Process Flow and P&IDs Workbook 1

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

1


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



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


46 2


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



activities for you to apply your new knowledge


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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


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 !

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.

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. • 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.

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.

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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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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

I will now summarise the scope of each of these British Standards.

Part 1: 1979 Basic requirements

identifying the basic functions of measurement and control equipment, in relation to the plant with which it is associated.

(Also incorporated as ISO 3511/1- 1977)

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

BS 1646: Establishes a symbols system for use in

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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Petroleum Open Learning 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. The unique number allocated to each drawing provides information that helps us identify the project, system, type of drawing, and its revision number. 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.

• General symbols • System numbers • Abbreviations • 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

Sequence No In this case a four digit number

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.

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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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.


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).


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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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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.


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 ? 4. How many Oil Booster Pumps are there and what are their serial numbers ?

9. How is the level in the 3rd stage separator controlled ? 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.

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 ?

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.


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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 :

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.

• 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. 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 ?


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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?

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) 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 ?

(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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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.


• 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.

35


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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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 ?

4. There are three PSVs on top of V-0101. Why has one of them (PSV 01007C) got the upstream valve closed ?

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 ?

(b) How is it controlled ?

(c) How will the operators in the CCR know that it is open ?

continued...

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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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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...

41


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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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...

43


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.


44


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.

45


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.

46

Check Yourself - Answers


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.

47


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.

48


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).

49


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).

10.The LCV will cut back and eventually close if the level continues to fall.

7. Centrifugal driven by electric motor.

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.

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. 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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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.

51


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.

52


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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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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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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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.

56


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

57

Process Flow and P&IDs Workbook 1

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