SUBSEA WELL CONTROL

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SUBSEA WELL CONTROL

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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

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SUBSEA BOP ARRANGEMENT

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SUBSEA STACK AND CHOKE MANIFOLD ARRANGEMENT

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Subsea BOP Controls

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SUBSEA CONTROL SYSTEM

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TYPICAL HYDRAULICHOSE BUNDLE

1. 1” I.D. Supply Hose

2. 3/16” I.D. Pilot Hose

3. Outer Protective Jacket

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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

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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.

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Opening Sequences- Open BOP,s from remote panel.



- 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.


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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.

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Changing Pod Sequences- Select yellow pod from remote panel.


- Shift 3 position 4 way valve on yellow pod.

- Close BOP,s from remote panel.



- 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.


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Subsea Animation

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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

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Precharge pressure with water depth

Water Depth Pre-charge

500 ft 1223

1000ft 1445

1500ft 1668

2000ft 1950

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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

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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

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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

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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

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500

First Method

RECORD THE PRESSURE

REQUIRED TO CIRCULATE THE

WELL THROUGH THE MARINE RISER WITH

THE BOP OPEN

500 PSI IN THIS CASE

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700

RECORD THE PRESSURE REQUIRED TO CIRCULATE

THROUGH A FULL OPEN CHOKE:


CHOKE LINE FRICTION LOSSES = 700 - 500 = 200 PSI

First Method

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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.


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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.


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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

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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

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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

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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

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Riser Loss/Riser Margin

Riser Collapse

Overburden Pressure

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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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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

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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


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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


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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

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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

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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 )

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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

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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

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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

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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

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Dynamic MAASP

• Dynamic MAASP is the MAASP while killing a well on a subsea stack

• Dynamic MAASP =Static MAASP -CLF

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• 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

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• 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

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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

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Removing trapped gas

from the BOP

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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.

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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.

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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.

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Step # 3:

- Vent the choke line to the MGS.

This will unload the water or the base oil and depressurized gas.

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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.

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Step # 5:

- Close the annular preventer and displace the choke line with kill weight mud through the kill line.

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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.

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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.

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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

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Hydrates

Hydrates

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What are hydrates?

• Hydrates are a solid mixture of water and natural gas (commonly methane).

• Once formed, hydrates are similar to dirty ice .

Hydrates

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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

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Where do they form?

• In deepwater Drilling

• High Wellhead Pressure

• Low Wellhead temperature

Hydrates

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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

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Hydrates

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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

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Floating rig mud monitoring

• Rig Heave

• Pitch and Roll

• Crane Operations

Documents

SUBSEA WELL CONTROL