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well control course
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Well Control Course
1
Well Control Equipment
IntroductionSince years, shallow gas blowouts have jeopardized the oil industry drilling operations, killed many people, and destroyed many rigs.
An analysis of well control statistics done by Veritec has revealed that:
• 33% of all gas blow outs: results from shallow gas kicks.
• 54% of shallow gas blowouts cause severe damage or total loss of the drilling support, due to the failure of the diverter system.
Shallow Gas
Well Control Course
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Shallow Gas
DIVERTERS,
is not the answer for shallow gas.
If any, move the rig off location.
Shallow Gas
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Shallow Gas
Shallow Gas
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Shallow Gas
Definition
• SHALLOW GAS is considered to be any gas accumulation encountered during drilling at depth above the setting point of the first string of casing intended for, or capable of pressure containment.
• SHALLOW GAS generally occurs as normally pressured accumulations in shallow sedimentary formations with high porosity and high permeability
• Drilling through such gas bearing formation requires extreme caution.Because of the difficulty in early detection of an influx while drilling top hole sections , the gas, upon entering the wellbore expands and reaches the surface very rapidly and with little warning.
Shallow Gas
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Evaluation & Planning
• SHALLOW SEISMIC SURVEY
• SHALLOW GAS PLAN SPECIFIC TO THE RIG / WELL
• DRILL A PILOTE HOLE, NORMALLY 9 7/8” OR LESS
Shallow Gas
Preparation• RESERVE OF HEAVY MUD
- WILL BE 1 TO 2 ppg HEAVIER THAN THE MUD WEIGHT BEING USED.
-THE MINIMUM VOLUME WILL BE THE CALCULATED ANNULAR VOLUME FOR THE SECTION TD.
• ALL MEASURING INSTRUMENTS
- MUST BE CALIBRATED AND IN GOOD CONDITION- THE MOST RELIABLE INDICATOR REMAINS THE FLOW OUT SENSOR.
• CLEAR DRILLING OR TRIPPING PROCEDURE
Shallow Gas
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• FLOW-CHECKS WILL BE MADE EVERY TIME A PROBLEM IS SUSPECTED, AND EACH CONNECTION WILL BE SYSTEMATICALLY FLOW-CHECKED WHILE DRILLING IN POTENTIAL SHALLOW GAS ZONES.
• DRILLING RATE SHOULD BE CONTROLLED TO PREVENT EXCESSIVE BUILD UP OF SOLIDS WHICH COULD CAUSE FRACTURING OF THE FORMATION AND RESULT IN LOST CIRCULATION.
• SWABBING MUST BE PREVENTED WHILE TRIPPING OUT OF HOLE IF NECESSARY THE DRILLSTRING SHOULD BE PUMPED OUT
Prevention
Schlumberger Policies: I.14A float (solid or ported) will be run while drilling and opening hole prior to setting surface casing or any time the posted well control plan is to divert.
Shallow Gas
IF THE WELL START TO FLOW WHILE DRILLING
– DO NOT STOP PUMPING– OPEN DIVERTER LINE AND CLOSE DIVERTER– INCREASE PUMP SPEED– SWITCH TO HEAVY MUD (MONITOR VOLUME)– RAISE THE ALARM– START EVACUATION PROCEDURE
Shallow Gas
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Diverter with Annular Packing Element
Functions should be interlocked
Flow line to Shakers
Diverter open port
Diverter close port
Vent line to over board
Body
Piston
Head
Annular packing element
Diverter with Insert Type Packer
Flow- Line Seal
Flow- Line Seal
Drill pipe
Insert packer lockdown dogs
Diverter close port
Flow / Vent line
Support housing
Insert packer
Standard packer
Diverter lockdown dogs
Functions should be interlocked
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Diverter
What is the position of the valves while drilling?
If the diverter needs to be operated, what will be the sequence?
Wind
Minimum Diverter Requirements
• CLOSING TIME SHOULD NOT EXCEED 30 SECONDS FOR DIVERTERS SMALLERS THAN 18 3/4’’ AND 45 SECONDS FOR DIVERTERS OF 18 ¾’’ NMINAL BORE AND LARGER
• A DIVERTER HEAD THAT IS CAPABLE OF PACKING OFF AROUND THE KELLY, DRILL PIPE OR CASIND WILL BE USED
• AT LEAST TWO RELIEF LINES SHALL BE INSTALLED TO PERMIT VENTING OF THE WELL-BORE RETURNS AT OPPOSITE ENDS OR SIDES OF THE RIG.
• ON LAND RIGS A SINGLE LINE IS ACCEPTABLE
• THE DIVERTER RELIEF LINE(S) SHALL BE AT LEAST 8 INCH DIAMETER.
Schlumberger Policies: I.19THE DRILLER WILL CHECK ALL DIVERTER AND OVERBOARD VALVES FOR PROPER SETTING AT THE BEGINNING OF EACH TOUR.
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API RP 53 - Installation
A diverter is not intended to be a well control device:
it just allows for the flow to be diverted in a safe manner, to contain the hazard for as long as possible, so as to leave enough time for proper and safe evacuation of
personnel and/or move off from the location.
Remember !!!
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It has been widely demonstrated that the
original design concepts underestimated the fact that, most of the time, surface gas
blowout produce a huge amount of gas and abrasive solids, flowing at very high
velocity, quickly eroding and destroying most of the
existing diverter components, and causing
fire and/or explosion.
Shallow Gas
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Accumulator Unit
1500
1500
3000
Accumulator Unit
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THE ACCUMULATOR BOTTLES ARE CONTAINERS THAT STOREHYDRAULIC FLUID UNDER PRESSURE TO:
- DECREASE BOP FONCTIONS RESPONSE TIME.- BE ABBLE TO SHUT IN THE WELL, IN CASE OF POWER FAILURE.
- VOLUME OF ACCUMULATOR BOTTLE: 10 gal
- WORKING PRESURE: 3000 psi
- NITROGEN GAS IS USED TO PRE-CHARGE ACCUMULATOR BOTTLES.
- MINIMUM PRECHARGE PRESSURE: 1000 psi
- MINIMUM OPERATING PRESSURE: 200 psi ABOVE PRE-CHARGE
Accumulator Systems
Bladder Type
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P X V = CST
1000 psi X 10 gal = 10,000
VOL gas = CST / PRESS
CST 10,000PRESS.
V. gas
BOTTLE
V. oil
USABLE FLUID =
Floating Type
Usable Hydraulic fluid is:
The fluid recoverable from the accumulator system between the maximum accumulator pressure and 200 psi above pre-charge pressure.
API RP 53 - Accumulator
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The BOP control system should have sufficient usable hydraulic fluid volume, with pumps inoperative, to:
- Close one annular
- Close all rams
- Open one HCR
The remaining pressure will be 200 psi or more above the minimum pre-charge pressure.
API RP 53 – Accumulator Capacity
Schlumberger Standard
The accumulator volume of the BOP systems will be sized to keep a remaining stored accumulator pressure of 200 psi or more above the minimum recommended pre-charge pressure after conducting the following operations (with pumps inoperative):
• Close all ram and annular functions and open all HCR valves.
• Open all ram and annular functions and close all HCR valves.
• Close the annular.
• Open the remotely operated choke line valve.
Accumulator Capacity
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Each closing unit should have a fluid reservoir with a capacity equal to at least twice the
usable fluid capacity of the accumulator system
API RP 53 – Reservoir Capacity
EXAMPLE:
BOP Equipment: 1 Annular + 3 Rams + HCR Valve
Closing Volume (CV): 20 + (3 x 10) + 1 = 51 GalOpening Volume (OV): 20 + (3 x 10) + 1 = 51 GalClosing Volume (CV): 20 = 20 GalOpen Choke Line Valve (OV): 1 = 1 Gal
Usable Volume (UV): = 123 Gal
Nominal Volume (NV): 2 x UV = 246 Gal
25 accumulator bottles
Schlumberger Standard
Accumulator Capacity
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Is the minimum pressure to effectively close and seal a ram BOP against a well bore pressure equal to the maximum rated working pressure of the BOP.
This pressure is equal to the maximum working pressure of the BOP divided by the closing ratio specified for that BOP.
API RP 53 - Minimum Calculated Operating Pressure:
With the accumulator isolated from service:
The pump system should be capable of closing the annular on the minimum size drill pipe being used, open the remote operated choke valve and provide the operating pressure level recommended by the annular BOP manufacturer to effect a seal on the annulus within 2 minutes.
API RP 53 – Pumps Systems
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Each surface BOP control system should have aminimum of 2 pump system having independent
power sources, such as electric or air.
API RP 53 – Pumps Systems
•Each pump should provide a discharge pressure at least equivalent to the BOP control system pressure.
•Air pumps should be capable of charging the accumulators to the system working pressure with 75 psi.
API RP 53 – Pumps Systems
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Each pump should be protected from over pressurization bya minimum of 2 devices.
•One device (pressure limit switch) should limit the discharge pressure so that it will not exceed the working pressure of the BOP control system.
•The second device (relief valve) should be size to relieve at a flow rate at least equal to the design flow rate of the pump and should be set to relieve at not more than 10 % over the control unit pressure.
API RP 53 – Pumps Systems
Electric, and or, air supply should be available at all times such that thepumps will automatically start when the system pressure has decreased to approximately 90 % of the system working pressure and automaticallystop within +0 to - 100 psi of the control system working pressure.
API RP 53 – Pumps Systems
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Response time between activation and complete operation of a function is based on BOP closure and seal off.
Remote valves should not exceed the minimum observed ram BOP
18 3/4”
30 sec.
SURFACE18 3/4”
45 sec.
30 sec.
API RP 53 – BOP Response Time
At least three flow paths must be provided that are capable of flowing well returns through conduits that are 76.14 mm (3”) nominal diameter or larger.
At least one flow path:• Shall be equipped with a remotely controlled, pressure operated adjustable choke. Simplified choke manifolds without remote control choke may be acceptable on light rigs with 2 – 3K psi stacks
• Shall be equipped with a manually operated adjustable choke
• Must permit returns to flow directly to the pit, discharge manifold or other downstream piping without passing through a choke. Two gate valves with full rated working pressure must be provided in this unchoked path
Choke Manifold
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The initial pressure test on components that could be exposed to well pressure should be
to the rated working pressure of the ram BOP or to the rated working pressure of the
well head ( whichever is lower).
Annular may be tested to a minimum of 70% of the annular preventer working pressure.
API RP 53 – Initial Pressure Test
API RP 53 – Initial Pressure Test
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Packing Unit
Low Pressure Test. 200 – 300 psi for 5 minutes prior to each high pressure test.
High Pressure Test. Rams-type BOPs and related control equipment including
the choke manifold shall be tested at the anticipated surface pressure.
. Annular will be tested to 50 % of the rated working pressure of the components.
. All high pressure tests will be conducted for 10 minutes.
Pressure Test Schlumberger
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• Manifold equipment subject to well pressure (up-stream including the choke) should have a minimum working pressure at least equal to the rated working pressure of the ram BOP in use.
• All choke manifold valves should be full bore.
• Function Tests: at least once a week.
API RP 53 – Choke Manifolds & Kill Lines
The body of new BOP’s are subjected to ahydrostatic proof testing or shell test prior shipment:
Rated WorkingPressure (psi)
2,000
3,000
5,000
10,000
15,000
20,000
API Size Designation13 5/8 and Smaller
4,000
6,000
10,000
15,000
22,500
30,000
API Size Designation16 3/4 and Larger
3,000
4,500
10,000
15,000
22,500
---
The hydraulic operating chamber shall be tested at a minimum test pressure equalto 1.5 times the operating chamber’s rated working pressure.
Shell Test
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Tester Cup & Tester Plug
Type “R”
Type “RX”
Type “BX”
“X” type are pressure energized meaning that well pressure helps to
effect the seal
Ring Gaskets
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The most common ring grooves are:• API 6B - 2,000 / 5,000 psi
• API 6BX - 2,000 / 20,000 psi
---------------------------------------------------
Ring gaskets to be used for specific grooves are:• API 6B - use API type “R” or type “RX”
• API 6BX - use API type “BX”
Ring Grooves
Which pressure energized ring gasket can match with aring groove API 6B ?
- BX
- R
- RX
Exercise
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API 6B Flange API 6BX Flange
R or RX Ring Gaskets
Stand-offgives
instability
BX Ring Gaskets
Closed Facegives
stability
Flange Types
What does this mean ?
a 3-1/16 , 10 000 flange
Nominal Size
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Studded
Clamp Hub
Flanged
Connection
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They are design to:
- Be closed on an open well (should be avoided)
- Reciprocate or rotate the string while maintaining a seal against the well bore.(need approval during WC situation)
- Seal around a square or hexagonal Kelly.
- Pass the tool joints through while stripping.
They can be operated with a variable Operating Hydraulic Pressure.
Annular BOP’s
Hydril GX
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1- Latched Head
2 - Opening Chamber Head
3 - Opening Chamber
4 - Closing Chamber
5 - Secondary Chamber
6 - Piston Seals
7 - Piston
8 - Packing Unit
Hydril GL
Quick-Release Top
DonutPacker
Outer Cylinder Lock Down
Operating PistonVent Port
Closing Hydraulic Port
Vent Port
Opening Hydraulic Port
Pusher Plate
Packer Insert
Access FlapsLocking Grooves
Cameron DL
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Manufacturer’s Data
State the Rating Operating Pressure
Standard Surface Hookup
Connects the secondary chamber to the opening chamber
- Least amount of fluid
- Fastest closing time
Connects the secondary chamber to the closing chamber
- Least amount of closing pressure for optimum closing force
Optional Surface Hookup
Hydril GL: Secondary Chamber
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Schlumberger Policies: I.22
Any time a trip is interrupted the hand tight installation of a safety valve is required.
Schlumberger Policies: I.23
A minimum of one safety valve and one inside BOP with appropriate cross-overs will be available on the rig floor at all times, including a circulating head when running casing. A proper meansof handling will be provided to assist with its installation.
Safety Valves
Body
Lower Seat
Upper seat
Ball
Crank
Full Opening Safety Valve
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Release tool
Valve Release rod
SeatValve
Valve SpringLower Body
Upper Body
Release Rod Locking Screw
Inside BOP’s
USED TO:• Prevent sudden influx entry into the drill string.
• Prevent back flow of annular cuttings from plugging bit nozzles.
Schlumberger Policies: I.14A float (solid or ported) will be run while drilling and opening hole prior to setting surface casing or any time the posted well control plan is to divert.
Float Valves
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Body
Ram Assy.
Intermediate Flange
Operating Cylinder
Operating Piston
Seal Rings Assy.Bonnet
Ram change cylinder
Ram change piston
Bonnet
Cameron Type - U
Block
Rubber
Retaining screw
Retaining screw
Holder
Shaffer Rams - NL
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Top Seal
Body
Packer
Cameron Variable Bore Ram Assy.
Top Seal
Side Packer
Upper Shear Ram
Face Seal
Lower Shear Ram assembly
Blade
Shearing Blind Rams
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Cameron Manual Lock
Cameron Wedge Lock
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Hydraulically-actuated mechanical clutch mechanism
Hydril MPL (Multiple Position Lock)
Shaffer Ultralock
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Shaffer POSLOCK (One Position Locking Mechanism)
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The mud gas separator is a low pressure vessel
Circulating through MGS, no gas no
pressure
Circulating gas through MGS, within
design capacity
Typical Land Rig Set-upTypical Offshore Set-up
Circulating through MGS, above design capacity, unloading
gas to shakers
Possible improvement of mud seal height
Typical Offshore Set-up Typical Land Rig Set-up
Mud Gas Separator
The function of the MGS is to mechanically separate gas from the mud.
From Choke Manifold
To Shakers
1 - Diameter and length of the vent line controls the amount of back pressure in MGS
2 - Diameter, height and internal design controls the separation efficiency in MGS
3 - Height of the “U” tube control the working pressure and the fluid level to stop the gas going out of the MGS
Mud
GA
S
Baffle Plate
Siphon Breaker
Drain Line with valve
Mud Gas Separator
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• A gas kick is being circulated out of a well.
• The slow circulating rate is 40 spm.
• The pump output is .119 bbls/stk.
• That means 4.76 Barrels of mud are passing through the Mud Gas Separator (MGS) every minute.
650 650 psipsi
0 0 psipsi
Mud Seal : 20 ft
Vent Line
Mud Gas Separator
• The mud weight is 10 ppg and has a pressure gradient of 0.52 psi/ft.
• The MGS shown here has a Mud Seal that is 20 feet high.
• So once it is full of our 10 ppgmud it would take a gas pressure of 10.4 psi from within the separator to evacuate the mud seal.
650 650 psipsi
0 0 psipsi
Mud Seal : 20 ft
Vent Line
Mud Gas Separator
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• We now have gas at surface, and the annulus pressure has risen to 1000 psi.
• Because we are still pumping at 40 spm which is 4.76 bbls/min. To keep bottom hole pressure constant we must bleed off the same amount of gas.
• Because the gas up stream of the choke is at 1000 psi and we are bleeding it down to atmospheric pressure (14.72 psi) ,the volume, as we know from Boyles law does not remain the same.
1000 1000 psipsi
8 8 psipsi
Mud Seal
Vent Line
MGS – Gas at Surface
• We now have gas at surface, and the annulus pressure has risen to 1000 psi.
• Because we are still pumping at 40 spm which is 4.76 bbls/min. To keep bottom hole pressure constant we must bleed off the same amount of gas.
• Because the gas up stream of the choke is at 1000 psi and we are bleeding it down to atmospheric pressure (14.72 psi) ,the volume, as we know from Boyles law does not remain the same.
1000 1000 psipsi
8 8 psipsi
Mud Seal
Vent Line
MGS – Gas at Surface
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• Using boyles law we can find how much gas per minute we would have down stream of the choke.
• Boyles laws states;P1 V1 = P2 V2
• We know our pressure up stream of the choke whitch is 1000 psi, so this is our P1.
• At 40 spm our volume of flow is 4.76 bbls/min so this is our V1.
• And our pressure down stream of the choke is atmospheric at 14.72 psi.
Gas expansion throughthe choke.
P1 = 1000 psiV1 = 4.76 bbl/minP2 = 14.72 psi
1000 1000 psipsi
8 8 psipsi
Mud Seal
Vent Line
Gas Expansion Through Choke
• At 40 spm the amount of gas escaping up the vent line is 323 bbls/min.
• This large volume of gas causes a back pressure due to friction losses that is proportional to the Inside Diameter (ID) and length of the Vent line.
• The larger the ID and shorter the length of the vent line the less the back pressure in the MGS.
• As long as this back pressure does not exceed the hydrostatic pressure of the mud seal. Gas should not travel down to the shakers.
Gas expansion throughthe choke.
P1 = 1000 psiV1 = 4.76 bbl/minP2 = 14.72 psi
1000 x 4.76 = 4760
476014.72 = 323 bbl/min
1000 1000 psipsi
8 8 psipsi
Mud Seal
Vent Line
Gas Expansion Through Choke
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• The easiest and safest way of preventing the loss of the mud seal is to reduce the pump speed, if the pressure in the MGS approaches 85% of the mud seal hydrostatic pressure.
• A blow down line can also be fitted. This is an overboard line that is fitted with a pilot operated valve controlled by computer.
• This system sounds an audible alarm when the MGS safe pressure is exceeded. If the pressure in the MGS is not reduced within a given time period the blow down valve is opened.
1000 1000 psipsi
Blow Down line
1000 1000 psipsi
8 8 psipsi
Mud Seal
Blow Down Line
22’
Vent line
To Shale Shakers
From Choke Manifold
MGS
What is the maximum operating pressure of this MGS with 11.3 ppg mud ?
Mud Gas Separator
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The Vacuum De-gasser is designed to remove the small bubbles of gas in mud:
• Left after passing through the MGS
• In case of gas cut mud
• When circulating any trip gas
The Vacuum De-gasser will be line up at all times during the Well Control operation and should be tested every tour.
Vacuum Degasser
Recommended