1 subsea well control. 2 subsea stack differences choke and kill line connected directly to stack...
TRANSCRIPT
1
SUBSEA WELL CONTROL
2
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
3
SUBSEA BOP ARRANGEMENT
4
SUBSEA BOP ARRANGEMENT
5
SUBSEA BOP ARRANGEMENT
6
SUBSEA BOP ARRANGEMENT
7
SUBSEA STACK AND CHOKE MANIFOLD ARRANGEMENT
8
Subsea BOP Controls
9
SUBSEA CONTROL SYSTEM
10
SUBSEA CONTROL SYSTEM
11
SUBSEA CONTROL SYSTEM
TYPICAL HYDRAULICHOSE BUNDLE
1. 1” I.D. Supply Hose
2. 3/16” I.D. Pilot Hose
3. Outer Protective Jacket
12
SUBSEA CONTROL SYSTEM
13
Shuttle Valve
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 to Bop’s Functions
Power Fluid port isolated from Blue Pod
Power Fluid from Yellow Pod
14
SUBSEA CONTROL SYSTEM
15
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.
16
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.
17
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.
18
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 psi.
19
Subsea Animation
20
The subsea accumulator bottles
capacity calculations should
compensate the hydrostatic
pressure gradient at the rate of .445 psi/ft of water
depth.
Subsea Accumulator Bottles
21
Precharge pressure with water depth
Water Depth Pre-charge
500 ft 1223
1000ft 1445
1500ft 1668
2000ft 1950
22
Response time between activation and complete operation of a function is based on BOP closure and seal off.
BOP Response Time
Remote valves should not exceed the minimum observed ram BOP
18 3/4”
30 sec.
SUBSEASURFACE18 3/4”
45 sec.
30 sec.
60 sec.
45 sec.Time to unlatch the lower
marine riser package should not exceed 45 seconds
23
Hydril GL Secondary Chamber
OPENING PRESSURE
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
24
Vetco H-4 Connector
0 to 2o Drilling
2o to 4o Stand by & Prepare to disconnect
4o to 6o Disconnection
25
- Choke Line Friction
26
Choke Line Friction Losses: There are four recognized methods of
recording choke line friction losses at slow circulating rates of 1- 5 bbls / min
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
27
500
First Method
RECORD THE PRESSURE
REQUIRED TO CIRCULATE THE
WELL THROUGH THE MARINE RISER WITH
THE BOP OPEN
500 PSI IN THIS CASE
28
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
First Method
29
200
Second Method
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
30
200
Third Method
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
31
Fourth Method
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
400
32
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.
500
700700
1200
BHP : 5000 psi
200
Increase to 5200 psi
Bringing Pump to Kill Rate Speed
33
Reduced Choke Pressure =
SICP - CLFL =
700 - 200 = 500 psi
Create a chart where CLFL and pump rates are divided by 3:
500
700500
1000
BHP : 5000 psi
200
0 700
10 630
20 560
SPM Pressure
30 500
Bringing Pump to Kill Rate Speed: First Method
34
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.
Bringing Pump to Kill Rate Speed: Second Method
35
Riser Loss/Riser Margin
Riser Collapse
Overburden Pressure
36
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.
37
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
Riser Loss
38
Example:Calculate the reduction in BHP is the riser is torn off:
1- hydrostatic from air gap is lost:
65 x 12.9 x . 052 = 43.6 psi
2- hydrostatic differential in riser:
2,150 x (12.9 - 8.6) x .052 = 480.7 psi
3- reduction in BHP:
43.6 + 480.7 = 524.3 psi
2,150’4,450’
65’
2,950’MW: 12.9 ppg
SW: 8.6 ppg
Riser Loss/Riser Margin
39
Example: To calculate the riser margin:
Riser margin=
HP reduction/ (TVD-Riser length)X0.052
524.3/(7400-2215)x0.052
= 1.94 ppg
MW plus riser margin
12.9ppg+1.94ppg =14.84
2,150’4,450’
65’
2,950’MW: 12.9 ppg
SW: 8.6 ppg
Riser Loss/Riser Margin
40
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.
Riser collapse
41
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.
Riser collapse
42
Example:
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’
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.
SW: .445 psi/ft
2,150 ‘
60’
Riser collapse (vacuum inside )
43
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 collapses the riser?
SW: .445 psi/ft
2,150 ‘
60’
Riser collapse (gas inside riser )
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
506=0.345y
Y=1466ft
Level drop to collapse point=1466+60=1526ft
44
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 collapses the riser?
SW: .445 psi/ft
2,150 ‘
60’
Riser collapse (gas inside riser )
Level drop from sea level before riser collapses
Collapse press + Air gap x Riser fluid grad
SW gradient –Riser fluid Gradient
=1466 ftAdd Airgap 60 ft ?= 1466 +60= 1526
45
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.
Overburden Pressure
46
Example:
Calculate the MAMW:
1- calculate formation depth:
600 - 220 - 80 = 300 ft
2- calculate overburden pressure:
300 x .65 = 195 psi
3- calculate SW pressure:
220 x .455 = 100 psi
4- calculate the pressure at shoe:
195 + 100 = 295 psi
5- convert this pressure to a MW:
295 / ( 600x .052) = 9.4 ppg
80’
220’
600’
SW: .455 psi/ft
Overburden: .65 psi/ft
Maximum press at the shoe
47
Dynamic MAASP
• Dynamic MAASP is the MAASP while killing a well on a subsea stack
• Dynamic MAASP =Static MAASP -CLF
48
• 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
Shut- in Procedure: HARD SHUT-IN
49
• 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
Shut- in Procedure: SOFT SHUT-IN
50
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
51
Removing trapped gas
from the BOP
52
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.
53
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.
54
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.
55
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.
56
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.
57
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.
58
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.
59
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.
60
CALCULATING TRAPPED GAS VOLUME AT SURFACE
EXAMPLE4 bbls trapped below stack Riser/choke line length is 1000ftMw in riser 12 ppgKill mud weight is 14 ppgAtmospheric 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
61
Hydrates
Hydrates
62
What are hydrates?
• Hydrates are a solid mixture of water and natural gas (commonly methane).
• Once formed, hydrates are similar to dirty ice .
Hydrates
63
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.
Hydrates
64
Where do they form?
• In deepwater Drilling
• High Wellhead Pressure
• Low Wellhead temperature
Hydrates
65
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
Hydrates
66
Hydrates
67
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
68
Floating rig mud monitoring
• Rig Heave
• Pitch and Roll
• Crane Operations