POL
Petroleum Open Learning
Process Flow & P&ID’s
(Process Engineering Drawings)
Part of the
Petroleum Processing Technology Series
OPITO
1
THE OIL & GAS ACADEMY
Process Flow & P&IDs - Process Engineering Drawings
Petroleum Open Learning
(Part of the Petroleum Processing Technology Series)
Contents
Page
BOOK1
Training Targets
4
Introduction
5
Section 1 - General Features of all Process Engineering Drawings
7
Standardisation of Codes and Symbols
Identification and Key Features
True North and Platform North
Equipment Lists
Section 2 - Plot Plans and Elevation Drawings
Modules
Scales
Elevations
Plot Plans
Visual Cues
training targets for you to
achieve by the end of the unit
test yourself questions to see
how much you understand
check yourself answers to let
you see if you have been
thinking along the right lines
18
activities for you to apply your
new knowledge
summaries for you to recap on
the major steps in your progress
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Contents (cont’d)
Section 3 - Process Flow Diagrams
Page
21
Introduction
Wells
Manifolds
Test Separators
Pig Launcher
Crude Oil Process Flow
Crude Oil Pumps
Gas Compression
Mass Balance
Section 4 - Piping and Instrument Diagrams
training targets for you to
achieve by the end of the unit
test yourself questions to see
how much you understand
check yourself answers to let
you see if you have been
thinking along the right lines
33
Every Day Use for Operators
The Ground Rules for P&IDs
Wellheads
Separation
Oil Booster Pumps
Gas Compression
Check Yourself - Answers
Visual Cues
activities for you to apply your
new knowledge
summaries for you to recap on
the major steps in your progress
46
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Contents (cont’d)
Page
BOOK 2
* Section 1
Definitions of Piping and Instrument Diagram Symbols
* Section 2
Practical Application of Symbols
* Section 3
Piping and Instrument Diagrams
Visual Cues
training targets for you to
achieve by the end of the unit
3
40
44
test yourself questions to see
how much you understand
check yourself answers to let
you see if you have been
thinking along the right lines
activities for you to apply your
new knowledge
summaries for you to recap on
the major steps in your progress
3
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Training Targets
When you have completed this unit on Process Engineering Drawings, you will be able to:
• Interpret symbols, codes and other information detailed on process flow diagrams (PFDs) and piping and
instrument diagrams (P&IDs).
• Demonstrate an understanding of the basic engineering standards utilised in PFDs and P&IDs.
• Identify equipment and valves by the symbols utilised on PFDs and P&IDs.
• Draw a simple process flow schematic using relevant symbols and codes.
• Detail the design criteria and objectives expected, from the information provided on a PFD.
• Describe the equipment used to achieve the design objectives from the information provided on a P&ID.
• Interpret the control process of equipment from the information provided on a P&ID.
Tick the box when you have met each target.
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Process Engineering Drawings
Petroleum Open Learning
Introduction
Note: For ease of reference, all Figures and Illustrations referred to are contained in Book 2
We use drawings to depict things which cannot
easily be described by words, or to depict things in a
way which can cross language barriers. Some very
early written languages consisted almost entirely of
small drawings, and even today we use symbols
instead of words for simple messages. An example
of this type of written language is seen in Figure 1.
It is an essential item of information in restaurants
and other public places all over the world and, even
if you cannot read the local language, you should
know which door to use !
The three types of drawings which we will work with
are:
•
Plot and Elevation Drawings (also called
Plot Plans) which show the physical location
and relevant position of various items of
equipment.
•
Process Flow Diagrams (also called Mass
Flow Diagrams) which show the operating
parameters, the main control points and the
mass balance data of oil, gas, water and other
process fluids flowing through the process.
•
Figure 1
The design and construction of an oil production
facility requires the use of many and varied types
of drawings. In this Unit we will look at the three
main types of drawing which will be of use to you in
understanding and operating an oil and gas
production facility,
For the purposes of the Unit, I have used drawings
for one oil production platform located in the UK
Sector of the North Sea.
I will first of all explain the key features and
terminology used in all drawings and then explain,
in turn, how each drawing is interpreted. In most
sections we will finish by looking at a particularly
detailed drawing and discover how we can interpret
the drawing to discover its full meaning.
This Unit comprises two Books split into four
sections as follows:
Book 1
•
Section 1 will explain the standards applied,
key features and terminology common to all
types of drawings. I will explain the revision
process for all drawings and define the
information that can be gleaned from the
drawing identification label. We will then look
at a few examples of the various types of
drawings.
•
In Section 2 we will take a brief look at Plot
Plans and Elevation Drawings. I will explain
how they are used to indicate the physical
location and the orientation of particular items
of equipment.
•
In Section 3 we will look at Process Flow
Diagrams (PFDs). I will explain how the
designer of a production facility uses process
flow diagrams to show how the process
equipment will achieve the design criteria.
Piping and Instrument Diagrams which
show the design criteria for the piping,
instrumentation and equipment used in the
process.
We will look at Process Flow Diagrams and Piping
and Instrument Diagrams in some detail because
they are the main tools for understanding the design
basis of the process and how it should operate.
We will also look at Plot and Elevation Drawings in a
little less detail, so that you will know what they are
and how to use them.
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• In Section 4 we will look at Piping and Instrument
Diagrams (P&IDs). They are of tremendous
importance to operators in their everyday work and
I will explain the symbols used on the drawings, and
the way in which the symbols are interpreted. At
the end of this section we will take a real P&ID of a
complex section of a process and work out how the
process operates.
Book 2
• Contains all the drawings that we will use in
this unit. It also contains drawings of symbols,
as specified by British Standards, with an
explanation of what the symbol means, what
the item of equipment is meant to do, and
where the item of equipment may be used.
I have chosen to lay out the Unit in this way
so that you may study the individual sections
of the Unit and refer to Book 2 as and when
required in the text.
I recommend that you read Section 1 and then
take a few hours to study the symbols and
explanations contained in Book 2. After that you
can use Book 2 to look at the various drawings
which we will use throughout the unit, and also
as a reference document as required.
As I have already explained, during this Unit we will
concentrate on one particular installation, but at the
end of the Unit you will be able to look at the relevant
drawings of any oil producing facility and be able to
work out the key features of:
•
what design objectives the process is expected
to achieve
•
what equipment is used to achieve the design
objectives of the process
•
how the process equipment is laid out, and
•
how the process is controlled
Whilst using these drawings as a learning aid
you should always remember that each facility is
unique, therefore Process Engineering Drawings
may differ slightly in terms of symbols used,
legends, terminology and design requirements.
The symbols and terminology used in this unit
are those which must be used in the examination
paper.
Summary
The whole purpose of this Unit is to
explain how to use the main types of
drawings which you may encounter in
the Oil and Gas Industry. One of the best
methods when learning a new process
is to start by studying the drawings to
discover what the process is meant to do
and what equipment will be used.
If you know what the symbols mean, and
you know how to interpret the drawings,
looking at a process drawing can be
as interesting as reading a good novel.
This especially applies if you are going
to operate or work on the process in the
future.
Before moving on, take a few minutes to
look at Figures 9 and 10 in Book 2. They
may seem extremely complicated but,
by the end of this Unit, you will be able to
“read” them like a book.
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Process Engineering Drawings
Section 1 - General Features of all Process Engineering Drawings
Standardisation of Codes
and Symbols
Instrument codes and symbols are graphically
represented in engineering drawings. Such
drawings are of particular importance to operation
and maintenance technicians, who require to
understand the process and control systems
associated with an installation.
Difficulties often arise due to the existence of
several systems of codes and symbols, which have
been developed over the years by the various
companies who carry out engineering design,
construction, and operation of process facilities.
The need was therefore recognised for
standardisation of codes and symbols, along with
recommendations of general principles for
engineering drawings.
The following British Standards are now referred to
for guidance on recommended practices,
specifications for graphical symbols, basic
requirements and general principles for all
engineering drawings.
BS 1646 :
Symbolic representation for
process measurement control
functions and instrumentation
Part 1: 1979 Basic requirements
(Also incorporated as ISO 3511/11977)
Part 2: 1983 Specifications for additional basic
requirements
Part 3: 1984
Specifications for detailed symbols
for instrument interconnection
diagrams
BS 5070 : Engineering diagram drawing
practices
Part 1: 1988 Recommendations for general
principles
Part 3: 1988 Recommendations for mechanical/
fluid flow diagrams
BS 1553 :
Graphical symbols for general
engineering
Part 1: Piping systems and plant
BS 308 Engineering drawing practice
Petroleum Open Learning
I will now summarise the scope of each of these
British Standards.
BS 1646: Establishes a symbols system for use in
identifying the basic functions of measurement and
control equipment, in relation to the plant with which
it is associated.
The symbols are used on PFDs and P&IDs.
BS 5070 : Part 1 gives recommendations for the
general principles of presentation and practice, to
be applied to engineering diagrams of all types that
depict functions of a system by the use of graphic
symbols.
Some definitions that are contained in this document
are :
Line - A graphic convention showing how devices
(represented by symbols ) are connected. A variety
of types of line are used to represent connections
having different functions.
Symbol
- A symbolic graphic convention
representing a discrete manufactured device
contributing to the function of a system or circuit.
Drawings / Diagrams - Commonly, as a diagram
can be called a drawing and a drawing can be called
a diagram, it is useful to summarise the difference
in the scope of British Standards.
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BS 5070 : covers the drawing of diagrams which
are normally associated with flow of one sort or
another and which relate components ( usually
indicated by symbols) functionally, one to another
by the use of lines, but do not depict shape, size or
form.
We will not make continual reference to these
Standards throughout the rest of this unit, although
we will adhere to the practices recommended in
them.
BS 308 : covers what are commonly accepted to
be drawings which define shape, size and form.
In this unit we will use the definition drawings when
referring collectively to all types of diagrams and
drawings as in Process Engineering Drawings,
which refer to various types of diagrams and
drawings.
Part 2 gives recommendations for the practice to be
followed in preparing mechanical, process and fluid
flow diagrams ( PFDs and P&IDs ). It covers all
aspects of diagram representation except the
choice of symbols for particular components; this is
the subject of BS 1553 and BS 1646.
BS 1553 : Specifies graphic symbols for use in
the creation of flow and piping diagrams for process
plant, and heating and ventilating installations. It is
intended that diagrams employing these symbols be
drawn in accordance with practices recommended
in BS 5070.
BS 308: Is not really applicable to PFDs and P&IDs
as was seen when we discussed the difference
between a drawing and a diagram.
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Identification and Key Features
The first feature of all drawings is that they
must have a specific identity. Figure 2 is a
typical identification label.
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From the label we can see that the drawing
relates to :
• Contract Number 6-23-2679/151
• For POL Oil Limited,
• On the ‘Alpha’ Field Development.
The identification label tells us that the main
contractor on the project is Adams Atlas Engineering
Limited and that the drawing is a General Legend for
Piping and Instrument Diagrams. A general legend
provides us with the vital information such as :
• Piping symbols
The identification label also provides us with the
drawing number, the history of the drawing , the
initials / names of all persons involved in producing
it, and any reference drawings used.
• Abbreviations
A breakdown of the information provided by the
drawing number in Figure 2 is as follows :
Project
In this case the Alpha project.
Originator
AA - The drawing was
produced
by Adams Atlas
Engineering Limited.
Area/Mod
This can be used to identify the
location of the equipment on an
installation by reference to the
module number.
Discipline
PR tells us that this refers to
Process systems. Other codes
used would be, DR for Drilling
systems, HV for Heating and
Ventilation systems, SS for
Subsea systems and so on.
Type
This refers to the type of
drawing, in this case PD infers
that it is a P&ID. Other codes
would be, FD for Process Flow
Drawing, PP for Plot Plan, EL
for elevation.
• Equipment identification numbering
• Vessel trim designation numbering
• Instrument symbols
• Meanings of instrument identification letters
• Equipment symbols
• Product designation codes
• Insulation class
• Primary equipment classification
• Line designation numbering
• Instrument identification numbering
• Valve symbols
is used. This will ensure that
there is a sufficiently high
number base available to cater
for all drawings required. In
some cases the first two digits
in this number will refer to the
system number and the next
two digits provide the reference
number of that drawing within
this particular system. As an
example, if the fuel gas system
number is 21 then the drawing
number of the fuel gas system
would be PR-PD-2101.
The unique number allocated to each drawing
provides information that helps us identify the
project, system, type of drawing, and its revision
number.
• General symbols
• System numbers
Sequence No In this case a four digit number
Sheet No
This allows a complex piece of
equipment to be drawn on more
than one sheet whilst retaining
the same drawing number.
Again as an example, the fuel
gas system may be represented
on two drawings, PR-PD-210101 and PR-PD-2101-02.
Rev
This refers to the revision
number of the drawing. It is
most important that you ensure
you are working with the latest
revision of a drawing.
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Revision 3 means that the drawing has been
changed on at least two occasions since it was
approved for construction (Rev 0). The original
Revision 1 drawing will normally have a stamp on it
similar to the one illustrated in Figure 3. This stamp
was placed on the document by J.F.H. of POL on
the 18th of September. The stamp certifies the
document as a Master Document. ANY alterations
to the design MUST be incorporated into THIS
document.
Changes required to the Revision 1 drawing will fall
into two basic categories. They are :
•
major changes, and
•
minor changes
If a single major change is made to the drawing then
the whole drawing will be re-drawn. The Master
Document will then be re-issued as Revision 2 after
it has followed the same authorisation path as the
previous revision.
Revision changes are normally identified by a cloud
drawn around each alteration as shown in Figure
4.
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If a minor change is to be made then the change
will be made ONLY to the Master Document. After a
certain number of minor changes have been made (
usually six to each drawing ) the whole drawing will
be re-drawn. The drawing will then be re-issued as
Revision 2 after following the same authorisation
path as the previous revision.
Be aware that, during the construction phase, ALL
drawings may have had minor changes made
to them. The only place where a small number
of minor changes can be found is on the Master
Document.
After the construction phase has been completed,
all drawings are revised and designated as being As
Built drawings. These drawings indicate the actual
situation of the process as it has actually been built.
The As Built drawings are again subject to the
amendment and revision process outlined above.
True North and Platform
North
When you are working with Plot Plans you will come
across examples of true north and platform north.
North, South, East and West are called the
CARDINAL POINTS of the compass. Platforms and
processes are very seldom oriented in an exact line
with one of the cardinal points of the compass.
Because of this a Platform North is created which
is roughly equal to true North.
NOTES:
An item common to all drawings is a small section
which is commonly titled Notes. The Notes are
items of information which the design engineer has
identified as being important. They may explain a
small aspect of the drawing on which they are written,
or refer the reader to another drawing or manual.
The Notes should be studied with care as they can
be a useful source of essential information.
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Figure 5 illustrates a situation where a platform
complex is positioned 20° to the West of True North.
In general conversation on the platform, the Flare
Boom would be described as being on the North
end of the Drilling and Production Platform.
The true orientation of the platform is critical
when describing events to an outside party. As an
example; a man overboard is suspected of having
drifted due North of the Flare Boom in Figure 5. A
vessel looking for him would be unable to find him
if the reference was to Platform North. The 20°
error extended out to three miles from the platform
means that it is possible that the search could be
carried out a mile away from the actual direction in
which the man overboard is drifting !
The actual amount of error, as shown in Figure 5, is
usually only indicated on large scale plans.
More often the type of indication shown in Figure 6
is used to indicate Platform North.
NOTE:
All Figure numbers referred to from here onwards
are contained at the back of the Book 2.
Equipment Lists
Many drawings incorporate EQUIPMENT LISTS
to indicate the equipment which will be found on
the drawing. In Figure 7 the equipment list is from
a Plot Plan. We will look at Plot Plans in Section
Two, but for the moment you should note that in this
drawing:
Note that the Produced Water Coolers (H-2701A/B)
have the same numbers as the Third Stage Water
Pumps (P-2701 A/B). However the prefix letters ‘H’
& ‘P’ inform us that they are heat exchangers and
pumps respectively.
NOTE :
You may find that the prefix letter E is used in some
cases instead of H for heaters, exchangers and
coolers.
• all vessels are prefixed with the letter ‘V’
• all heat exchangers are prefixed with the
letter ‘H’
• all pumps are prefixed with the letter ‘P’
Figure 7 lists some of the equipment used in a
Separation Process. We can also establish that
the four digit serial numbers for equipment involved
with this separation process utilise the first two
digits to identify the system number, with the last
two digits providing the equipment number within
that system.
Figure 6
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Summary of Section 1
In this Section we looked at the various British Standards that provide specifications and
practices to be adopted for all Process Engineering Drawings.
We looked at the definitions of drawings and diagrams as described in BS 5070.
We have seen that all drawings :
• have a unique identification number
• have an identification title
• are subject to a revision process
We have seen how the engineers and draughtsmen
responsible for producing the drawing are identified,
and how a document progresses through the
revision process.
We have seen how changes may occur to the
process itself, WITHOUT all of the drawings in
circulation being amended to show the changes.
We have seen how the design engineer highlights critical items
of information with Notes to clarify and expand upon certain
aspects of the drawing.
We then looked at how platforms and process plants are oriented
towards a mythical compass point called Platform North. We
discussed the critical aspects of this orientation with regard to
passing on information to persons outwith the installation.
Finally we looked at Equipment Lists and discovered that quite
a lot of information can be collected from even the simplest of
lists.
Before moving on to the next Section try Test Yourself 1 and
then take some time to study the symbols contained in Book 2.
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Test Yourself 1
1. What type of equipment would you expect V-1601 to be ?
2. What British Standard would you refer to for graphic symbols for piping systems and plant ?
3 Describe the difference between the THREE types of drawings by completing the following statements.
a)
Plot and Elevation Drawings show:
b)
Process Flow Diagrams show:
c)
Piping and Instrument Diagrams show:
4. What is an As Built drawing ?
5. What method is normally used to identify changes made to a drawing when it has been revised
and re-issued ?
You will find the correct answer in Check Yourself 1 on Page 47.
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Process Engineering Drawings
Section 2 - Plot Plans and Elevation Drawings
Plot Plans are detailed maps which show the
location of all the main items of equipment on a
process system or platform. Elevation Drawings are
views of a process system or platform as seen from
a particular direction. Before looking at examples of
the two types of drawing we will take a brief look at
Modules and Module Identification.
Modules
To simplify the mechanism of locating items of
equipment most process systems are split into
MODULES. A Module is usually a physical area in
which a certain process or processes are carried
out. In the case of offshore platforms, individual
Modules will probably have been constructed
by different manufacturers, and even in different
countries, before being assembled on-site.
If you refer back to Figure 5 you will see the module
layout of an installation. It indicates that:
• D1 & D2 are drilling Modules
• P1 & P2 are process Modules
• P3 is the flare ( part of the process system )
• B1 & B2 are the interconnecting Bridges
• L1 & L2 are the accommodation modules
(living quarters)
You will note that there is a fairly logical system of
module identification employed in the letters used.
However, the numbers do not appear to follow any
specific logic.
Some installations use a simple module / equipment
location logic where, for instance, all identification
numbers and letters run in ascending order from
Platform North to South (top to bottom ) and from
Platform West to East (left to right). An example of
this would be where three booster pumps in a row,
running from west to east, are numbered P-0101A/
B/C.
Module identification varies from installation
to installation, with the module and equipment
numbering system often having no bearing on the
location of the Module. This situation often arises
because the individual Modules are designed and
built in different locations and are given different
numbers. Each Installation will therefore have a
unique Module numbering system.
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Scales
Elevation Drawings and Plot Plans are DRAWN TO
SCALE. This means that there is a definite
relationship between the sizes and distances shown
on the drawing, and the sizes and distances which
will be present in the real location.
The scale of a drawing will depend upon the
expected use. In the case of Plot Plans and Elevation
Drawings a scale ratio of 1:150 is normal.
The main thing to remember is to ALWAYS check
the scale of the drawing.
Elevations
Figure 8 is an Elevation Drawing for an offshore
platform.
In Elevation Drawings the platform is viewed from
the four cardinal points of the compass (North,
South, West and East) and where appropriate each
Module is often identified.
Elevation drawings are utilised to provide a scaled
view of the installation, which can be utilised in
conjunction with Plot Plans for identifying hazardous
areas ( zone classification ), escape routes, and
location of emergency equipment and facilities
(lifeboats, life rafts etc.).
• U1, U2 & U3 are the utilities modules
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In Figure 8 we can see the Southside of the UQ
platform (U1), accommodation module (L1), helideck
(L2), and the bridges (B1 + B2) which connect the
UQ platform to the Drilling / Production platform.
This type of information is important when we are new
to an installation as a lot of leg work can be avoided
by studying the Plot Plans, before setting out, to
locate a particular piece of plant / equipment.
This type of scale drawing provides a perspective
which will be useful in determining the relative size
and physical layout of equipment detailed in the
PFDs and P&IDs.
Plot Plans, as mentioned earlier, are extensively
used to identify escape routes and the location of
safety and emergency equipment.
Plot Plans
From the scale we can see that the Module is
approximately 30 metres wide and 82 metres long.
Test Yourself 2
By studying Figure 7, describe two alternative
routes, using platform cardinal points, from the inboard end of the HP Flare Drum to the Main Closed
Drain Vessel, naming all equipment passed on each
route.
If we now look at the right hand side of Figure 7, we
will see a list of all equipment contained within the
Main Deck Level of a Drilling / Production platform.
We now have to find out where the equipment is
positioned within the Module, and for this we need
a Plot Plan.
Figure 7 is a scale Plot Plan of Level 1 ( Deck
Level) of the Production Module and we can see
the location of the listed equipment.
By looking at the Plot Plan we can determine a
precise location of equipment e.g. in Figure 7 we
can see that the HP Flare Drum (V-1601) is located
in Module P1 in the north east corner of the main
deck (Level 1).
You will find the correct answer in Check
Yourself 2 on Page 46.
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Summary of Section 2
In this section we have taken a brief look at how complex process systems are
separated into Modules so that their location can be more easily identified. We
have seen that they are normally arranged in a logical sequence and that they are
arranged on different levels. We have also seen that specific locations within a
module are given by reference to Platform North.
We have seen how Elevation Drawings and Plot Plans are drawn to scale and that
they are oriented to Platform North.
We have discussed some of the uses to which Plot Plans and Elevation Drawings
are put, such as escape route identification, location of emergency and safety
equipment etc.
You should note that whereas Elevation Drawings and Plot Plans are drawn to
scale, Process Flow Diagrams and Piping and Instrument Diagrams are NOT
drawn to scale.
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Process Engineering Drawings
Section 3 - Process Flow Diagrams
Introduction
In this section we will be looking at Process Flow
Diagrams (PFD). The purpose of a PFD is to depict
all the essential parts of a process system in such
a way that they show the operation as clearly as
possible, without regard for the physical layout of the
items, their parts or connections. In other words, the
PFD Figure 9 may show the LP Gas Compressor
sitting above the 3rd stage separator. This has no
bearing whatsoever on its actual location, which
may well be alongside, or even in another module.
PFDs should be drawn so that the process sequence
is shown from left to right. Vertical orientation will
be dependent on the process, but it is normally
accepted that the natural separation qualities of gas
at the top, oil in the middle and water at the bottom,
are observed.
We will see that from the PFD we can discover a lot
of information about the installation. We will also see
that, with a little bit of deduction, we can discover
why the process is designed the way it is.
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Before we take a look at the PFD we should remind
ourselves of what we hope to see on a process flow
diagram. We have seen that the designer has a very
tight set of design criteria to work with, so we should
be able to see how he intends to fulfil them in the
design. We should therefore expect to see :
On the crude oil side of the process locate and
identify:
• the main items of equipment which will be used
• the Separators
• the main points at which the process is controlled
• the Oil Coolers
• the changes which are made to the reservoir
fluids as they pass through the process
• the Oil Booster Pumps
Lay Figure 9 out flat on a table, in a good light, so
that you can scan across the whole diagram as you
read the rest of this Section.
I will take you through this PFD of the separation
system step by step, but first of all take a few
minutes to study the diagram and see if you can
work out the basic flow for yourself. It may look a
little bit complicated if you have not used a PFD
before, but don’t worry.
• the Typical Well Flowlines
• the Test and Production Manifolds
• the Oil Metering Package
• the Oil Export Pumps
• the Pig Launcher
• the Subsea Pipeline
To begin with, ignore the Mass Balance Data
information table at the foot of the page, we will have
a look at this in some detail later. For the moment,
just look at the diagram and identify the main items
of process equipment which will be used.
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On the gas processing side of the process locate
and identify:
Activity 1
• the LP ( Low Pressure ) Compressor Suction
Coolers
• the LP Compressor Suction Drum
• the LP Gas Compressors
• the IP (Interstage Pressure ) Compressor
Suction Coolers
• the IP Compressor Suction Drum
Manifolds
The next items of equipment we come to are
the TEST MANIFOLD and the PRODUCTION
MANIFOLD.
Use high-lighting pens and bring the PFD alive
by tracing the flows for the oil, gas and water,
and colouring them as appropriate. (Yellow for
gas, red / pink for oil, and blue for water).
Over the planned years of production we will have
to test the wells to see how much oil each well is
producing. As a general rule, one of the wells will be
on test at all times.
You will now have a coloured diagram which
will help identify the flow lines more easily as
we work through the separation process.
You can see that each well is connected to both
the Test Manifold and the Production Manifold.
By changing over the valves, each well can be
temporarily diverted through the Test Manifold into
the Test Separator.
• the IP Gas Compressors
Test Separators
Wells
The wellheads are not depicted on this diagram, however we will be looking at wellheads later when we look
at P&IDs. The well flowline choke valve and divertor
valves are indicated on this diagram.
In order that you begin to get a feel for reading
process flow diagrams, we will utilise a Test
Yourself approach periodically throughout this unit.
This first one on the test separator should help get
you started if you are unfamiliar with PFDs, and test
your knowledge if you have used PFDs in the past.
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Test Yourself 3
Take a moment or two to jot down some information about the Test Separator operation
from the information on the PFD.
1. Where is the gas from the test separator normally routed to ?
2 Where is the oil normally routed to ?
Now, if you have answered all these questions
correctly, you will know a lot about the operating
modes of the test separator without having read any
manual.
As we progress through this unit you will be able to
learn even more from reading a drawing.
Before moving on make sure that you are familiar
with the workings of the Test Separator, because
the next section is another Test Yourself which will
teach you the Production Separation part of the
process.
3. What type of pump is P-0201 Test Separator Oil Pump and what purpose does it serve ?
4. What type of pump is P-0202 Test Separator Water Pump and what purpose does it serve ?
5. Assuming you have figured out the reason for the pumps, what will we do with the gas in
these circumstances ?
6. What can you glean from the information given about the start-up fuel gas line ?
7. How is the separator pressure normally controlled ?
8. The normal operating pressure is ............... bara. How did you obtain this information ?
9. How is the oil level controlled ?
10. How is the interface level controlled ?
You will find the correct answers in Check Yourself 3 on Page 49
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Test Yourself 4
The main production system is very similar to the Test Separator System. This Test Yourself will actually teach you the workings of the
Separation and Oil Export Systems.
1.
How many stages of separation are there, and what is the operating pressure for each stage ?
7.
What type of compressors are the LP and IP compressors and how are they driven ?
2.
Where is the gas from each separator routed to during normal operations ?
8.
What is the purpose of the LP and IP compressors ?
3.
What type of cooler is utilised upstream of the oil booster pumps, and what medium is used for
cooling ?
9.
How is the level in the 3rd stage separator controlled ?
4.
How many Oil Booster Pumps are there and what are their serial numbers ?
5.
Is there one oil export recycle cooler, or is there one dedicated to each export pump ?
6.
What type of cooler serves the export pump recycle and what is the medium used for cooling ?
10. Describe all the controlling actions that would inevitably
take place to prevent any process trips, should the oil
flow into the 3rd stage separator suddenly fall off.
You will find the correct answers in Check Yourself 4 on Page 50.
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After completing Test Yourself 4 you should have
a good feel for the main flows in the Production
Separation process.
Pig Launcher
We can see that the crude oil pipeline is fitted with PIG
LAUNCHER MO-0301. Pigs are items of equipment
which are pushed through the pipeline to keep the
pipeline clean. Crude oil often contains wax which
will tend to stick to the walls of the pipeline where
it is coolest. Pigs are therefore launched into the
pipeline on a regular basis to clean the pipeline.
Crude Oil Process Flow
Before moving on, have a look at the overall picture
of the Crude Oil Process Flow and ask yourself:
• Why has the designer chosen to have three
production separators? Could he have had a
single large separator? Could he have chosen
to have two separators or maybe even four
separators? Why a single train and not two trains
in parallel operation for increased reliability?
• Why has the designer chosen to have three
Crude Oil Booster and Export Pumps? Could
he have made do with one or two pumps? Could
he have chosen to have four pumps, or maybe
even five pumps?
There is no definite answer to these questions but a
realistic answer would be that the designer’s choice
of three separators and three pumps provides
a compromise between cost effectiveness, and
flexibility and reliability.
Test
Yourself 5
Study the PFD and state what facility the
designer has provided which makes it
unnecessary to take a total production
shutdown if the 1st stage separator becomes
inoperable for any reason.
If either the 2nd or 3rd stage production separators
become inoperable for any reason, there will have
to be a total production shutdown. Separators are
reliable items of equipment. Therefore, unless there
is a total structural failure, the most likely problems
will arise from the control systems. The control
systems can usually be repaired in a day or even
less.
This indicates that it would not be cost effective to
have sparing of separator capacity, as the reliability
factor is high.
You will find the correct answers in Check
Yourself 5 on Page 51.
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Crude Oil Pumps
The booster and export pumps will require more
frequent maintenance, therefore by having three
pumps, two can be operating with the third on
standby. The standby pump is ready to replace any
one of the other pumps in the event of failure. This
set-up is also often referred to as sparing.
The cost effectiveness of pump sparing is achieved
by the increased flexibility and reliability provided.
Gas Compression
We know, in this instance, that we have a large
amount of gas because of the gas / oil ratio of the
crude oil leaving the reservoir.
If it were only a small amount of gas it would not be
cost effective to provide gas treatment and
compression facilities to export the gas, especially
if it can be used within the process as a source of
fuel gas.
The gas from the Production Separators and the Test
Separator, as we saw earlier, join together before
entering the HP Compressor Suction Coolers.
You should now lay out Figure 10 which is the
PFD for Gas Treatment and Compression.
The gas is cooled by cooling medium as it passes
through the suction coolers. Suction coolers in gas
compression systems are provided for two
reasons :
•
Cooling of the gas prior to entering the gas
compressor. Gas compression causes a large
temperature increase in the gas, therefore to
improve the efficiency of the compressor, the
gas is cooled prior to entering the suction.
•
Removal of heavier ends of hydrocarbons,
often referred to as gas condensate or natural
gas liquids (NGL). These condense from the
gas as a result of the cooling process and are
then knocked out in the suction knock out
drum.
We will now follow the flow through the remainder of
the gas treatment and compression system. Once
again I will incorporate a Test Yourself philosophy
throughout this session.
The removal of these liquids serves two purposes :
•
We do not want liquids entering the gas
compressors. Liquids, as you may already
know, are in-compressible, and would
inevitably cause serious damage if they
inadvertently entered the compressor.
•
These valuable condensates / NGLs will
naturally separate from the gas as a result
of cooling, therefore they are economic to
produce and spike back into the crude oil for
export.
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Test Yourself 6
1.
The PFD indicates that there are four HP Compressor Suction Coolers (H-1103A-D),
yet there are only two HP Compressor Suction Drums (V-1103A/B) and two HP
Compressors C-1103A/B. What do you deduce from this information ?
2.
What type of heat exchanger are the coolers on the gas treatment and
compression system ?
In this unit I have asked you to Test Yourself as
much as possible as part of the learning process.
This is intended to help you become literate in
reading drawings as quickly as possible.
The method of learning by doing is most
appropriate in this particular subject as, when you
look at drawings you should be asking yourself a
whole series of questions such as :
• Why has the designer chosen this particular
equipment ?
• What is the function of this equipment ?
3.
What type of compressors are the HP and Export Gas Compressors ?
4.
What process is carried out in the gas treatment system ( System -13) ?
• Why is it located at this point in the process and
not somewhere else ?
5.
Can you spot anything unusual regarding the export compressor suction cooling facility ?
• What will happen to that controller if the pressure /
level / temperature / flow set point rises ?
• Why is it there at all ?
• What will happen to that controller if the set point
falls ?
• Why has the designer chosen two of them :
why not three or one ?
You will find the correct answers in Check Yourself 6 on Page 51.
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As you work your way through the drawings you
will find that the questions are endless and that the
answers are invariably supplied by the information
provided.
The two main reasons for working out the answers
for yourself are:
•
Satisfaction
•
Long term knowledge
There is great satisfaction in being able to figure out
from just a few drawings, why a process has been
designed the way it has. With practice and regular
application, even the most complicated processes
become understandable.
The long term knowledge comes from working it out
for yourself, instead of getting someone else to tell
you. If you can work something out once you can do
it again, therefore every time you work out an answer
for yourself ( providing it is the right answer) you are
increasing your knowledge PERMANENTLY.
One word of warning before you carry on. ALWAYS
MAKE SURE THAT WHAT YOU HAVE WORKED
OUT IS CORRECT. Never leap in and try to operate
a process on the basis that you have ‘calculated’
how it works.
We will now move on to look at the information
supplied in the tables that are provided on a PFD.
Mass Balance
The table on the PFD appears to be just a mass
of numbers. However, when you have cracked the
code, you will find that it is actually packed full of
useful information. The table represents the Mass
Balance ( often called the Material Balance ) of
the process.
The Mass Balance sheet accounts for the flow of
fluids as it passes through the process. In other
words it is a chart which shows us the BALANCE
between what comes into the process and what
leaves the process.
We will take a look at the column on the left hand
side before we go any further. I will give you a brief
explanation of what each title means. They are :
• STREAM NUMBER - if you look at the flow diagram
you will see small diamond shapes with numbers
inside. These are the Stream Numbers to show
you at what point in the process the mass balance
data refers to.
• PRESSURE BARA - this is the pressure, in Bar
Absolute, at which the designer expects the process
to operate. (NOTE : Most Process Flow Diagrams
and Mass Balance Diagrams are explained in
terms of absolute pressure. Remember to correct
for this when you are operating the process !
(1 ATMS = 1.01325 bar).
• TEMPERATURE - this is the temperature, in
degrees Celsius, at which the designer expects
the process to operate.
• MASS FLOW - this is the total fluid flow measured
in Tonnes / hr.
• LIQUID MW (Dry) - this states Molecular Weight of
the liquids. The reference to Dry, infers that there
is no water content.
• VAPOUR MW - this states the Molecular Weight of
the vapours.
• ENTHALPY - this is a term used to define the
energy of the fluid. Enthalpy is calculated from the
temperature, pressure and composition. As it is
quite an involved calculation it is usually performed
by a computer. It is used as a basis for designing
the size of compressors and heat exchangers.
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• LIQUID DENSITY - this is indicated in kg/m3
COMPOSITION MOL%
• VAPOUR DENSITY - this is also indicated in
kg/m3
This section of the Mass Balance sheet gives a breakdown of the
various components which make up the process fluids. I will not
go through all of them but I will give you a brief description and
explain a few significant points which we can see in Stream 1 :
• LIQUID FLOWRATE - this is temperature and
pressure compensated, and indicated in m3/hr.
• STANDARD LIQUID FLOWRATE - this is measured
in Barrels Per Day (BPD)
• CO2 (CARBON DIOXIDE) - carbon dioxide can be corrosive if
present in large amounts, particularly if it dissolves in water to
form carbonic acid.
• VAPOUR FLOWRATE - this is temperature and
pressure compensated, and indicated in m3/hr.
• N2 (NITROGEN) - is an inert gas and not present in any
significant quantity.
• STANDARD VAPOUR FLOWRATE - this is
measured in Standard Cubic Metres / Hour (sm3/hr)
and Million Standard Cubic Feet Day (mmscfd)
• C1 (METHANE) - the Gas / Oil Ratio is high as the methane
content is high at almost 32% of the total mass flow.
• Z Factor - this is a compressibility factor used for
gas measurement calculations
• VAPOUR MOL FRACTION - this is the fraction
of vapour in the fluid (1.0 = all vapour & 0.0 = all
liquid)
NOTE :
C1 is an abbreviated form of C1H4 which is the chemical formula
for methane.
The remaining hydrocarbon composition is as follows :
• C2H6 - ethane
• C3H8 - propane
• iC4H10 - iso-butane
nC4H10 - normal-butane
• iC5H12 - iso-pentane
nC5H12 - normal-pentane
• nC6H14 - normal-hexane
• C7+ - this section refers to all crude oil components which are
heavier than heptane.
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• H2O (WATER) - you can see that there is an
arbitrary figure given for the water content, as it
is not expected that there will be any produced
water content in the oil in year 1. The saturated
water content of the gas streams is more
realistic, as the gas from the reservoir will always
contain entrained free water. You should note,
by referring to Figure 10, that there is 0.00%
water content indicated from stream number 26
through to stream number 29. These streams are
downstream of the gas dehydration system where
all free water will be removed from the gas.
Now that I’ve explained the contents of Figures 9
and 10, you should be able to work out a few things
for yourself. It is much more difficult, but much more
interesting, than just having the sheets explained to
you.
• Total flowrate given in kilogram mol per hour
(kgmol/h) is calculated from the mol% of each
component. You will note that every gram is
accounted for as it flows through the process. In
other words the mass flows are ‘balanced’.
• PPM (mol) H2S - this is the hydrogen sulphide
content of the gas. Again as with carbon dioxide,
hydrogen sulphide can be very corrosive if
dissolved in water, as it will form sulphuric acid.
• Free water flowrate - calculated at standard
temperature and pressure in m3/h.
• Free water flowrate - expressed in kg/h. Again
note that the free water content is not given
downstream of the gas dehydration system.
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Test Yourself 7
1. (a) What are the temperatures at Stream number 11 and Stream number 13?
(b) What has caused this temperature change ?
2. There is a temperature and pressure change between
Stream number 9 and Stream number 10, what has caused
this change ?
3. Why is there a temperature difference between Stream
number 10 and Stream number 11 ?
4. What has caused the temperature drop between Stream
number 26B and Stream number 26D ?
5. (a) At what point in the process is the largest amount of propane removed ?
(b) Why is this the case ?
6. A Process Flow Diagram incorporates a Mass Balance sheet.
List SIX items of information that are provided for the various
points in the process as identified by the specific Stream
No.
You will find the correct answers in Check Yourself 7 on Page 52
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Summary of Section 3
Spend some time looking at Figures 9 and 10 until you are familiar with them and their relationship with each other. If you can understand Mass Balance
Data, you are well on the way to an overall understanding of the Process to which it refers.
In this Section we have seen that Process Flow Diagrams can reveal a wealth of information.
From this information we could work out WHY the designer chose to design the process system as depicted on the Process Flow Diagram, and HOW
the process should operate.
The process fluid from the wells is a known factor, and to meet the known specification for oil and gas export into the pipelines are the process
objectives. The designer then has to design the process and equipment required to meet these objectives.
We looked at the crude oil side of the process and identified the main items of equipment. We then identified the gas processing equipment.
I then asked you to bring the drawing “alive” by highlighting the various flows. This helped you to readily identify the gas, oil, and water systems.
We used a Test Yourself approach to learn how to read a process flow diagram, by answering various questions regarding the operation of the test
and production separator systems.
I then went on to explain the Mass Balance sheet, to give you an insight into how to use the information provided, to help you to understand better how
the process is expected to operate.
In the next section we will look at Piping and Instrument Diagrams. We will be asking a lot of WHY ? questions, and trying to find out the answers from
the drawings.
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Process Engineering Drawings
Section 4 - Piping and Instrument Diagrams
Every Day Use for Operators
The Ground Rules for P&IDs
Piping and Instrument Diagrams (P&IDs) are the
key tool for anyone who is trying to understand
the equipment used in a process operation. They
are in every day use by production operators, who
will use them to identify isolation valves, and drain,
purge and vent points to prepare equipment for
maintenance.
First of all you must appreciate that the diagrams are
graphical representations of the piping, equipment
and instrumentation. The symbols used will therefore
be a representation rather than an illustration. As
an example, the symbol for a compressor will be
the same all the way through the system. A small
centrifugal compressor used to supply instrument
air will have the same symbol as a large centrifugal
compressor used to compress a hundred million
cubic feet of gas per day.
In this Section we will look at various P&IDs from
our installation so that you can learn how to read
and interpret the information provided, and also
use them to plan preparations for maintenance on
specific equipment.
We will start with a simple P&ID of the Wellheads
and work our way through the process system to
the more complex P&ID of the Separation System.
At the end of this section you will be able to look at
any P&ID and have a good chance of understanding
why the items of equipment have been selected.
Before we actually look at a P&ID, I want to explain
a few of the ‘ground rules’ which apply to all P&IDs.
Not understanding these rules makes life extremely
difficult.
Petroleum Open Learning
• an emergency shutdown valve (SD 01028)
• a density transmitter (DT 01189)
• a corrosion probe (CP 01031)
• a corrosion coupon (CC 01032)
• a pipe reducer (18” x 12”)
• a flow element (FE 01029)
The second rule to remember is that the distances
on the drawings do not represent the actual distance
on the process. As an example, the distances
between three valves on a P&ID may be equal at
one centimetre. The actual situation may be that the
middle valve is one metre from one valve and 10
metres from the other valve.
• 8” LV by-pass line
The third rule is most important when you are trying
to match up a P&ID with the real process. As you
walk through the process you should always find that
the pipes, valves, equipment and instruments are in
EXACTLY the same position as shown on the P&ID.
Imagine you are checking the flow of crude oil from
a separator. The oil outlet line is shown on the P&ID
(Figure 12) leaving the bottom of the separator and
then incorporating the following equipment:
• a level control valve (LV 01016)
• a butterfly valve
• a pipe reducer (12” x 8”)
• 3/4” drain tapping
• a pipe reducer (8” x 18”)
• a butterfly valve
• a non-return valve (NRV)
The line then leaves this P&ID and will be picked
up on the P&ID number noted in the arrow shaped
box.
You should ALWAYS find, when you walk the
lines, that the position of equipment, pipes and
instrumentation are identical, relative to each other,
between the P&ID and the actual process.
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The reason for this is that the process is designed
with equipment, pipes, valves and instruments all
positioned for a purpose. If a valve or instrument
was moved the process may be adversely affected.
One final item before we start is the references we
will see on the P&IDs to the Emergency Shutdown
(SD) System and Process Logic (PL) System.
The ESD system, which is indicated on our P&IDs
as SD, (although it is also common to use the
term ESD), is the system of switches which will
shut the process down in the event of any process
emergency. An example of a situation which would
cause the ESD system to activate is a high-high
pressure in a separator. If the high-high pressure
switch is activated it means that the pressure is
extremely high in the separator. If the process is not
shutdown, this over-pressurisation may result in an
explosion and fire. The ESD system will shutdown
the process before the pressure gets any higher.
The Process Logic (PL) system, sometimes referred
to as Process Logic Control (PLC), ensures that
the process is operated correctly. An example of a
situation which would cause a PL system to activate,
is a pump suction valve not indicating open. If the
pump were to be started with the suction valve
closed, then damage to the pump could occur. This
is a process problem rather than an emergency
problem. To prevent damage to the pump the PL
system will prevent the pump from being started.
I will give a brief explanation of process logic
systems as they occur in this section.
Having now explained the basic ground rules we will
start with a simple P&ID. Take at least ten minutes
to look at Figure 11 and use your knowledge of the
installation, so far, to work out what the drawing
represents
Wellheads
We will start by looking at the title of Figure 11 which
is in the bottom right hand corner. The drawing is
PIPING AND INSTRUMENT DIAGRAM - TOPSIDE
PRODUCTION WELLHEAD TYPICAL
If you look at Note 1 you will see that this drawing
is typical of 28 production wells. We already know
from the Process Flow Diagram that our installation
has 28 Wellheads. This tells us that what we are now
looking at is one of the 28 production wellheads.
Before we look at this P&ID in some detail, I would
like you to note that the Wellhead Control Panel
JP-0101 is identified as a seller system and that
reference must be made to the relevant seller
drawing. This often happens on P&IDs as the
manufacturers of certain self-contained items of
equipment will supply their own P&IDs. As a general
rule they are held in a separate file with all of the
other information on the equipment.
A prime example of such a system is where a
wellhead control panel is purchased and provided
on site as a skid mounted package. The wellheads
P&ID shows the wellhead control panel as a box
and refers the reader to See Seller Drg No. P0176D0002.
I will now explain some of the detail provided in this
P&ID, and then we will revert to a Teach Yourself
method once again.
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Starting with the downhole valve (DHV T0102) we
can deduce that this is a hydraulically operated ball
valve. (Note the symbol for hydraulic control lines.)
This valve is the emergency shutdown valve for the
well and is positioned below the sea bed.
The valve is held open by hydraulic pressure. If the
surface section of the wellhead was destroyed by
fire, or damaged by some other catastrophic incident,
then the hydraulic pressure would fail and the valve
would close and stop the well from flowing.
The hydraulic line comes from a box marked
WELLHEAD CONTROL PANEL and INDIVIDUAL
WELL CONTROL which indicates that there is a
panel for each wellhead.
We can see that the DHV hydraulic line leaving the
wellhead panel is fitted with a panel mounted
pressure indicator (PI T0102B) and handswitch
(HS T0102). There is another pressure indicator
(PI T0102A) fitted on the control line downstream
of a tie-in line with NOTE 4 written above it. This
note tells us that this is a wireline control connection
point (690 barg).
NOTE :
The instrument tag numbering system used in
this P&ID, taking PI T0102B as an example, is as
follows:
PI Pressure Indicator
T
Topsides well
01 System number 01
02 Unique identification number for this
instrument
B Used to indicate that there is at least one
other PI with the same number indicating
this pressure
The letter T for topsides infers that there must be
subsea wells routed to this installation. The letter
S would be used instead of T for subsea well tag
numbers.
If you locate the hydraulic line to the master valve
(MV T0103), you should note that this also has a
wireline control connection point (414 barg). These
connection points are used by the wireline crew
to allow them to maintain control of the hydraulic
supply to the DHV and master valve, whilst carrying
out wireline operations in the well. This prevents
ESD signals closing the valves, resulting in the wire
being cut. Obviously if there is a real emergency
situation, then the wireline crew would be instructed
to close the valves regardless.
To the bottom right of the wellhead control panel there
is a second box marked WELLHEAD HYDRAULIC
POWER GENERATION SYSTEM.
Note that there are two hydraulic lines leaving this
box and entering the wellhead control panel. This
indicates that there are two systems of hydraulic
pressure provided and this is confirmed by noting
that the DHV is supplied from the 690 barg system
and the master valve is supplied from the 414 barg
system. The production wing valve (PWV T0109)
and the service wing valve (SWV T0107) will also
be supplied by the 414 barg system. The higher
hydraulic pressure is provided to the DHV to ensure
it can operate against the higher well pressures
encountered at the depth at which it is located.
If you look at the alarms to the right of the wellhead
control panel you will see that one of them is titled
hydraulic skid group alarm (XA 01181). You will
note that this is the same instrument symbol as the
other specific alarms and signals coming from the
panel. This symbol tells us that the alarm/signal is
displayed in the CCR.
A group alarm, which is also referred to as a
common alarm, means that a number of different
alarms will activate a single alarm. In this case each
hydraulic power unit will have a low pressure switch
and a high pressure switch on each of the two
hydraulic outputs, and a low level switch on each
hydraulic fluid reservoir. If any of these five switches
are activated then the group alarm will be activated
in the control room.
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Group or common alarms are often run from small
packages. In the design stage the designer may not
know how many alarms the manufacturer will mount
on the package. To simplify matters the designer
installs a connection to a common alarm.
Coming into the wellhead control panel are four
signals which originate at boxes marked :
SD - from ESD level 3&4 fire and gas in wellhead
area, will be a direct input from the ESD system to
shut-in the well.
SD - from ESD level 1&2 will be a direct input from
the ESD system to shut-in the well due to a process
trip.
• HIPS
Take a few moments to think about two different ESD
inputs. One is a fire or gas leak in the wellheads area,
and the second could be something like a high-high
pressure in one of the crude oil separators.
• SD - from ESD level 3&4 fire and gas in
wellhead area
What do you think would be a suitable response to
the two emergencies ?
• DCS
• SD - from ESD Ievel 1&2
These are all signals being sent to the wellhead
panel to carry out certain shutdown functions which
I will now explain.
In the case of the high high level, by simply closing
the wing valves we would be able to prevent more oil
flowing into the separators. This would be a suitable
response to such an emergency.
DCS is input from the Distributed Control System
which is the production control system, and this will
be a command from the CCR operator to close a
valve on this particular well.
In the case of a fire in the well heads area, we would
want a much more effective response. In this case
we would almost certainly wish to close the down
hole valve, the master valve and the wing valve.
HIPS is the High Integrity Protection System which
is normally a 2 out of 3 voting high high pressure or
high high level shutdown device. This signal is
normally input directly to the panel to ensure that
the well is shut-in immediately.
In both cases we have shut off the flow of oil from
the wells.
If we now turn our attention back to the wellhead
once again and look at the right hand side of the
well, we can see two pressure instruments from the
95/8” annulus, PIA T0104 which is a high pressure
alarm (denoted by the letter H beside the symbol)
that will indicate in the CCR, and PI T0105, which is
panel mounted.
The production tubing hangs inside the production
casing all the way to the bottom of the well. The 95/8”
annulus is the space between the production casing
and the production tubing. Pressure will build up
in the 95/8” annulus if the production tubing starts
to leak. Pressure indicator PIA T0104 will pick up
any change in pressure in the annular space, and
alarm at the CCR when the setpoint is reached and
indication of the pressure can be monitored on PI
T0105.
On the left hand side of the well we can see that there
are two pressure indicators. They are PI T0119 and
PI T0121, which are locally mounted. You should
notice that PI T0119 comes off the 133/8” annulus
of the wellhead and P1 T0121 comes off the 185/8”
annulus. Again these devices are provided to give
early indication of pressure communication between
the separate annular spaces.
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Petroleum Open Learning
If we return to the wellhead, we can see that the oil
passes through a manual valve and then the master
valve MV T01013. The manual valve is called the
lower manual master valve. The upper valve is
usually referred to as either the upper master valve
or the hydraulic master valve.
Theoretically MV T01013 is the valve which will
isolate the wellhead from the reservoir in all but the
most severe emergencies. The manually operated
lower master valve is installed so that the hydraulic
master valve can be serviced, and to ensure that
the wellhead can be isolated manually if required.
MV T01013 is shown as having two switches
attached to the valve stem. They are :
• ZSO T0103A which goes to ZIO T0103
• ZSC T0103A which goes to ZIC T0103
The switches are activated by the movement of the
valve as it opens or closes. ZIO T0103 indicates
when the valve is open and ZIC T0103 indicates
when the valve is closed. These signals are sent to
the CCR.
Located on the tubing above MV T01013 is the
wellhead pressure indication devices, which include
a panel mounted PI, a local wireline panel mounted
PI and a pressure indication to the CCR.
After passing through MV T01013 the oil flows into a
cross piece where it branches into three lines.
The left hand branch is routed to the service header
via the service wing valve SWV T0107.
The right hand take-off is the main flow line from the
wellhead. The well fluids flow through the hydraulically operated production wing valve PWV T0109
which is fitted with open and closed indicators similar to the ones fitted to the hydraulic master valve.
Incorporated in the service header is a kill fluid
line from the cement unit, which allows mud to be
pumped into the well in order to kill the well and
stop it flowing. In this instance, to kill the well would
involve pumping mud into the production tubing
and
forcing the oil back into the reservoir.
The following instruments and valves are provided
on the flowline downstream of the production wing
valve :
Other facilities on the service header are :
• Corrosion coupon CC T0110.
• Crossover connections to the subsea wells and
other topsides wells. As all the well DHVs will
require to have the pressure equalised across
them in order to be opened, this facility to
crossover will be required if any well has been
depressurised above the DHV.
• High High pressure switch PEA T0123 routed
direct to the ESD system.
• Depressurisation facility to the HP flare header.
• Erosion probe EP T0118.
• Corrosion probe CP T0111.
• Low Low pressure switch PSLL T0120 which is
routed to the wellhead panel, where it is indicated
on PALL T0120B and from there to the CCR via
PALL T0120A.
• Drain facility to the closed drain header.
• 95/8” annulus depressurisation facility.
The vertical branch is to the swab valve which
provides wireline access to the well.
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• Flowline choke valve HV T0112 which is an
electric motor operated valve. You will note that
this valve is operated by a hand switch located in
the CCR which can be over-ridden by a wellhead
shutdown signal from the wellhead control panel
via the DCS. You should also note that there is a
closed limit switch (ZSC T0112) which will prevent
the well valves from being opened until the choke
valve is indicated as being closed.
• Local pressure indication PI T0113.
• High High pressure switch PSHH T0114 routed
to the wellhead control panel where it initiates a
well shutdown signal and is indicated on PAHH
T0114B. This signal is also indicated in the CCR
by PAHH T0114A.
• Low Low pressure switch PSLL T0115 routed to
the wellhead control panel where it initiates a
well shutdown signal and is indicated on PALL
T0115B. This signal is also indicated in the CCR
by PALL T0115A.
NOTE :
PSHH T0114 and PSLL T0115 are fitted at this
location so that they can measure the pressure of
the flow line downstream of the flowline choke valve.
If the pressure rises too high at this point (e.g. 205
barg ) or too low ( e.g. 5 barg ) this would indicate
that there is a major problem with the flowline.
• Temperature indicating alarm switch TIA T0116
which will indicate a high temperature alarm
signal in the CCR.
• Flowline isolation valve PT 003.
Please take the time to make sure that you are fully
familiar with Figure 11, and my explanations, as we
will now change back to the Test Yourself method
once again.
Using Figures 12,13,14 and 15, I will ask a number
of questions and you should use your knowledge
and experience to work out the answers. You also
have the information contained within Book 2 to
refer to as necessary.
Separation
• Drain line to closed drain header via a ball valve
and a globe valve.
Figure 12 is a P&ID of the first stage production
separator V-0101. Take your time and study the
general layout so that you are familiar with the main
flows.
The flowline can now be diverted into either the
production manifold, via a non return valve (NRV)
and a divertor valve HV T0125, or to the test manifold,
via a NRV and a divertor valve HV T0126.
You should be fairly familiar with this installation’s
process by now as you have already covered it
earlier in this unit in the Process Flow Diagrams
section.
You may come across the term header as an
alternative to manifold.
We have now managed to work our way through a
fairly complicated P&ID. I explained each detail as
we went along.
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Test Yourself 8
1. V-0101 is a
2. What does the symbol
01004 represent?
. phase separator
5. From the information provided on the P&ID, can you determine
why the upstream valve is locked closed on PSV 01007C, and
not the downstream valve ?
on the separator inlet valve SDV
3. What does the line number and the piping symbol tell you about
the line from the fuel gas knock-out drum V-1501 ?
6. Describe the type and function of instrument PEA 01018
located on the top of the vessel.
7. With reference to PV 01023 on the gas outlet line :
(a) What purpose does it serve ?
4. There are three PSVs on top of V-0101. Why has one of them
(PSV 01007C) got the upstream valve closed ?
(b) How is it controlled ?
(c) How will the operators in the CCR know that it is open ?
continued...
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Petroleum Open Learning
Test Yourself 8 continued
8. How is the separator pressure controlled ?
12. What level is LICA 01013 controlling, and where would you expect to
find LCV 01013?
9. During a total platform maintenance shutdown we have the test
separator full of nitrogen and we would like to route this nitrogen
direct into V-0101. From the information provided on this P&ID
and the wellhead P&ID ( Figure 11 ), can this be done and if so
how, and if it can’t be done, why not ?
13. There is a High Integrity Protection System ( HIPS ) incorporated within
the separator instrumentation, can you identify it ?
10. What level will be indicated by LG 01012 ?
14. What type of meter is used to measure the oil flow from the separator ?
15. What type of instrument is DT 01189 which is located on the oil outlet
line, and what purpose does it serve ?
11. What is the purpose of LEA 01015?
You will find the correct answer in Check Yourself 8 on Page 53
continued...
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Petroleum Open Learning
Oil Booster Pumps
Figure 13 is a P&ID of the oil booster pumps P0101A/B/C. Again take your time and study the
general layout so that you become familiar with the
main flows.
We will again use the Test Yourself approach to
learning about this system by using the P&ID as the
source of information.
Test Yourself 9
1. List the types of valves that are used for the booster pump suction and suction valve
bypass line.
Suction Valves
Bypass Valves
2. What is the piece of equipment on the pump suction line downstream of the suction
valves ?
3. What instrumentation protects the pump from pumping against a closed discharge valve ?
4. Are the booster pumps operating in series or in parallel operation ?
continued...
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Petroleum Open Learning
Test Yourself 9 (cont’d)
5. There is some ancillary equipment connected to P 0101 A, that have
equipment identification numbers 0105A. What vital part of the pump
operation does this equipment support?
6. What instrument protects the pump from low discharge pressure ?
7. What P&ID would you refer to for more information on how the cooling
medium system ties into the crude oil booster pumps ?
9. What is the insulation class on the pump suction and
discharge lines ?
10. Can you figure out why there is no need for a thermal
relief facility (PSV) to be provided for the booster pumps.
In other words, if the suction and discharge valves were
closed and there was a fire in the area of the booster
pumps what facility would prevent over pressurisation of
the pipework ?
8. What are the design parameters for the booster pumps ?
You will find the correct answer in Check Yourself 9 on page 54
continued...
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Petroleum Open Learning
Gas Compression
Figures 14 & 15 are P&IDs of a LP Gas Compression
train. As with the previous Test Yourself exercises,
you should take some time to study the general
layout and familiarise yourself with the main flows.
Test Yourself 10
1. Using the information provided on Figures 14 &15, give a brief description of the gas flow
from the 3rd stage separator V-0103 to the IP compressor suction cooler H-102A.
2. With reference to suction cooler H-1101 A, which of the following statements is correct:
(a) If there was a tube rupture the gas would pass into the shell side of the cooler and contaminate the cooling medium system.
(b) If there was a tube rupture the cooling medium would pass into the tube side of the cooler and contaminate the gas compression system.
3. How is the temperature of the gas to the compressor suction controlled ?
continued...
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Petroleum Open Learning
Test Yourself 10 (cont)
4. XV 12150A controls the
. pressure to the
compressor. It also controls the pressure of the
5. What prevents the compressor suction valves from being
opened with a high ∆ p across them and how is this achieved ?
6. What type of insulation is applied to the suction drum V-1101A ?
7. Give a brief description of the operation of the suction drum
condensate level control and flow.
8. There is a line from the LP condensate pump P-1101A to the
atmospheric vent header that incorporates PEA 11441, RO 11442
and a valve VA 005. What is this line for and what is the function of
these facilities provided on the line ?
9. Would you obtain a start permissive if the compressor recycle valve
was closed ? Give a brief explanation of your answer.
10. What is the purpose of XV 11033 on the discharge side of the
compressor.
You will find the correct answer in Check Yourself 10 on Page 55.
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Summary of Section 4
In this Section we have seen how Piping and Instrument Diagrams can be interpreted
to reveal a wealth of information about the process and plant utilised for a specific
operation.
We can see how the design engineer expects to achieve his objectives by looking at
the equipment, plant and control systems he has incorporated within the process.
Understanding what the design objectives are goes a long way to understanding how
the process operates.
We must however, never forget the importance of the hands on approach to learning
the process and remember that reading and gaining knowledge from the P&IDs plays
a major part in the learning process, but only if used in conjunction with the practical
application.
Book 2 contains several P&IDs, some of which we have not used in this unit. I
recommend that you take time to study and make yourself familiar with the detailed
information provided on all the P&IDs contained in this unit, as they are all potential
sources for future examination questions.
You should pay particular attention to the symbols and abbreviations illustrated in
Section 1 and practice identifying them and drawing the symbols. Another useful
exercise would be to practice drawing simplified sketches, using the appropriate
symbols. There will be a requirement in the exam paper for you to demonstrate your
ability to use the correct symbols in reproducing some simplified diagrams.
Test yourself 11 gives you some exercises to help you practice using symbols.
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Petroleum Open Learning
Test Yourself 11
1. Identify prefix letters that are normally used, and any common
alternatives, for tag number identification of the following equipment
pump............
heat exchanger...............
filter...........
compressor............
separator..............
electric motor........
2. Identify the products / systems that are normally identified by the following
product designation codes for line designation.
SW or WS
PL or PO
FG
PW
Al or lA
CM or CW
PG
LO
FO
FW or WF
3. Identify the type of valve from the following typical P&ID abbreviations:
(a) ESDV
(b) UHMV
(c) PSV
(d) SSSV
(e) SSIV
(f) BDV
4. Draw the correct symbol for the following different types of valves.
hand operated choke valve
fail open control valve
wedge gate valve
butterfly valve
plug valve
pressure vacuum breaker
check valve
4 way valve
3 way valve
diaphragm actuated pneumatic valve
actuated hydraulic ESD valve
ball valve
globe valve
double seated ball valve
pressure safety valve (PSV)
needle valve
rupture disc (bursting disc)
motor actuated valve (MOV)
hand operated valve
5. Draw the correct symbols for the following items of equipment.
horizontal three phase separator
hydrocyclone separator
reciprocating pump
eductor/ejector
orifice plate
plate heat exchanger
vertical two phase separator
centrifugal pump
centrifugal compressor
turbine meter
shell and tube heat exchanger
straightening vanes
6. Draw a simple level control instrument loop consisting of:
level transmitter (LT)
level indicating controller (LICA)
I/P relay/converter (LY)
level control valve (LCV)
Your diagram should show the correct symbols for the instrument lines
connecting each instrument.
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Check Yourself - Answers
Petroleum Open Learning
Check Yourself 1
1.
Separator Vessel.
2.
BS1553 Part 1.
3.
a) Plot and Elevation Drawings show :
The physical location and relevant position of various items of equipment.
b) Process Flow Diagrams show :
The operating parameters, the main control points and the mass balance data of the process fluids flowing
through the process.
c) Piping & Instrument Diagrams show :
The design criteria for the piping, instrumentation and equipment used in the process.
4.
AS BUILT drawings have been revised after construction and commissioning.
These drawings indicate the actual situation of the process as it has actually been built. The As Built drawings remain
subject to the amendment and revision process.
5.
Revision changes are normally identified by a “cloud” drawn around each alteration.
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Petroleum Open Learning
Check Yourself 2
Go to the North walkway and then turn right and walk to the East side of the module. Turn
right again and head South passing on the East side, the escape chute, the east stairs,
Dehydration KO Drum and the Glycol Regeneration Package. On the west side of the
walkway you will pass the Oil Export Pumps P-0301A/B/C. After you have passed the Export
Pumps turn right down the next walkway and head West. You will pass LP Condensate
Pumps P-1101A/B on the south side of the walkway, and Oil Coolers H-00101 A/B on the
north side. At the point that the walkway turns North, you will find the Main Closed Drain
Vessel V-2801 on your left hand side.
OR
Go to the North walkway and then turn left and walk to the West side of the module passing
Produced Water Coolers H-2701 A/B and LP Flare Drum V 1602 on the South side of the
walkway. At the West end of the walkway turn left again and head South passing on the East
side, Third Stage Water Pumps P-2701 A/B and Oil Booster Pumps P-0101 A/B/C. On the
west side of the walkway you will pass a laydown area, hose loading area, the North Bridge
and the North Stairs. After you pass the North Stairs, you will find the Main Closed Drain
Vessel V-2801 on the East side of the walkway.
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Check Yourself 3
1. HP compressor suction cooler.
2. Second stage separator V-0102.
3. Centrifugal pump. It appears that it will only be
required if the test separator operates at lower
than normal pressures when the oil would not be
able to flow into V-0102.
4. Screw pump. Again it appears that it will only be
required if the test separator operates at lower
than normal pressures when the produced water
would not be able to flow to the produced water
system.
5. Pressure control will be maintained via the
pressure control valve to the flare.
6. The fact that the isolation valve indicates NC
( normal closed ) and the line to fuel gas indicates
NNF ( not normal flow ) would lead us to believe
that it is normally isolated and only used for start
up purposes.
The gas from the test separator would also have
to be routed to flare with the flare PCV set at fuel
gas pressure so that any excess gas would go to
flare.
7. Pressure would normally be controlled by the
pressure controller (PC) acting on the PCV to the
HP gas compressor.
If the compressor was shut down, then the PC
would act on the PCV to flare to control the pressure.
8. The
for stream 1 on the inlet line to the first
stage separator points you to the appropriate
column in the mass balance data table where
the pressure is given.
During normal operation, the test separator
would operate at the same pressure as the first
stage separator (27.58 bara).
The pressure for the first stage separator is also
given in the circle shape on top of the vessel.
9. The level controller (LC) acts on the level control
valve (LCV) on the oil outlet line to V-0102.
10.The interface level controller (ILC) acts on a
LCV located at the produced water system. This
would infer that the produced water system is a
hydrocyclone unit as the interface LCV would be
on the water outlet side of the hydrocyclone. (The
line from the HP Hydrocyclone into the inlet of
the test separator confirms that a hydrocyclone
system is used).
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Petroleum Open Learning
Check Yourself 4
1. Three Stages.
1st stage pressure 26.58 barg.
2nd stage pressure 14.51 barg.
3rd stage pressure 8.65 barg.
2. 1st stage pressure to HP compressor.
2nd stage pressure to IP compressor.
3rd stage pressure to LP compressor.
3. Plate cooler using sea water.
6. Shell and tube using cooling medium (normally
potable water/glycol mixture).
7. Centrifugal driven by electric motor.
8. The LP compresses gas from the 3rd stage
separator up to IP compressor suction pressure
(2nd stage separator pressure ) where it is
commingled with gas from the 2nd stage separator
and then compressed by the IP compressor up
to HP compressor suction pressure (1st stage
separator pressure). All separator gas is now
commingled and routed to the HP compressor.
10.The LCV will cut back and eventually close if the
level continues to fall.
The export pumps and booster pumps recycle
valves will open to maintain a flow through the
pumps.
The 3rd stage separator pressure control
valve (PCV) will cut back to maintain separator
pressure.
The LP compressor recycle valve will open to
maintain a flow through the compressor.
9. The level controller (LC) acts on the level control
valve (LCV), located downstream of the export
pumps. If the level rises above the setpoint, the
LCV will open up and vice versa if the level falls.
4. Three, P-0101A/B/C.
5. One for each pump, H-0301A/B/C.
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Petroleum Open Learning
Check Yourself 5
The test separator can be used for limited 1st
stage separation, although the facility to test
wells during this period would be lost.
Check Yourself 6
1. There are two suction coolers for each compressor due to the large
volume of gas and the high cooling duty requirement.
2. Shell/tube.
3. Centrifugal.
4. Dehydration,
5. There is only one to serve both compressors which means that there will
only ever be one compressor on line at any one time and that the cooling
duty is very low.
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Check Yourself 7
1. (a) Stream number 11 is 88.5°C.
Stream number 13 is 32.2°C.
(b) Cooling the gas through suction cooler H-1102A/B.
2. Gas compression through C-1101 A/B.
3. The gas from the compressor discharge (Stream 10) is commingled in
Stream 11 with the warmer gas from V-0102 (Stream 5).
6. Any six from:
Pressure
Liquid MW
Vapour density
Vapour flowrate
Standard liquid f/rate
Enthalpy
Vap MOL Fraction
Total flowrate
Free Water
Mass
Temperature
Vapour MW
Liquid density
Liquid flowrate
Standard vapour f/rate
Z factor
Comp MOL %
PPM (MOL) H2S
Free water flowrate kg/h
4. The pressure drop across the LCV from 68 bara to 27.58 bara has
created a proportional temperature drop of the NGL.
5 (a) From the export compressor suction scrubber V-1105A/B.
(b) The higher pressure of 68 bara at this stage in the process
combined with the 10.5°C temperature drop created across H-1106
and the PCV on the inlet to V-1105A/B make the ideal conditions to
maximise the removal of propane by liquefying it.
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Petroleum Open Learning
Check Yourself 8
2. It requires to be reset locally.
6. It is a high high and a low low pressure trip
device that will cause a process shutdown
and anunciate in the CCR.
3. It is a 2” - Two Phase Line - System 01 Line number 012 - Piping specification
H6A - Insulated for heat conservation
(electric tracing ).
7. (a) It will open if the separator pressure
rises due to a forward flow restriction
to the compressors, and vent excess
pressure to the HP flare header.
4. There are only two required on line at any
one time. Keeping this one off-line allows
it to be put on line when one of the other
two requires to be isolated for
recertification.
(b) PT 01023 sends a signal to
PICA 01023 on the DCS which in turn
will send a signal to PY 01023 to act
on PV 01023 when the set points are
reached.
5. There is a change in piping spec,
downstream of the PSV. If the
downstream valve were locked closed with
the upstream valve locked open, and the
PSV were to pass, there would be a
pressure build up downstream of the PSV
at a pressure above the piping spec
design.
(c) PICA 01023 incorporates a high and
low pressure alarm signal that will
anunciate on the DCS.
1. V-0101 is a 3 phase separator.
8. Suction pressure control to the HP
compressors via PIC 01208.
9. It cannot be done as there are non return
valves (NRVs) in the gas outlet from
V-0101 and also on the test and
production manifolds.
10. Oil / water interface.
11. Protect the separator from a low low level
by causing a process shutdown when the
level falls to the low low level setpoint.
12. Oil/water interface. LCV 01013 is located
downstream of the hydrocyclone units.
13. LEA 0101OA/B/C which provides a 2 out of
3 voting protection for high high level.
14. Ultrasonic.
15. Densitometer transmitter. It compensates
the flow measurement from FE 01029 for
density.
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Petroleum Open Learning
Check Yourself 9
1.
Suction valves - Manual butterfly and electric motorised
butterfly valve.
7. PR-PD-0086-01.
Bypass valves - Manual ball and globe valves.
8. Flow 693.4 m3/h.
2.
Suction strainer.
p 3.2 barg.
3.
Temperature -10°C/110°C.
FICA 01045 acting on recycle valve FV 01045 (P-0101 A).
Pressure 18.6 barg.
4.
Parallel.
9. P ( personnel protection )
5.
Booster pump seal oil system.
6.
PEA01172LL
10. The recycle line valves are locked open and the FV is fail open.
This means that there will always be a flowpath back to the
3rd stage separator.
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Petroleum Open Learning
Check Yourself 10
1.
Gas flows through suction valve SDV 11001 which incorporates a
pressurising valve SDV 11002 and a pressure differential switch
PDI 11003. The flow then passes through suction pressure control
valve XV 12150A before entering the tube side of suction cooler
H-1101A.
The flow then enters suction drum V-1101A where condensate,
formed as a result of the cooling, is separated and removed from
the gas stream. The condensate is routed under level control to the
3rd stage separator via LP condensate pump P-1101 A.
The gas from the suction drum is routed forward to the suction of LP
compressor C-1101 A. The gas from the discharge side of C-1101A
is routed to the IP compressor suction cooler H-1102A. An anti
surge/ recycle line is incorporated in the compressor discharge to
maintain a flow through the compressor and back to upstream of
the suction cooler H-1101 A.
2.
(b)
3. A temperature controller TICA 11005 monitors the gas
temperature downstream of the suction cooler H-1101 A.
The output from this controller acts on TV11005 which
controls the flow of cooling medium on the outlet from the
shell side of H-1101A to increase or decrease the flow of
cooling medium as required.
4. XV 12150A controls the suction pressure to the
compressor. It also controls the pressure of the 3rd stage
separator V-0103.
5. PD111003 across suction valve SDV 11001 transmits a
signal to the compressor logic (CL) which will not permit
SDV 11001 to be opened until the required ∆p is achieved.
( Normally less than 5.0 barg ).
6. FE - Frost proofing with electrical trace heating.
If there were a tube rupture the cooling medium would pass
into the tube side of the cooler and contaminate the gas
compression system.
continued...
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Petroleum Open Learning
Check Yourself 10 (cont’d)
7.
Condensate is removed under level control (LICA 11008) from
V-1101A by LP condensate pump P-1101A to the 3rd stage
separator V-0103. LICA 11008 acts on LV 11008 which is
located downstream of P-1101A to ensure a continuous suction
flow to the pump.
A 1” minimum flow recycle line located between the pump
discharge and LV 11008 will maintain a flow back to the inlet line
to V-1101A when LV 11008 requires to be closed to control the
vessel level.
8.
This is a ‘seal failure’ line that will relieve pressure to
atmospheric vent if the pump mechanical seal fails.
VA 005 is normally open (NO) to maintain the flowpath.
RO 11442 is a restriction orifice that will create a slight back
pressure in the line when the seal fails.
PEA 11441 is a pressure switch which will sense the pressure
build-up in the line and transmit a shutdown (SD) signal to the
DCS in the CCR and trip the pump. This will, in all probability,
have the effect of tripping the compressor.
9. No.
The recycle valve UV 11037 is a fail open valve, it would
therefore be expected to remain open whilst the compressor
is shutdown. There are valve position switches (ZSC 11037
& ZSO 11037) which transmit signals to the compressor logic
(CL), It is therefore necessary that a ‘valve open’ signal is
seen by the CL as one of the start permissives.
10. It is the compressor purge valve which is controlled by CL to
open as part of the compressor start-up logic.
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Petroleum Open Learning
Check Yourself 11
4. You will find the correct symbols in Book 2 on Pages 12-19.
1
Flow meter Q
Heat exchanger H, E, X
Filter F
Compressor C, K
Separator S, V
Electric motor M
2
SW or WS
PL or PO
FG
PW
Al or IA
Seawater
Process liquid/oil
Fuel gas
Produced water
Instrument air
3
(a) ESDV
(b) UHMV
(c) PSV
(d) SSSV
(e) SSIV
(f) BDV
Emergency shutdown valve
Upper hydraulic master valve
Pressure safety valve
Sub surface safety valve
Sub sea isolation valve
Blowdown valve
5. You will find the correct symbols in Book 2 on Pages 22-34
6. Refer to Figure 12 in Book 2. The level control instrumentation loop
for the oil side of the separator gives a good indication of what you
should have drawn.
CM or CW Cooling medium/water
PG
Process Gas
LO
Lube oil
FO
Fuel oil/diesel
FW or WF
Fire water
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