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.
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.
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:
• an emergency shutdown valve (SD 01028)
• a density transmitter (DT 01189)
• a corrosion probe (CP 01031)
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.
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. P0176-D0002.
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.
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 :
• DCS panel to carry out certain shutdown functions which I will now explain.
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.
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.
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.
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.
What do you think would be a suitable response to the two emergencies ?
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.
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.
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.
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 andforcing the oil back into the reservoir.
Other facilities on the service header are :
• 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.
• Depressurisation facility to the HP flare header.
• 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.
The right hand take-off is the main flow line from the wellhead. The well fluids flow through the hydrauli-cally operated production wing valve PWV T0109 which is fitted with open and closed indicators simi-lar to the ones fitted to the hydraulic master valve.
The following instruments and valves are provided on the flowline downstream of the production wing valve :
• Erosion probe EP T0118.
• Corrosion probe CP T0111.
• Corrosion coupon CC T0110.
• High High pressure switch PEA T0123 routed direct to the ESD system.
• 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.
• 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.
• Drain line to closed drain header via a ball valve and a globe valve.
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 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.
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
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.
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.