SUBSEA WELL CONTROL
1
SUBSEA STACK DIFFERENCES
• Choke and kill line connected directly to
stack
• Choke and Kill lines are Manifolded so that
either can be used for circulation and
returns during a kill operation
• Use of blind/shear rams are used in place
of ordinary blind rams
• Rams are equipped with integral or
remotely operated locking systems
2
SUBSEA BOP ARRANGEMENT
3
SUBSEA BOP ARRANGEMENT
4
SUBSEA BOP ARRANGEMENT
5
SUBSEA BOP ARRANGEMENT
6
SUBSEA STACK AND CHOKE MANIFOLD ARRANGEMENT
7
Subsea BOP Controls
8
SUBSEA CONTROL SYSTEM
9
SUBSEA CONTROL SYSTEM
10
SUBSEA CONTROL SYSTEM
TYPICAL HYDRAULIC
HOSE BUNDLE
1.
1” I.D. Supply Hose
2.
3/16” I.D. Pilot Hose
3.
Outer Protective Jacket
11
SUBSEA CONTROL SYSTEM
12
Shuttle Valve
Power Fluid port isolated
from Blue Pod
Power Fluid to
Bop’s Functions
The shuttle valves
isolate the control fluid
system between the
selected pod and the
redundant pod.
The power fluid from
the selected pod will
shift the shuttle valve.
Power Fluid from
Yellow Pod
13
SUBSEA CONTROL SYSTEM
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Closing Sequences
- Close BOP,s from remote panel.
- Activate solenoid valve.
- Shift 3 position 4 way valve.
- Send pilot signal to the close SPM
valve on both pod with 3000 psi.
- Close SPM valve shift on the
selected blue pod.
- Power fluid from Subsea bottles is
able to flow and close function on
BOP.
- The fluid from opening chamber is
vented to the sea through the open
SPM valve.
- Accumulator pumps pressure up all
accumulator and BOP’s bottles to
3000 psi.
15
Opening Sequences
- Open BOP,s from remote panel.
- Activate solenoid valve.
- Shift 3 position 4 way valve.
- Send pilot signal to the open SPM
valve on both pod with 3000 psi.
- Open SPM valve shift on selected
blue pod.
- Power fluid from Subsea bottles is
able to flow and open function on
BOP.
- The fluid from closing chamber is
vented to the sea through the close
SPM valve.
- Accumulator pumps pressure up
all accumulator and BOP’s bottles
to 3000 psi.
16
Block Sequences
- Block BOP,s from remote panel.
- Activate solenoid valves.
- Shift 3 position 4 way valve in block.
- Release pressure on pilot lines, pilot
fluid is vented back to the reservoir.
- SPM valve on selected blue pod shift
to close position.
- Allowing the pressure from BOP’s
function to be released, the power
fluid is vented to the sea through the
SPM valve.
17
Changing Pod Sequences
- Select yellow pod from remote panel.
- Activate solenoid valve.
- Shift 3 position 4 way valve on yellow
pod.
- Close BOP,s from remote panel.
- Activate solenoid valve.
- Shift 3 position 4 way valve.
- Send pilot signal to the close SPM
valve on both pod with 3000 psi.
- Close SPM valve on selected yellow
pod shift.
- The power fluid from Subsea bottles
can flow and the shuttle valve can shift
allowing the power fluid to pressure
up the close function on BOP.
- Accumulator pumps pressure up all
accumulator and BOP’s bottles to 3000
18
psi.
Subsea Animation
19
Subsea Accumulator Bottles
The subsea
accumulator bottles
capacity
calculations should
compensate the
hydrostatic
pressure gradient at
the rate of .445
psi/ft of water
depth.
20
Precharge pressure with water depth
Water Depth
Pre-charge
500 ft
1223
1000ft
1445
1500ft
1668
2000ft
1950
21
BOP Response Time
Response time between activation and complete operation of a
function is based on BOP closure and seal off.
SURFACE
18 3/4”
18 3/4”
30 sec.
45 sec.
30 sec.
SUBSEA
60 sec.
45 sec.
Time to unlatch the lower
marine riser package
should not exceed 45 seconds
Remote valves should not exceed the minimum observed ram BOP
22
Hydril GL Secondary Chamber
Requires lowest hydraulic closing
pressure
This allows to balance the opening
force on the piston created by the
drilling fluid H. P. in the marine riser
OPENING PRESSURE
23
Vetco H-4 Connector
0 to 2o Drilling
2o to 4o Stand by &
Prepare to
disconnect
4o to 6o
Disconnection
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- Choke
Line Friction
25
Choke Line Friction Losses
If SICP is held constant until kill rate is achieved,
BHP will be increased by an amount equal to CLFL.
To accomplish constant BHP, a method must be used
while bringing the mud pump to kill rate
Choke Line Friction Losses:
There are four recognized methods of
recording choke line friction losses at slow
circulating rates of 1- 5 bbls / min
26
First Method
500
RECORD THE
PRESSURE
REQUIRED TO
CIRCULATE THE
WELL THROUGH THE
MARINE RISER WITH
THE BOP OPEN
500 PSI IN THIS CASE
27
First Method
700
RECORD THE PRESSURE
REQUIRED TO CIRCULATE
THROUGH A FULL OPEN CHOKE:
700 PSI IN THIS CASE
CHOKE LINE FRICTION LOSSES =
700 - 500 = 200 PSI
28
Second Method
200
CIRCULATE THE WELL
THROUGH A FULL OPEN
CHOKE WITH THE BOP
CLOSED AND RECORDING
THE PRESSURE ON THE
(STATIC) KILL LINE. THE KILL
LINE PRESSURE WILL
REFLECT THE CHOKE LINE
PRESSURE LOSS.
200 PSI IN THIS CASE
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Third Method
200
CIRCULATE DOWN THE CHOKE LINE
AND UP THE MARINE RISER WITH THE
BOP OPEN.
THE PRESSURE REQUIRED FOR
CIRCULATION IS A DIRECT REFLECTION
OF THE CHOKE LINE FRICTION LOSS.
200 PSI IN THIS CASE
30
Fourth Method
400
CIRCULATE DOWN THE KILL LINE
TAKING RETURNS THROUGH A FULL
OPEN CHOKE WITH THE WELL BORE
AND RISER ISOLATED BY CLOSING
THE BOP’s.
PRESSURE OBSERVED IS DOUBLE
THE CLFL:
IN THIS CASE 400 PSI / 2
CLFL = 200 PSI
31
Bringing Pump to Kill Rate Speed
1200
500
700
200
If CLFL is not accounted for, casing
pressure varies from SICP at pump start
up to SICP + CLFL with the pump at kill
rate.
This results in BHP increasing by an
amount equal to CLFL.
Increase
BHP : 5000
to 5200
psi psi
32
Bringing Pump to Kill Rate Speed: First Method
1000
500
Reduced Choke Pressure =
500
700
SICP - CLFL =
700 - 200 = 500 psi
200
Create a chart where CLFL and pump
rates are divided by 3:
BHP : 5000 psi
SPM
Pressure
0
700
10
630
20
560
30
500
33
Bringing Pump to Kill Rate Speed: Second Method
700
keeping the Kill Line gauge
constant while bringing the
pump up to speed eliminates
the effect of CLFL.
No pre calculated CLFL information is
required.
It would be advisable to rig a remote kill
pressure gauge which could be seen by the
choke operator.
34
Riser Loss/Riser Margin
Riser Collapse
Overburden Pressure
35
Riser Loss/Riser margin
In case of a riser loss
(emergency drive off,
anchor chain breaks, ship
drift), there will be a
reduction in hydrostatic
pressure.
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Riser Loss
This drop in hydrostatic
pressure on the well bore:
• is equal to the hydrostatic
differential between fluid in
the riser and sea water
•The hydrostatic from the air
gap is lost
37
Riser Loss/Riser Margin
Example:
Calculate the reduction in BHP is the
riser is torn off:
65’
1- hydrostatic from air gap is lost:
65 x 12.9 x . 052 = 43.6 psi
2- hydrostatic differential in riser:
4,450’
2,150’
2,150 x (12.9 - 8.6) x .052 = 480.7 psi
3- reduction in BHP:
43.6 + 480.7 = 524.3 psi
MW: 12.9 ppg
SW: 8.6 ppg
2,950’
38
Riser Loss/Riser Margin
Example:
To calculate the riser margin:
65’
Riser margin=
HP reduction/ (TVD-Riser length)X0.052
524.3/(7400-2215)x0.052
4,450’
2,150’
= 1.94 ppg
MW plus riser margin
12.9ppg+1.94ppg =14.84
MW: 12.9 ppg
SW: 8.6 ppg
2,950’
39
Riser collapse
In deep water, the
potential for riser
collapse exists if
the level of drilling
fluid in the riser
drops due to gas
unloading the riser
or in case of heavy
losses.
40
Riser collapse
Assuming the worst case to be during an
emergency or accidental line
disconnection, the pressure at the bottom
of the riser would equal the seawater
hydrostatic.
The fluid level in the riser would fall until
the equilibrium is reached.
41
Riser collapse (vacuum inside )
Example:
60’
If a riser has a collapse
pressure of 500 psi, how far
could the mud level fall
before sea water collapses
the riser?
500 / .445 = 1123’
2,150 ‘
SW: .445 psi/ft
1123 + 60 = 1183 feet
A riser fill up valve should be
used if the collapse pressure
could exceed the collapse
pressure rating of the riser.
42
Riser collapse (gas inside riser
)
Example:
If a riser has a collapse pressure
of 500 psi,and is filled with
0.1psi/ft of gas how far could the
mud level fall before sea water
60’
collapses the riser?
2,150 ‘
Riser collapse =water depth x SW gradient(Airgap+water depth)x riser fluid gradient
500=yx0.445-(60+y)x0.1
500=0.445y-(6+0.1y)
500=0.445y-6-0.1y
SW: .445 psi/ft
506=0.345y
Y=1466ft
Level drop to collapse point=1466+60=1526ft
43
Riser collapse (gas inside riser
)
Example:
If a riser has a collapse pressure
of 500 psi,and is filled with
0.1psi/ft of gas how far could the
mud level fall before sea water
60’
collapses the riser?
Level drop from sea level before riser
collapses
2,150 ‘
Collapse press + Air gap x Riser fluid grad
SW gradient –Riser fluid Gradient
SW: .445 psi/ft
=1466 ft
Add Airgap 60 ft ?= 1466 +60= 1526
44
Overburden Pressure
Overburden Pressure is
the pressure exerted at
any given depth by the
weight of the sediments,
or rocks, and the weight
of the fluids that fill pore
spaces in the rock.
Generally considered to
be 1 psi / ft on land while
offshore part of this
overburden is replaced
by about .65 psi/ft.
45
Maximum press at the shoe
Example:
Calculate the MAMW:
1- calculate formation depth:
80’
600 - 220 - 80 = 300 ft
2- calculate overburden pressure:
300 x .65 = 195 psi
3- calculate SW pressure:
220’
220 x .455 = 100 psi
600’
4- calculate the pressure at shoe:
SW: .455 psi/ft
195 + 100 = 295 psi
Overburden: .65 psi/ft
5- convert this pressure to a MW:
295 / ( 600x .052) = 9.4 ppg
46
Dynamic MAASP
• Dynamic MAASP is the MAASP while killing
a well on a subsea stack
• Dynamic MAASP =Static MAASP -CLF
47
Shut- in Procedure: HARD SHUT-IN
• Stop rotation
• Pick up the drill string to hang off position
• Stop the pump
• Flow check
If the well flows
• Close
BOP
• Open remote control choke line valves (Fail safe valves)
• Notify Tool Pusher and OIM
• Record time, SIDPP, SICP and pit gain
• Check Space out
• Hang off and lock pipe rams
48
Shut- in Procedure: SOFT SHUT-IN
• Pick up the drill string to hang off position
• Stop rotation
• Stop the pump
• Flow check
If the well flows
• Open remote control choke line valves (Fail safe valves)
• Close BOP
• Close choke
• Notify Tool Pusher and OIM
• Record time, SIDPP, SICP and pit gain
• Check Space out
• Hang off and lock pipe rams
49
Subsea kill sheet (differences with surface)
• Inclusion of choke line friction calculations
• Casing set depth vs length of casing in the
hole
• Inclusion of Riser displacement volumes
• Dynamic Casing Pressure
50
Removing
trapped gas
from the BOP
51
Removing trapped gas from the BOP
It is quite likely that some gas will have
accumulated under the closed BOP
during displacement of the influx.
The gas must be removed from the
stack before the BOP is opened.
The volume of the trapped gas depends
on the volume between the preventer in
use and the choke line outlet in use.
52
Removing trapped gas from the BOP
Step # 1:
- Isolate the well with the lower rams.
- Displace the kill line with kill weight
mud taking returns up the choke line.
- Continue to circulate until the kill
and choke line are full of
uncontaminated kill weight mud.
53
Removing trapped gas from the BOP
Step # 2:
- Displace choke line to water or
base oil to BOP stack taking returns
up the kill line.
- Do not over displace.
- Close the fail safe valves on the kill
line.
54
Removing trapped gas from the BOP
Step # 3:
- Vent the choke line to the MGS.
This will unload the water or the base
oil and depressurized gas.
55
Removing trapped gas from the BOP
Step # 4:
- Open the annular preventer and
allow the mud to U-tube from the riser
into the choke line.
- Continuously fill the riser with mud.
56
Removing trapped gas from the BOP
Step # 5:
- Close the annular preventer and
displace the choke line with kill
weight mud through the kill line.
57
Removing trapped gas from the BOP
Step # 6:
- Close the Diverter and line up the flow
return to the MGS (if possible).
- Open the annular and pump down into
the choke line or use the booster line (if
available) to displace the riser to kill
weight mud.
58
Removing trapped gas from the BOP
Step # 7:
- Close the annular preventer
- Open the pipe rams and monitor the
well for flow.
- If the well is dead, open the annular.
- Circulate and condition the mud.
59
CALCULATING TRAPPED GAS VOLUME AT SURFACE
EXAMPLE
4 bbls trapped below stack
Riser/choke line length is 1000ft
Mw in riser 12 ppg
Kill mud weight is 14 ppg
Atmospheric pressure is 14.6psi
What is the volume of the gas at surface?
Using Boyles law P1V1=P2V2
= ((14 x0.052x1000)+14.6)x4)/14.6
=203.45 bbls
60
Hydrates
Hydrates
61
Hydrates
What are hydrates?
• Hydrates are a solid mixture of water and natural gas
(commonly methane).
• Once formed, hydrates are similar to dirty ice .
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Hydrates
Why are they important?
• Hydrates can cause severe problems by forming a
plug in Well Control equipment, and may completely
blocking flow path.
• One cubic foot of hydrate can contain as much as 170
cubic feet of gas.
• Hydrates could also form on the outside of the BOP
stack in deepwater.
63
Hydrates
Where do they form?
• In deepwater Drilling
• High Wellhead Pressure
• Low Wellhead temperature
64
Hydrates
How to prevent hydrates?
• Good primary well control = no gas in well bore
• Composition of Drilling Fluid by using OBM or
Chloride (Salt) in WBM.
• Well bore temperature as high as possible
• Select proper Mud Weight to minimize wellhead
pressure.
• injecting methanol or glycol at a rate of 0.5 - 1 gal per
minutes on the upstream side of a choke
65
Hydrates
66
Riserless Surface Hole Drilling
• Involves drilling directly on the seabed
without a riser
• Returns are deposited on the sea bed and
are not allowed to get to the rig floor
• Gives the rig flexibility in the event of
abandonment
67
Floating rig mud monitoring
• Rig Heave
• Pitch and Roll
• Crane Operations
68