A ROUGH GUIDE TO OFFSHORE PLATFORMS OR FPSO

About plant design scheme

1. 1. PLANT DESIGN
A ROUGH GUIDE TO
OFFSHORE PLATFORMS

2. 2. DESIGN BASIS
• What is the client trying to achieve?
• We need to know what the plant feed is
• And what the products need to be
• Accurate compositions and production
forecasts; Plant design flow and turndown
• FTHP, FTHT, SITHP
• Ambient conditions
• Product specs –oil -BS&W, RVP; gas -
dewpoint, LHV, Wobbe index, CO2,
dryness spec, and sweetness
• Waste water specs –oil-in-water content
? Flow and
turndown

3. 3. WHAT MAKES UP A PROCESS
PLANT?
• equipment
• piping and valving
• instruments and controls
• safety systems (fire and gas) and shutdowns
• utilities (water, FG, air, nitrogen, waste water)
• storage (sometimes for oil platforms if no pipeline)
• communications systems
• electrical systems
• structural supports
• accommodation (if a manned site)
• needed to convert the raw crude into a usable product

4. 4. WHAT ARE PROCESS
ENGINEERS INTERESTED IN?
• Process Equipment
• Piping
• Instruments and controls
• Safety systems
• Utilities
•Storage
• Supplying information to other disciplines

5. 5. WHAT IS THE PURPOSE OF A
PROCESS PLANT?
• Convert raw material to usable product
• Oil platform produces stable crude to be
fed to a refinery
• Gas Platform produces gas which may
need further treatment (sweetening etc.)
• To satisfy a demand and make money for
the client

6. 6. WHAT IS THE PROCESS
ENGINEER’S ROLE?
• Process is at the heart of the plant
• With no process everyone else can go
home
• We tell other disciplines what they have to
do
• We provide them with data to let them do
their job

7. 7. PROCESS ENGINEERS WORK • Define plant streams (P,T,F,C)
• Do process simulations
• Determine and size the equipment required
• prepare the process specification and data
sheets for the equipment
• size the lines and prepare line lists
• determine the control systems required
• prepare instrumentation data sheets
• design the safety systems

8. 8. PROCESS ENGINEER’S WORK • prepare SAFE Charts to API-14C
• check other disciplines work
• Do feasibility studies and write reports
• write operating procedures
• write commissioning and start-up
procedures
• prepare philosophy documents (plant
sectionalisation, sparing, relief and
blowdown, general operating, and design)
• write system descriptions

9. 9. PLANNING YOUR WORK
• List your activities
• Allocate time to each activity
• Prioritize your activities
• Put your activities in order and show which
activities follow which
• You can do a network diagram and barchart
and work out which items are critical

10. 10. PLANNING YOUR WORK (cont)
• Example:
1. Read background information and ensure you
understand what the client is trying to accomplish –
2 days follows (start)
2. Do simulations on HYSYS –3 days follows (1)
3. Prepare PFDs and UFDs, heat and material
balances –5 days follows (2)
4. Prepare first issue P&IDs & linelist –20 days follows
(3)
5. Prepare equipment list –2 Days follows (3)
6. Size equipment–5 days follows (5)

11. 11. PLANNING (cont.)
7. Size lines (except flare) –2 days –follows (3)
8. Size PSVs –5 days –follows (3)
9. Size blowdown valves/orifices –3 days follows
(6)
10. Size Control valves –5 days follows (5)
11. Size vent lines –2 days follows (9)

12. 12. NETWORK DIAGRAM
1
2
4
20
2
3
3
1
5
2
8
5
6
5
7
2
9
3
10
5
11
2
S
T
A
R
T
2 2
5 5
6 6
26
8 16
4 26 7 26
13 21 10 26
16 24
18 26
F I N
I
S
H
26
26
0 0
26
4
20
26 26
Activity
Earliest finish date
Duration
Latest finish date

13. 13. BAR CHART
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
0 2 4 6 8 10 12 14 16 18 20 22 24 26

14. 14. KEY DOCUMENTS
• Design Basis
• Scope of Work
• PFDs
• Heat and Material Balances
• P&IDs

15. 15. DRAWING/DOCUMENT
STAGES
• rev A for interdiscipline check
• rev B for client comment
• rev C for hazop
• rev D for Design or for Approval
• REV 0 Approved for Construction
There should be an original and master kept
for each issue. The master is marked up
with revisions that are backdrafted and
issued as the next revision

16. 16. DRAWING STAGES (cont.)
• After the drawings are issued AFC, any
changes should be subject to a key
document change request and every
discipline that is affected by the change
must approve it and every discipline must
be aware of it.
• At the end of the project, there should be a
clear audit trail showing every drawing
change

17. 17. DESIGNING A PLANT
• feasibility study to determine economic
viability
• Front End Engineering Design (FEED) or
Basic Design
• Crude testing for emulsion stability, foam,
forming, corrosion, sand etc.

18. 18. BASIC DESIGN
• Simulations (H&M Balances)
• establish equipment sizes
• get basic vendor data for large rotating
equipment and package units
• prepare PFDs and basic P&IDs
• define control systems
• size important large lines
• establish sectionalisation philosophy
• sparing philosophy

19. 19. BASIC DESIGN (cont.)
• control and shutdown philosophy
• operating philosophy
• brief process description
• Determine type of heating utility
• Determine type of cooling utility
It is important to get the basic design right
because in China it is difficult to change
something once it has been approved

20. 20. DETAILED DESIGN
• Confirm Basic Design data
• detailed piping hydraulics
• detailed PSV sizing and specifications
• Vent and Flare Systems sizing
• control valve sizing and specifications
• vent dispersion and flare radiation
• line lists (if done in Basic design, do well)
• process data for instrument and
equipment data sheets

21. 21. DETAILED DESIGN (cont.)
Detailed P&IDs incl.
• Adding line and instrument numbers
• control valve sizes, PSV sizes and settings
• alarm and trip settings
• incorporating vendor data
• integrating vendor P&IDs with your P&IDs
The PFDs and H&M Balances must always
agree with each other and be consistent.

22. 22. LINE NUMBERING
• Normally take the form: size-service code-
system code-sequential number-pipe
spec-insulation spec
• Size –as calculated by the process eng.
• Service code –contained fluid e.g. DC
(drain closed)
• System Code –e.g. process may be 21,
22, 23, 24. May use 21 and 22 for process
liquids and 23 and 24 for process gas
• Sequence number –should be orderly

23. 23. LINE NUMBERING (cont.)
• Pipe spec –as required by design
pressure and temperature and contained
fluid requirements
• Insulation Spec –either for heat retention
or Personnel protection (or sometimes
cold retention)
Line sequence numbering should be done in
an orderly fashion

24. 24. LINE NUMBERING DO’s
• DO allocate a group of numbers for each
P&ID
• DO use similar numbering on parallel
trains (same applies for Instrument
Numbering)
• DO the line list at the same time as adding
line numbers to the P&IDs.
• DO specify test pressure according to pipe
spec.

25. 25. LINE NUMBERING DON’Ts
• DON’T duplicate numbers for various
services
WHY THE DO’s and DON’Ts?
To minimize time for inputting to computer
and minimize CAD time for Process and
Piping Disciplines. This will save a lot of
time.

26. 26. TYPICAL LINE NUMBERING
8”-PV-2052-E2-
H
8”-PL-2083-E2-HCT
8”-PF-2016-E2-HCT
8”-PV-2114-E2-H
8”-PL-2137-E2-HCT
8”-PF-2102-E2-HCT
PI
2032
PI
2116
PI
2132
PI
2032
TRAIN A
TRAIN A
TRAIN B
TRAIN B
8”-PV-2041-E2-
H
8”-PF-2040-E2-
H
8”-PL-2042-E2-H
8”-PL-2142-E2-H
8”-PV-2141-E2-
H
8”-PF-2140-E2-
H
BAD NUMBERINGGOOD NUMBERING

27. 27. OIL PLATFORMS -SPECS
• BS&W (0.5% v/v) in oil
• RVP (8 to 12 psi) of oil
• Produced Water quality (30 ppm oil-in-
water for dumping to Bohai Bay)
RVP is affected by butane and lighter
hydrocarbons

28. 28. BYPRODUCTS AND WASTE
• Associated Gas –HP gas used for power
production, LP gas flared
• Crude Oil is also used for power raising
but not preferred if gas can be used. Oil is
saleable
• Produced Water reinjected or dumped to
sea

29. 29. HANDLING CONTAMINANTS
• Sand –gravel packing, desanding cyclones,
vessel sand-jetting and tornado devices
• Waxes and Asphaltenes –heating and
chemicals (wax and asphaltene inhibitors)
• Asphaltenes dissolve in LPGs can cause
trouble in downstream processes
• Emulsions –chemicals and heating is used
to break these. Basic Design testing.

30. 30. CONTAMINANTS (cont.)
• Foam –treatment chemicals (antifoam)
but the best defence is to keep foam
forming surfactants out of the process
•CO
2
/H
2
S and salts (Cl
-
etc.) Desalters can
be used but not on a platform ( sometimes
on FPSO). Corrosion inhibitors can be
used. pH control important.
• In produced water for reinjection –use
scale inhibitor, deaeration, oxygen
scavenger, biocide, polyelectrolytes, filter
aids

31. 31. ENHANCED OIL RECOVERY
• Water injection
• Gas injection
• Gas lift
• Downhole pumping

32. 32. WATER INJECTION
• Oil Reservoir engineers predict design
information –flow rate and injection
profiles for the life of the platform
• Produced water, source well water, and
sea water are used for injection
• Treatment –removing oxygen, filtering,
treating with corrosion, biocide and scale
inhibitors
• Control of injection wells is by flow and
pressure

33. 33. Gas Reinjection
• gas is compressed and injected under
pressure control
• Gas reinjection wells have similar
wellhead configurations to production
wells

34. 34. GAS LIFT
• Gas is injected to the bottom of the oil riser
which creates a low density two phase mix
of oil and gas with a low static head.
• At the surface, the gas is compressed and
returned to the well bottom
• Gas is absorbed by the oil and so make-
up gas is required

35. 35. GAS PLATFORMS -SPECS
• Dryness (water dewpoint to stop free
water at lowest temperature in pipeline)
• Dewpoint (to stop HC liquids dropping out
in pipeline)
• LHV -range to satisfy users
• Wobbe -range to satisfy users
• Sweetness –to satisfy user specs for CO
2
and H
2
S and give correct Wobbe and LHV

36. 36a. What is WOBBE No.?
• Wobbe no. is related to the heat that a
burner can release at a particular supply
pressure.
• For a particular burner, two gases with the
same Wobbe index will have same burner
pressure drop and same heating value.
• Weaver index is a measure of flame speed
–not normally specified for natural gas.

37. 36. SPECIFICATIONS
•CO
2
< 3% v/v to satisfy LHV and Wobbe
•CO
2
removal by Amine, Benfield (Pot carb),
membranes
• Chemical supplier provides design data to
allow detailed design of CO
2
removal
• Can also be simulated using HYSYS add-
on amine package
• Sulphur –also removed by amine process

38. 37. SPECIFICATIONS
• Sulphur –SO2, H2S, mercaptans –
corrosion and safety problem. H2S can be
fatal in small concentrations. Inhalation of
a single breath at 1000ppm can cause
coma
• Dryness –Why?
• Wet gas is corrosive and can form
hydrates that will block pipes

39. 38. GAS DRYING
• Solid and liquid desiccants.
• Solid desiccants –alumina, silica gel,
molecular sieves
• Liquid desiccants are the glycols and
methanol
• Gas Drying Units use TEG
• Injection of MEG to pipelines is used to
suppress hydrates and also acts to
prevent corrosion
• DEG can be used as a compromise for
both of the above services

40. 39. WET GAS TRANSPORT
• Minimum facilites platform –no drying –
determined by economics
• MEG or MeOH and Corrosion Inhibitor (at
20 ppm) added (determined by
Hammerschmidt equation)
• MEG transported by supply boat or “piggy-
back” pipeline on top of the main gas
pipeline
• MEG regenerated onshore and then
returned to platform

41. 40. WET GAS TRANSPORT
Glycol to platform
Gas with MEG and CI to gas terminal
MEG
regenerated
MEG and CI
added to gas

42. 41. IF HYDRATES FORM
• Methanol injected to dissolve
• Pipe heated externally
• Long pipeline may be depressured and
pigged at low pressure
•NEVER, NEVER,NEVER clear a
hydrate using pressure to push
it !!!!!!!!!!!!!!!!!

43. 42. GAS DEWPOINTING
• Not often done offshore
• Gas is normally dewpointed to about 10ºC
below the minimum ambient or sea
temperature
• Cooling by refrigeration often uses propane
as a refrigerant.
• For deeper cooling, turboexpanders (if
sufficient pressure) or mixed or cascade
refrigeration can be used

44. 43. GAS SWEETENING
• Not normally done offshore. Why?
• It is cheaper and easier to do onshore
• Amine plants (MDEA ) for selective
sweetening
• Benfield Plants for CO2 removal
• Membrane plants

45. 44. HOMEWORK QUESTION
It is necessary to sweeten and compress
a sour (CO2), low pressure wet gas
stream using an MDEA process. How
should we design this plant assuming it is
on an offshore platform and that
centrifugal compressors will be used?
Should the compression come before or
after the sweetening process? What
should we consider and what precautions
should we take in designing this plant?

46. 45. HOMEWORK ANSWER
We should put the compression first even
though the gas is sour. We can use
special materials for the first compressor
wheel (first internal stage). Then the size
of the gas sweetening plant is smaller
because we are operating at high pressure.
After the first compressor wheel, the gas
will be at elevated temperature and hence
superheated above dewpoint.