PREVENTION AND DETECTION

 Kick Detection
• Detecting a kick on a floater sometimes becomes difficult, because of the drilling vessel and natural
wave motion. Wave action and the drilling vessel motion, create pit level fluctuations and flow rate
changes. Equipment to compensate for fluctuations in levels and flow rates are installed to minimize
the problems.

 Pits: In the pits multiple monitors are installed. A Pit Volume Totalizing system accounts for the
gains and losses on each monitor and displaces a true single value.
 Return Flow Meter: Flowline sensors that compensate for fluid surges are used in the flowline.
These flowline sensors back fluid up in the flowline creating a small reservoir and thus
providing a continuous and relatively stable flow past the paddle.

 Other things which can affect our ability to monitor trends include;
1. Pitch and roll;
2. Ballasting operations; any solid or liquid that is brought on board a vessel to increase the draft,
regulate the stability and similarly discharged when cargo was to be loaded on board.
3. Crane operations
4. Anything else which makes the rig move.
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 S U B SE A ST A C K

Kick Detection in
Subsea Environments
Conditions that can make
kick detection difficult
• Low permeability
formations.
• Long laterals.
• SOBMs and OBMs.
• High pressure/high
temperature wellbores.
• Vessel movement can
affect return flow and pit
levels.
• Crane operations.
Copyright ©Wild Well Control, Inc. 2015
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 S U B SE A ST A C K

Air Gap

• Definition
– Space between rig floor
(RKB) and water line.
• Application
– Used in determining
calculations (when required) Rig
floor
such as riser margin,
volume, strokes and time. AIRGAP

Waterline

Copyright ©Wild Well Control, Inc. 2015

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 S U B SE A ST A C K

Riser Margin

• Definition
– The difference between HP of mud in the riser and that of
seawater around it.
– Upon riser disconnect, HP of mud in riser is replaced with HP of
seawater.
• May result in underbalanced well.
• Riser margin must be calculated to prevent such an underbalance.
• Calculating riser margin
– Is it always useful to calculate riser margin?
– No: As water depth increases, using a riser margin may result in
severe overbalance.

Copyright ©Wild Well Control, Inc. 2015

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 S U R F AC E S T AC K

How to Calculate the

Riser Differential
• Purpose
– To calculate the pressure differential between the fluid column
inside the riser and the seawater outside of the riser.
• Formula
– RDpsi = HP Riserpsi – HP Seawaterpsi or RD = Riser Differential
• Parameters
– Riser length.
– Seawater depth.
– Mud gradient.
– Seawater gradient.

Copyright ©Wild Well Control, Inc. 2015

5
Fracture Gradients
• Fracture gradients in deep water are effectively less than those observed on land or
in shallow water at equivalent drilling depths.
• The reason being, lower overburden stresses. Water does not exert as much
overburden pressure as earth material.

Example:- What is the total overburden pressure at the shoe?

Water Depth = 1000 ft

Air gap = 65 ft
RKB to Shoe = 1565 ft
Sea water gradient = .445 psi/ft
Formation gradient = .69 psi/ft
65 ft

Sea water overburden pressure = 1000 X .445 = 445 psi

1000 ft

Formation overburden pressure = 500 X .69 = 345 psi

500 ft

Total overburden pressure @ shoe = 445 + 345 = 790 psi

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Shut In and Hang Off
 With the well shut in the drill string will slide up and down through the stack due to heave.
This will cause excessive wear and early failure. To prevent this, it is normal to close the
Annular and then ‘Hang Off’ on a Pipe Ram.

 Hang Off involves closing a ram (at lower than normal pressure), stripping down to rest
the Tool Joint on the Ram Block, then applying correct closing pressure.

 Another important point is space out. The Driller needs to know his correct space out in
order to shut in/ hang off correctly. This involves a little more working out than a surface
well and is also affected by Tides.

 Hang off procedure

 Space out
 Reduce manifold pressure
 Close rams
 Reduce annular pressure
 Strip to rams
 Activate locks (if not automatic)
 Increase manifold pressure
 Bleed off pressure between ram and annular

Monitor the riser with the trip tank 7

 Procedures for Hard Shut In

Subsea BOP - Drilling Subsea BOP - Tripping

 Stop drilling  Set slips below top tool joint
 Pick up to hang off position
 Install FOSV
 Shut down pumps
 Flow check (if positive continue)  Close FOSV
 Close BOP (Annular)  Close BOP(Annular)
 Open choke line valves (fail-safes)  Open choke line valves (fail-safes)
 Record pressure
 Notify person in charge  Record casing pressure
 Check space out  Notify person in charge
 Hang off using DSC  Make up top drive
 Activate ram locks(if not automatic)
 Record drill pipe pressure
 Bleed off pressure between rams
and annular  Evaluate

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 Procedures for Soft Shut In

Subsea BOP - Drilling Subsea BOP - Tripping

 Stop drilling  Set slips below tool joint
 Pick up to hang off position
 Install FOSV
 Shut down pumps
 Flow check (if positive continue)  Close FOSV
 Open choke line valves (fail-safes)  Open choke line valves (fail-safes)
 Close BOP  Close BOP
 Close choke
 Record pressure
 Close choke
 Notify person in charge  Record casing pressure
 Check space out  Notify person in charge
 Hang off using DSC  Make up top drive
 Activate ram locks (if not automatic)
 Bleed off pressure between rams and  Record drill pipe pressure
annular  Evaluate

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CHOKE AND KILL LINE FRICTION

 The long choke and kill lines create additional

pressure loss when pumping through them

 Friction is caused by fluid flow and acts back toward

the pump. Therefore, Choke Line Friction (CLF)
acts back down hole.

 CLF will therefore affect the open hole formations

and if too high, can cause losses.

 The value of the CLF at normal kill speed is

important for the well control operation .

 The following slides shows how this is achieved.

CHOKE AND KILL LINE FRICTION
There are 4 recognized ways to take CLF. Depending on method chosen, you may exert
friction pressure on the formation.
BOP Configuration may restrict the number of ways you can take an SCRP.
Method 1: Method 2:
1. Take a standard SCRP (down string and up to flow 1. Close a BOP above the choke and kill lines to be
line). used for this test.
2. Close Annular and pump at same rate down the 2. Pump down the kill line and up the choke line.
string and back to surface via the choke line and
3. The pump pressure will be two times the CLF.
fully open choke.
4. To prevent the friction acting downhole you will
3. Subtract the two pressure readings. The difference
have to close a BOP below the choke and kill in
is the CLF.
use.
Advantages
Advantages
Uses same line up that would be used to kill well.
1. No increase in BHP if LPR closed.
Disadvantages
2. Displaces both lines to clean mud.
1. Well must be shut in. Disadvantages
2. BHP increases by CLF.
1. Well must be closed in.
3. Dirty mud through failsafes and choke manifold.
2.Increase in BHP if LPR open.
4. Pipe remains static.
3. Mud circulated via choke and choke manifold.
This method should be done with the bit inside the
This could be done with or without pipe in the
shoe (i.e. prior to drilling out). 11
hole.
 CHOKE AND KILL LINE FRICTION
Method 3:

1. Pump down the choke or kill line with returns back up

the Riser to the flow line.
2. The pump pressure is the CLF.
Because flow is down the line any friction loss acts
back upward towards the pump and not downhole.

This is the simplest and most effective way to obtain

CLF.

Advantages
1. Pipe can be rotated or reciprocated.
2. No increase in BHP even with LPR open.
3. Clean mud used.
4. Choke manifold and choke not used.

Disadvantages

This method assumes pressure losses in riser are negligible.

 CHOKE AND KILL LINE FRICTION

NOTE: All rigs are not equipped Method 4:

with a static kill line pressure 1. Circulate the well through a fully open
gauge. choke with BOP Closed and record the
pressure on the (static) kill line.
2. The kill line pressure will reflect the CLF.

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Pump start up is different and takes into account choke line friction

First procedure :
We do not want the extra CLF pressure as it can
cause losses if too high. Therefore the start-up is
modified in such a way that the CLF is
compensated for by a reduction in Casing
pressure.
If CLF = 300 psi, then instead of holding it
constant we reduce Casing pressure by 300
psi during start-up.

To achieve this there are two techniques we

can use.
Procedure 1
Bring mud pump up to kill speed and at the same
time allow Casing pressure to drop in increments
by the CLF pressure. (i.e) every 50 psi .
This drop in Casing pressure compensates for the
CLF or hold a static Kill line pressure constant. 14
 Procedure 2

 In this technique, the kill line valve at the stack is opened to allow
pressure to be read on the surface kill line gauge. The kill line is a dead
end at the choke manifold; it is not opened up to the circulating path.
 Before start up both SICP and Kill Line pressure (SIKP) should read the
same (assuming contents in the lines are the same density).
 The choke is opened on the choke line side as pump speed is increased.
During this process, the SIKP is held constant by adjusting the choke.
 As the mud begins to flow up the choke line the CLF starts to build. This
pressure begins to act on the kill line causing the SIKP to rise. By
adjusting the choke to maintain SIKP constant you cause the Casing
pressure to fall by an amount equal to the CLF.
 Once up to kill speed the Casing pressure would have fallen by an amount
equal to the CLF.
 The beauty of this technique is that you do not have to know the CLF
beforehand. It allows the pressure to drop by the ‘actual’ CLF at that time,
therefore it is more accurate.
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 Both techniques mentioned maintain BHP both constant and correct during start up.
 But! There is one situation where you cannot maintain a constant BHP; this
is when the SICP is less than CLF.
 e.g. SICP = 200 psi CLF = 300 psi
 In this case you cannot reduce the casing pressure by any more than 200 psi, therefore the
difference (100 psi) builds up in the hole to affect the pressure acting on the formation as
well as the pump pressure; the choke would be fully open and Casing pressure would
equal 100 psi.

 ICP = SIDPP + SCRP + (CLF– SICP)

 If this effect were critical to well bore integrity then you would either use
1) Slower kill speed to reduce CLF
2) Circulate up both choke and kill line at the same time.
 Assuming that both lines are the same ID, this would effectively reduce CLF to ¼ of
its value if only one line was used.
KILL PROCEDURE
The same methods are used for killing a well on a floater as used on a fixed rig, but there are two
things to look out for, these are: -
1. Effects of influx when it is in the Choke Line.
2. Effect of Choke Line Friction once the influx has been circulated out.
 Effects of Influx in the Choke Line.
 When the influx enters the choke and kill lines, it affects the hydrostatics in the well and the friction loss in the line
and across the choke.

 As the light influx enters the narrow choke line, it quickly fills the line. This results in a rapid increase in the length
of the influx.

 The increase in length reduces the overall hydrostatic in the Annulus. The resulting imbalance allows the drillpipe to
u-tube causing a reduction in the drillpipe pressure. To counteract this, the choke will need to be adjusted to bring the
drillpipe pressure back to its correct value.

 The choke size reduction will increase the casing pressure back to the correct value for that moment in time and
therefore restore bottom hole pressure as well as the u-tubebalance.

 So when the influx enters the choke line, be prepared to close the choke fairly quickly to maintain correctPump
Pressure.

 The opposite effect will take place as the influx exits the choke line and is replaced by mud.
and when mud is replacing the influx. 17
 The key point is to be prepared for major choke adjustments when the influx is lengthening, exiting through the choke
 Effect of Choke Line Friction once the influx has been
circulated out.
 As noted earlier, CLF affected the start up procedure. So it affects the shut down procedure as well. In this
case, the reverse takes place to allow Casing pressure to rise by theCLF.

 There is another effect and that is when the influx is out and mud is being circulated out. This could be old
or kill mud, but the effect is more noticeable with kill mud.

 First, consider that kill mud has to be circulated all the way round and that the mud hydrostatic would at
least equal formation fluid pressure. Therefore, no backpressure would be required to maintain the correct
bottom hole pressure because the kill mud is doing thejob.

 But the CLF would still be present (probably a little more due to heavier mud), therefore the CLFwould
act on the well and you would also see the pump pressure increase by the same amount.

 Sometime earlier; normally once the influx is out and as the casing pressure was getting less and less, the
choke would be fully open.

 This would happen around the time that the casing pressure remaining on the well was the same as the
CLF. From this point on, further pumping of kill mud up the annulus would cause the Casing pressure to
rise up to the CLF value. This rise in pressure would affect the pressures downhole and back to the pumps.

 If this pressure build up was not acceptable then a slower pump rate would be required or use both kill and
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choke line to complete the kill.
Shallow Hole Kicks
 The most severe well control problems of drilling in deep water is that of a kick
occurring when no protective casing is set.

 Many companies will drill the conductor hole without a marine riser, and taking returns
at the sea bed.

 These returns can be monitored for indications of gas with a Remote Operated Vehicle
(ROV), Watch at surface or Decrease in Pump pressure.

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 S U B SE A ST A C K

Gas Trapped in the Stack

• Issue
– During a well control operation, some gas will become trapped
beneath annular and/or rams of a shut-in well.
• Problems
– If BOP is opened, trapped gas will migrate up the riser and
expand rapidly.
• Corrective action
– Stack must be “swept” prior to opening the well.

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 Trapped Gas
 During the well kill process, there is a possibility
of influx being trapped between the closed BOP
element and the choke line outlet.

 The consequences of not dealing with trapped

gas correctly include:
1. Unloading the riser.
2. Drop in BHP causing further influx.
3. Riser collapse.

The Key steps are:

1. Close lower rams and pump down kill and up choke line to flush cavity.
2. Displace choke line to a lighter fluid (e.g.) water or base oil.
3. Open upper BOP and allow Riser mud to U-Tube into Choke Line.
4. Close BOP and flush lines to clean mud.
5. Displace Riser to Kill Mud.
6. Open well and check for flow
 S U B SE A ST A C K

Displacing Riser Fluid

• Purpose
– During or after well control operation, original fluid in riser
must be displaced with kill weight fluid so that HP
of wellbore is balanced when BOP is opened.

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 Trapped Gas
Water Depth = 1000 ft Volume of trapped gas = 9 bbls
Kill Fluid weight = 12 ppg Original Fluid weight = 10 ppg
Atmospheric pressure = 14.7 psi

What would be the volume of gas at surface, if the Driller opened the BOP without
circulating the gas bubble out?

Answer
• The volume of gas at surface will be:
– Pressure in the Bubble when trapped (P1) = 0.052 * 12 * 1000 = 624 psi
– Volume of the Bubble when trapped (V1) = 9 bbls
– Pressure @ surface (P2) = 14.7 psi
– Volume of the bubble @ Surface (V2) = 382 bbl

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 Riser Collapse Example:-
 Depth 11,500 ft
 Water depth 2,500 ft
 Air gap 70 ft
 Riser length 2,570 ft
 Sea water gradient 0.45 psi/ft
 Mud weight 13.1 ppg
 Riser collapse pressure 550 psi

 Calculate how far could the mud level drop before the riser collapsed? 1,292 ft

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Trapped Gas
 Below is a generic procedure which may not exactly match with specific rig procedures.

 Example procedure

 Isolate the wellbore by closing a set of pipe rams. It is then possible to subject the complete contents of the
BOP to the procedure. If any other ram is closed, gas can become trapped under the closed set of rams.

 Displace kill weight mud by pumping water or base oil down the kill line and up the choke line., holding
back pressure on the choke equal to the hydrostatic difference between the kill mud and the water or base
oil. Circulate 3 times the volume of the choke and kill.

 Next bleed off the pressure by opening the choke fully

 Once the pressure is bled off the BOP and the choke line will contain a mixture of water (or base oil) and
gas. This mixture is displaced by using the hydrostatic overbalance of the riser.
The procedure to do so is, as follows:
 Close the diverter
 Fill the riser and keep full using TripTank.
 Open the annular
 Take returns up the choke line through the mud gas separator.
 Monitor Trip Tank
 After opening the annular
 What happens when the annular is opened?
 Hydrostatic overbalance of the riser displaces the gas/water mixture in the BOP and choke line.
 The level in the riser will drop.
 The riser will have to be filled from the top.
Remember that the lower pipe rams are still closed. 25
Continue
 After opening the annular preventer the level in the riser will drop as it displaces the
contents of the BOP and the choke line. The riser must be kept full with mud from the top
using the fill up line.

 Next close the ram or annular to fully displace contents of kill and choke lines to kill
mud.

 Once equilibrium has been reached, the riser is displaced to kill mud by using the kill and
choke line or the riser boost line. As mentioned before, a small amount of the gas/water
mixture may remain behind in the BOP while bleeding pressure from the choke. This will
be circulated to the surface through the riser, and expansion of this small amount might
take place as it nears the surface. This small amount of gas/water mixture should not
create a problem but has to be addressed in order to make the correct decision to continue
the displacement of the riser.

 Once the marine riser is static and it is confirmed that there is no pressure under the lower
pipe rams, the well can be opened and monitored.
26
LMRP

27
 Marine Riser Fill Up Valve
 The automatic Riser Fill-Up Valve is designed to prevent collapse of the riser if the
level of drilling fluid drops due to intentional drive-off, loss of circulation, or
accidental line disconnection

 During drilling operations, the valve's internal sleeve is kept closed by a spring.

 When riser pressure drops, hydrostatic pressure pushes up on the sleeve and
overrides the spring force.

 This causes the valve to open and sea water enters the riser, equalizing the pressure
and preventing collapse.

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SUBSEA BOP EQUIPMENT

29
 The Subsea BOP is bigger in size and has an additional Annular and Rams. The
reason for having additional equipment is for redundancy.
• Connectors: There are two connectors. One on the bottom of the BOP stack and the
other between the two Annular.

– If the BOP needs to be left on bottom, then the top connector is unlatched.
– If the BOP needs to be pulled to surface then the bottom connector is unlatched.
• Flex (Ball) joints: There may be two or more flex joints. One is installed on top of
the Upper Annular and the other could be near surface. These are installed to
compensate for lateral movement of the drilling vessel.
• Slip or Telescopic joint: The slip or telescopic joint is installed near surface. It is
installed to compensate for vertical movement in the drilling vessel. The slip joint is
the weakest when diverting shallow gas due to the seals between the outer and inner
barrel.

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 S U B SE A ST A C K

Shutting in a Subsea Well

Considerations when shutting in a subsea well

• Allowance of longer shut in times than surface stacks.
• Larger BOP components, thus more fluid required.
• API Std 53 response times:
• Each ram BOP must close in 45 seconds or less of actuation.
• Each annular in 60 seconds or less.
• Additionally, choke and kill line valve response times “shall not exceed
the minimum observed ram close response time.”
– Accumulator unit
• Accumulator pre-charge for subsea stacks.
• Overcome hydrostatic pressure of the seawater.
• Closing ratios.
• What are your BOP response times?
Copyright ©Wild Well Control, Inc. 2015
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• Components of a Hydraulic System:(For simplicity the hydraulic system will be discussed)
 Manipulators: The manipulators are three position four way valves. The three positions
of the manipulator are OPEN, CLOSE and BLOCK(neutral). These manipulators can be
functioned from a remote location or manually.
• On a Subsea Hydraulic system manipulators direct pilot fluid to the Sub Plate Mounted
(SPM) valves in the pods, when the manipulator is in the Open or Close position
BUT Block pilot fluid when the manipulator is in the Block position .
 Pods
 There are two pods in a Subsea control system, Blue and Yellow.
 These pods are mounted on the Lower Marine Riser Package.
 The reason for having two is for redundancy.
 The pods could be retrieved separately in a Guide line system only. In a guide line less system
they cannot be retrieved separately.
 The Driller has to select either one of the pods to be active, By active, it means that power fluid to
function the BOP goes only to the active pod.
 Sub Plate Mounted (SPM) valves:
 In each pod there are open SPM valves and close SPM valves for each function on the Subsea BOP.
 These valves are actuated by pilot pressure. Once actuated, power fluid from the active pod is direct
to a function via a shuttle valve. SPM valves when not activated, are venting.
• Shuttle valves:
 The shuttle valve is installed as close as possible to the function.
 The shuttle valve directs power fluid from the active pod to the function and isolates the non-active
 BOP Operation:
• The main objective of the BOP control system is to operate any of the functions in as short a time
as possible. There are three systems. The Hydraulic system, Electro-hydraulic system or the
Multiplex system. The difference between them is the way the command signal is transmitted from
Surface to the Pods on the BOP Stack
Conventional Hydraulic Multiplex (MUX) Control System
These are common on moored floaters.  Used on the dynamically positioned Deepwater rigs.
 It gives a much faster response time.
Steps of operation are as follows:
 In MUX systems an electric signal is sent from the
 Driller presses Annular Close Button onthe rig down to the BOP Control Pod on the stack.
drill floor electric panel. Steps of operation are as follows:
 Electric signal is sent to Subsea Control Room.
 Driller presses Annular Close Buttonon the drill floor electric
 A solenoid is activated to open an Air valve. panel.
 The air pressure operates the Annular Close 4-
 Signal is sent to the Subsea Control Room for processing.
Way Valve.

 Hydraulic fluid now pressures up the Annular  Processed signal is now sent subsea to electronic control unit
Close Pilot Line that runs to the Subsea control on the stack.
pod.
 Electric power (also run subsea along another cable) fires the
 At the pod the hydraulic pressure opens the Annular Close solenoid (this command is sent by the subsea
Annular Close SPM Valve. electronic control unit).
 This allows main operating fluid, at regulated  Hydraulic fluid operates the Annular CloseSPM.
pressure, to close the Annular.  The SPM allows regulated operating fluid to go to the
 Fluid from the Annular opening chamber is Annular Closing chamber.
pushed back to the AnnularOpen SPM valve
 Fluid from the opening chamber is vented back to sea th r ough
Conventional Hydraulic
 Conventional Hydraulic
• Pilot and operating fluid are sent to the subsea stack via two hose bundles
which are connected to the control pods mounted on a receptacle on the
LMRP.

• Conventional systems consist of a 1” supply hose for power fluid (3,000psi)

and up to 64 small 3/16” hoses for pilot fluid.

• In each pod , the pilot lines are connected to SPM valves and also to the
common power supply

• When a stack function is selected the pilot fluid pressure is directed down a
pilot line to the selected SPM valve in both pods.

• Both SPM valves operate but only the selected pod has pressurized operating
fluid that flows through a shuttle valve mounted on the stack , where it is
routed to the operating cylinder of the BOP function.
 Multiplex (MUX) Control System
• In water depth exceeding 5000 ft the response time of an all hydraulic system is
too slow for an acceptable function operating response time.

• Deepwater rigs use a control system called Multiplex (MUX). Hydraulic fluid is
plumbed from surface through conduits on the riser modules and the individual
pilot functions are controlled by an electrical signal.

• All pilot fluid signals for component on the BOP and LMRP are electrically
actuated from the surface via the MUX cables and happen instantly.

• Mounted internally on the pods are the PLCs, electrical solenoids, control valves
and remote pressure regulators.

• The control panels communicate to the MUX pods using PLCs and modems and
use copper wire or fiber optics to transmit the signal through the MUX cables.

• An electrified solenoid releases the hydraulic pilot signal which shifts the SPM
valve to allow regulated control fluid to the shuttle valve and then the LMRP or
BOP component you want to function.
 MANAGING EMERGENCIES
 Dynamically positioned vessels may have the need to disconnect from the well in an
emergency like rough sea conditions, a loss of well control. In these condition an
Emergency Disconnect (EDS) will be performed.
 DP vessels are equipped with various types of emergency back up systems to close the
BOPs and shear the drill string in an emergency .
1. Auto-Shear
2. Dead-Man
3. ROV Intervention
Autoshear is a safety system that is designed to automatically shut-in the wellbore in the
event of a disconnect of the LMRP.
Autoshear shall be installed on all subsea BOP stacks.
The deadman system is designed to automatically shut in the wellbore in the event of a
simultaneous absence of hydraulic supply and control of both subsea control pods.
A deadman system shall be installed on all subsea BOP stacks.
The BOP stack shall be equipped with ROV intervention ( Hot Stab) equipment that at a
minimum allows the operation of the critical functions (each shear ram, one pipe ram, ram
locks, and unlatching of the LMRP connector).
The acoustic control system is designed to operate designated BOP stack and LMRP
functions and may be used when the primary control system is inoperable.
The acoustic control system should be capable of operating critical functions.
 S U B SE A ST A C K

Emergency Disconnect System

(EDS)
• Purpose
– Disconnects the riser & LMRP
from the stack and secures
the well in an emergency.
• Operation
– Drive-off. Vessel is driven
out of position accidentally
due to loss of power.
– Flex joint safe operating angle
exceeds yellow and red watch
circles.
– Maximum disconnect time
= 45 seconds.

Copyright ©Wild Well Control, Inc. 2015

38
Pod Selection
YELLOW BLOCK BLUE
RESERVOIR

Step1:
The Driller pushes the Blue Pod YELLOW BLOCK BLUE
Selector Button and a signal is sent to
the manipulator.

Step2: Manipulator
The manipulator shifts to the Blue
Pod selection and perm its Power
Fluid to go to the Blue Pod only.
The Blue Pod is now Active, where as
the Yellow Pod is Not Active.

YELLOW POD BLUE POD

39
Ram Close Function
Step 1:
OPEN BLOCK CLOSE
The Driller pushes the close RESERVOIR
button to close the ram and a
signal is sent to the
manipulator Pod Selector
Step 2: OPEN BLOCK CLOSE
The manipulator shifts to the
close and allows Pilot fluid to
go to the close SPM valves in Manipulator
Open Close
both pods. SPM SPM
Step 3:
The close SPM valves in both
pods actuate but power fluid To Yellow Pod
to close the ram only goes
through the active Manifold
pod. Regulator
Step 4:
Close
The ram closes. Power Shuttle
Open
fluid from the opening Shuttle
chamber vents at the open
SPM valve.
40
Ram Open Function
OPEN BLOCK CLOSE
Step 1:
The Driller pushes the ram open
button.
Step2: Pod Selector

A signal is sent to the manipulator. OPEN BLOCK CLOSE

Step 3:
The manipulator shifts to the open
position. Pilot fluid from the close line Manipulator Open Close
bleeds back into the reservoir.
SPM SPM
Step 4:
Pilot fluid goes to the open SPM
valves in both pods
To Yellow Po d
Step 5:
The open SPM valves in both pods Manifold
actuate but power fluid to open the Regulator
rams only goes through the active pod.
Step 6: Close
The ram opens. Power fluid from the Shuttle
closing chamber vents at the close Open
Shuttle
SPM.
41
Ram Block Function
Step1: OPEN BLOCK CLOSE
RESERVOIR
The Driller pushes the block
function.
Step2: Pod Selector
A signal is sent to the OPEN BLOCK CLOSE
manipulator.
Step 3:
The manipulator shifts to the
Manipulator
BLOCK position. Pilot fluid Ope Close
n
from the open line bleeds back SPM
SPM
into the reservoir.
Step 4:
The power fluid from the
To Yellow Pod
opening chamber vents at the
open SPM.
Manifold
Regulator

Close
Shuttle
Open
Shuttle

42
43
 API Standard 53 For Sub Sea
 Close each ram BOP in 45 seconds or less;

 Close each annular BOP in 60 seconds or less;

 Unlatch the riser (LMRP) connector in 45 seconds or less;

 Close non-sealing shear rams in 45 seconds or less;

 There is an increased risk of damage to the bladder if the pre-charge pressure is less
than 25 % of the system hydraulic pressure.

 The control pods may be retrievable or non-retrievable.