package, utility water lines).

iii) Only vendor instrumentation signals which interface with the main Distributed Control System (DCS) or Emergency Shutdown System.

The philosophy mentioned above is indicative and should be followed for other packages too. Some additional details may be added in the vendor box on the P&IDs to aid engineering, if required.

8.21 PH-21 — Philosophy for Valve Check List

I. Objective

The purpose of this philosophy is to define a valve check list that allows identifying and verifying the proper provision of block and check valves in the Plant.



II. Sizes

All sizes, no size or spec. limitations.

III. Philosophy

This philosophy is general and not intended to override any individual philosophy in this document. In case of conflict, the individual philosophy shall be governing.

PH 21a Block valves are normally provided in the following cases:

1) For all lines crossing the plant battery limits and crossing a bridge.

2) At vessel and tank nozzles and at pump and compressor suction and discharge lines

3) At utility lines connected to lines or process equipment

4) For isolation purpose of instruments or equipment to be inspected during normal operation of the plant.

5) At utilities hose stations.

6) At sampling devices.

7) For preventing flow or diverting flow through an alternative route.

8) At suitable points in fire water ring to allow isolation.

9) On each connection line from the instrument air and nitrogen distribution headers.

10) Block valve type shall be according to piping class. Generally ball valves should be used.

PH 21b Double valve are normally provided for:

1) Utility lines permanently connected to process lines or equipment in all cases.

2) Preventing product contamination where the use of spectacle blinds is not suitable.

3) Sample connections.



4) Equipment drain lines with operating pressure over 150 psig

5) Bypass lines around control valves with an operating differential pressure of 150 psi or more.

PH 21c Check valves are normally provided where necessary to prevent back flow:

1) On the discharge of centrifugal and rotary pumps and compressors.

2) On the discharge of dosing and volumetric pumps.

3) On utility lines permanently connected to process lines or equipment.

4) Check valve may be provided on all lines connected to flare header. A block valve should be provided downstream of the check valve and should be specified LO. A bleeder should be provided in between check valve and the block valve.

8.22 PH-22 — Philosophy for Spectacle Blinds / Spacer Blinds Check List

I. Objective

The purpose of this philosophy is to define a check list that allows identifying and verifying the proper provision of blinds in the Plant.

II. Sizes

All sizes, no size or spec. limitations.

III. Philosophy

This philosophy is general and not intended to override any individual philosophy in this document. In case of conflict, the individual philosophy shall be governing.

Blinds generally provided:

PH 22a At battery limits, for all the lines entering or leaving geographical unit. Blinds are installed towards the plant side.

PH 22b For isolation purposes at vessels to be inspected during normal operation of the plant.

PH 21c To prevent contamination of process or utility lines, during normal or special operation.



8.23 PH-23 — Philosophy for Utility Connections to Piping or Equipment

I. Objective

The purpose of this philosophy is to define the arrangement required on utility connections to piping or equipment.

II. Types of service

Any utility (water, steam, etc.).

III. Philosophy

Utility lines, if permanently connected to process piping or equipment, generally include the following:

PH 23a Block and check valve to be installed at minimum distance from equipment. Material and rating for block and check valves is selected based on the most stringent condition of the process or utility service.

PH 23b Check valve can be omitted for connections used only when equipment is not operating, such as “steam out”.

PH 23c Spectacle blind to be provided for infrequent service.

A spool piece can be used instead of a spectacle blind.

PH 23d In case multiple fluids are to be provided at different times, one connection to piping/equipment is provided.

8.24 PH-24 — Philosophy for Instrumentation on Pig Launchers

I. Objective

The purpose of this philosophy is to define the minimum instrumentation to be provided on the pig launchers.

II. Philosophy

General

PH 24a Pressure gauge are gnerally provided.

PH 24b One or more PSVs is generally installed to protect the pig launcher from overpressure. This may not be required if not a coded vessel.

PH 24c One flow orifice is provided in the depressurization line going to flare / Drains. The depressurization is carried out with manual globe valve.



8.25 PH-25 — Philosophy for Blow Down Valve (BDV) Arrangement

I. Objective

The purpose of this philosophy is to define the requirement of the BDV and the arrangement for the BDV to be shown on P&ID.

II. Philosophy

PH 25a Equipment operating above 100 psig are generally provided with BDV.

PH 25b For piping segments, emergency blowdown is generally required for segments which contain more than 100 ft3 flammable gas or light hydrocarbon liquid operated at 100 psig and above.

PH 25c For storage tanks emergency blowdown is not required but a fire water system can be provided.

PH 25d BDVs require a downstream isolation valve with a bleeder valve located between the two. Isolation valve should be locked open.

PH 25e A flow orifice should be provided downstream of BDV.

PH 25f A check valve can be provided upstream of BDV.

PH 25g All BDV are generally specified as tight shut off valves (TSO).

Figure 22 – A Typical Representation of BDV on P&IDs.

BDV

FO

LO

SP

TSO LO



8.26 PH-26 — Philosophy for Shut Down Valve (SDV) Arrangement

I. Objective

The purpose of this philosophy is to define the requirement of the SDV and the arrangement for the SDV to be shown on P&ID.

II. Philosophy

PH 26a Emergency SDV is required in the pump suction when all of the following criteria are met:

1) Pump capacity exceeds 1 GPM.

2) The normal quantity of liquid in suction vessel exceeds 200 gallons.

3) Suction vessel is pressurized or is under vacuum. (Vapor space @ > 0.1 psig).

4) Pump service is in category as follows:

o Operating temperature above auto ignition temperature. o Liquefied flammable gases with vapor pressure above

14.7 psia @ 100 oF. o Cooled flammable liquids with vapor pressure above

14.7 psia @ 100 oF. o Hot flammable liquids with vapor pressure above 14.7

psia @ operating temperature. o Highly toxic liquid. o Exception: Diesel pump suction line should be provided

with a SDV.

PH 26b Emergency SDV is required in the pump discharge for pumps of 1 GPM or more capacity, of any pumpage service that discharge into systems operating above 500 psig and containing more than 200,000 SCF of flammable vapor.

PH 26c Compressors having flammable and highly toxic gas generally have the following emergency isolation.

1) Compressor suction SDV.

2) Compressor discharge SDV.



PH 26d SDVs are generally provided at following locations:

1) For pumps as per PH 26a, b

2) For compressors as per PH 26C

3) On individual production flow lines close to production header.

4) On individual Test flowlines, close to test header.

5) Test separator liquid outlet.

6) At crude oil pig launcher and gas pig launcher.

7) At battery limits of crude oil and gas pipeline.

9) HP and LP fuel gas scrubber inlet.

PH 26e SDVs generally have upstream and downstream isolation valves with a bleeder installed between them when the SDV valve is part of the inlet system boundary.

PH 26f SDVs may be used as isolation valves for system or component isolation.

PH 26g A full size bypass around the SDV in pump suction line is sometimes provided with a lock closed manual block valve. A 2” LC bypass for other SDVs are considered for pressure equalization during startup.

9.0 PROCESS RELATED TO OFFSHORE FACILITY TYPE

Depending on the type of offshore facility, the process department may be involved in more activity than the process and utility systems.

The offshore facility type may impact the topsides process design due to motion, space and weight constraints.

9.1 Safety System

Process facilities shall be designed for safe operation. The challenge in offshore is the restricted area where personnel are exposed to potential danger.



The safety system is built with two levels of protection. Those two levels shall be independent from each other.

The primary level is the highest order and the secondary level is the next highest order.

To define the adequate level of protection, one shall use proven system analysis techniques like SAT, SAC, SAFE as recommended in API 14C.

Appropriate support documentation shall be provided (safe logic diagrams, etc).

9.2 Special Consideration for Design of Topside Facilities for Floating Production Systems

9.2.1 Impact of motion on equipment performance, equipment design/ Technology selection

All types of floating production systems have wave motion that can create six degrees of motion – pitch, roll, yaw, surge, sway and heave (see figures following). Yaw and sway do not have much effect on process equipment design while surge, heave, roll and pitch may have significant effect.

Problems caused by motion include spirit level effect (results in higher gas velocities, potential liquid entrainment in gas and in some cases foaming), resonant waves (causing phase mixing in oil and water compartments), turbulence (causing poor gas/liquid and oil/water separation).

9.2.2 Effect of motion on specific equipment

9.2.2.1 Separators

Loss of efficiency, foaming, phase mixing, interface control problems.

9.2.2.2 Oil Treaters

Waves at interface can short out the grid, emulsion distribution is affected. Other effects are same as for separators.

9.2.2.3 Produced Water Treatment System

Same effects as for separators.

9.2.2.4 Fuel Gas System

No significant effect is observed but the level control issues may arise.

9.2.2.5 Manifolds, Heat Exchangers, Pumps, Compressors, Coolers and Metering Units

No significant impact anticipated as process is either single phase or well mixed two phases. However rotating equipment department should take vessel motion into account.



9.2.2.6 Tray Tower

Channeling of gas flow, reduction in gas/liquid contact may affect mass transfer.

9.2.2.7 Packed Tower

Gas/Liquid contact generally not significantly affected.

9.2.2.8 Process Control

Motion causes process control problems (especially with float type level instruments) including false alarms.

9.2.3 Mitigation of Motion Effects

9.2.3.1 Equipment Specification

Acceleration and wave motion parameters should be included in development of equipment specifications and these should be communicated to equipment supplier for evaluating potential impact on equipment design.

9.2.3.2 Equipment Location

Axis of process equipment is to be located along the axis of minimum pitch (if applicable).

Critical equipment are to be located close to the Centre Of Gravity (COG). Most critical equipment include separators, treaters, trayed towers, less critical equipment include two phases separators, scrubbers, surge tanks, packed towers, heaters, etc and least critical equipment include production manifold, heat exchangers, pumps, compressors, etc.

9.2.3.3 Internals

Production vessels need to be sized and internals to be designed to achieve desired performance under specified vessel motion conditions. Internal baffling needs to be optimized to reduce total turbulence. More advances internals may be required if baffling is not adequate/effective.

Dynamic simulation studies might be required from equipment Supplier for performance warranty when considered critical.

9.2.3.4 Produced Water Treatment

Performance of conventional topside produced water separation equipment such as skimmer vessel, induced gas floatation system may be significantly affected due to vessel motion. The use of hydrocyclone is highly recommended for produced water system for floating systems. Hydroclyclones offer much higher separation efficiency,



occupy less deck space and capacity can be increase during the life of the facility (if required) by addition of conical tubes.

9.2.3.5 Storage tanks

Storage tanks design should be carefully looked at in view of vessel motion and inclination, nozzles (such as those for overflow and pump suction) should be properly located.

9.2.3.6 Piping slope

Special piping slope requirements are to be identified and shown on P&IDs.

9.2.3.7 Hazards and Operability

Specific points related to floating system design should be highlighted and discuss during HAZOP to evaluate potential Hazard or Operability issues.

9.2.3.8 New technology

New equipment technology such as cyclone/vortex separators/Mist eliminators, separators equipped with properly designed wave motion internal baffles, electro-pulse inductible coalescers (EPIC), insulated electrostatics equipped separators or rotating separators may be used if economic considerations permit for better separation and compact designs.

Oil bath bearings may be used for pumps or other rotating equipment as applicable.

9.2.3.9 Flow assurance

(Major consideration in Deep Water Field development)

This requires a broader and in-depth analysis of reservoir, production profiles, operating conditions, sizing of flowlines, well fluid characteristics at various stages, identification of potential hydrate problems, required chemical injection (such as LDHI methanol etc). This may require additional equipment such as storage tanks, injection pump skid, sub-sea chemical injection will require use of umbilical.

Design is to be compliant with MMS and marine codes as applicable.

10.0 TOOLS AND SOFTWARE

Tools and software are common to Onshore and Offshore process. Calculation sheets are under Process Company program, PISCES.

Softwares used by Process are listed under Technip USA intranet, Section “Engineering Softwares”, Sub-section “Engineering Applications Information”.



11.0 FORMS / ATTACHMENTS

Forms are common to Onshore and Offshore process.

Refer to Technip USA Engineering DRB, Section “Data Sheets” for process equipment specifications.

1) TPUSA-ENG-RP-PS-0004-0, Equipment Sizing and Selection Guidelines

2) TPUSA-ENG-RP-PS-0006-0, Standard Engineering Calculations

3) TPUSA-ENG-RP-PS-0001-0, Pump Design

4) TPUSA-ENG-RP-PS-0003-0, Heat Exchanger Design

12.0 REFERENCES

12.1 Standard and Recommended Practices

1) Engineering Design Verification and Checking TPUSA-ENG-PR-EN-0012-3

2) API RP14E, Recommended Practice for design and installation of Offshore Production Platform Piping System

3) API RP520 Part II, Sizing, Selection and Installation of Pressure Relieving devices in Refineries

4) API STD 521, Guide for Pressure Relieving and Depressuring System

5) API RP14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms

6) API RP14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities

7) API Spec. 12 GDU, Specification for Glycol-type Gas dehydration units.

8) GPSA, Process Design Guideline

9) Technip Process Data Book, EG312_1_1_1 to EG312_1_1_3

13.0 RECORDS

Not Applicable

offshore process reference book rev 4.pdf

Documents