Equipment IWCF Course

Well Control Course Well Control Equipment

Shallow Gas Introduction Since 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.

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Well Control Course Shallow Gas

DIVERTERS, is not the answer for shallow gas. If any, move the rig off location.

Shallow Gas

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Well Control Course Shallow Gas

Shallow Gas

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Well Control Course Shallow Gas

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.

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Well Control Course Shallow Gas 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

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Well Control Course Shallow Gas Prevention • 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

Schlumberger Policies: I.14 A 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

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Well Control Course Diverter with Annular Packing Element

Flow line to Shakers

Annular packing element Head Piston

Diverter open port Diverter close port

Body

Functions should be interlocked

Vent line to over board

Diverter with Insert Type Packer Functions should be interlocked

Drill pipe Insert packer lockdown dogs Diverter close port

Diverter lockdown dogs Standard packer

Flow- Line Seal

Insert packer Flow / Vent line Support housing

Flow- Line Seal

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Well Control Course Diverter Wind

What is the position of the valves while drilling? If the diverter needs to be operated, what will be the sequence?

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.19 THE DRILLER WILL CHECK ALL DIVERTER AND OVERBOARD VALVES FOR PROPER SETTING AT THE BEGINNING OF EACH TOUR.

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Well Control Course API RP 53 - Installation

Remember !!! 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.

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Well Control Course Shallow Gas 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.

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Well Control Course Accumulator Unit

Accumulator Unit 3000

1500

1500

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Well Control Course Accumulator Systems THE ACCUMULATOR BOTTLES ARE CONTAINERS THAT STORE HYDRAULIC 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

Bladder Type

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Well Control Course Floating Type P X V = CST 1000 psi X 10 gal = 10,000 VOL gas = CST / PRESS

CST

10,000

PRESS.

V. gas BOTTLE

V. oil USABLE FLUID =

API RP 53 - Accumulator Usable Hydraulic fluid is: The fluid recoverable from the accumulator system between the maximum accumulator pressure and 200 psi above precharge pressure.

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Well Control Course API RP 53 – Accumulator Capacity 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.

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.

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Well Control Course API RP 53 – Reservoir Capacity Each closing unit should have a fluid reservoir with a capacity equal to at least twice the usable fluid capacity of the accumulator system

Accumulator Capacity Schlumberger Standard EXAMPLE: BOP Equipment:

1 Annular + 3 Rams + HCR Valve

Closing Volume (CV): 20 Opening Volume (OV): 20 Closing Volume (CV): 20 Open Choke Line Valve (OV):

+ (3 x 10) + 1 + (3 x 10) + 1 1

Usable Volume (UV):

= 51 Gal = 51 Gal = 20 Gal = 1 Gal = 123 Gal

Nominal Volume (NV):

2 x UV

= 246 Gal

25 accumulator bottles

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Well Control Course API RP 53 - Minimum Calculated Operating Pressure: 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 – Pumps Systems 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.

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Well Control Course API RP 53 – Pumps Systems Each surface BOP control system should have a minimum 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.

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Well Control Course API RP 53 – Pumps Systems Each pump should be protected from over pressurization by a 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 the pumps will automatically start when the system pressure has decreased to approximately 90 % of the system working pressure and automatically stop within +0 to - 100 psi of the control system working pressure.

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Well Control Course API RP 53 – 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. Remote valves should not exceed the minimum observed ram BOP

Choke Manifold 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

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Well Control Course API RP 53 – Initial Pressure Test

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

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Well Control Course Packing Unit

Pressure Test Schlumberger 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.

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Well Control Course API RP 53 – Choke Manifolds & Kill Lines

• 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.

Shell Test The body of new BOP’s are subjected to a hydrostatic proof testing or shell test prior shipment: Rated Working Pressure (psi)

API Size Designation 13 5/8 and Smaller

API Size Designation 16 3/4 and Larger

2,000

4,000

3,000

3,000

6,000

4,500

5,000

10,000

10,000

10,000

15,000

15,000

15,000

22,500

22,500

20,000

30,000

---

The hydraulic operating chamber shall be tested at a minimum test pressure equal to 1.5 times the operating chamber’s rated working pressure.

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Well Control Course Tester Cup & Tester Plug

Ring Gaskets

Type “R”

Type “RX”

“X” type are pressure energized meaning that well pressure helps to effect the seal

Type “BX”

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Well Control Course Ring Grooves The most common ring grooves are: • API 6B

- 2,000 / 5,000 psi

• API 6BX

- 2,000 / 20,000 psi

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Ring gaskets to be used for specific grooves are: • API 6B

- use API type “R” or type “RX”

• API 6BX

- use API type “BX”

Exercise Which pressure energized ring gasket can match with a ring groove API 6B ? - BX -R - RX

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Well Control Course Flange Types Stand-off

Closed Face

gives instability

gives stability

BX Ring Gaskets

R or RX Ring Gaskets

API 6B Flange

API 6BX Flange

Nominal Size

What does this mean ? a 3-1/16 , 10 000 flange

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Well Control Course Connection Studded

Clamp Hub

Flanged

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Well Control Course Annular BOP’s 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.

Hydril GX

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Well Control Course Hydril GL 1- Latched Head 2 - Opening Chamber Head 3 - Opening Chamber 4 - Closing Chamber 5 - Secondary Chamber 6 - Piston Seals 7 - Piston 8 - Packing Unit

Cameron DL Quick-Release Top Donut Packer Access Flaps Locking Grooves Packer Insert Pusher Plate

Outer Cylinder Lock Down Vent Port Operating Piston Closing Hydraulic Port

Opening Hydraulic Port Vent Port

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Well Control Course State the Rating Operating Pressure Manufacturer’s Data

Hydril GL: Secondary Chamber Standard Surface Hookup

Optional Surface Hookup

Connects the secondary chamber to the opening chamber

Connects the secondary chamber to the closing chamber

- Least amount of fluid - Fastest closing time

- Least amount of closing pressure for optimum closing force

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Well Control Course Safety Valves 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 means of handling will be provided to assist with its installation.

Full Opening Safety Valve Upper seat

Ball Crank Lower Seat

Body

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Well Control Course Inside BOP’s Release Rod Locking Screw

Release tool

Valve Release rod Upper Body Seat Valve Valve Spring Lower Body

Float Valves USED TO: • Prevent sudden influx entry into the drill string. • Prevent back flow of annular cuttings from plugging bit nozzles.

Schlumberger Policies: I.14 A 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.

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Well Control Course Cameron Type - U Bonnet

Operating Piston

Operating Cylinder Ram change cylinder Ram change piston

Seal Rings Assy. Bonnet Ram Assy. Intermediate Flange

Body

Shaffer Rams - NL Block Rubber

Retaining screw Holder

Retaining screw

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Well Control Course Cameron Variable Bore Ram Assy. Top Seal

Packer

Body

Shearing Blind Rams Top Seal

Upper Shear Ram Blade Side Packer Lower Shear Ram assembly

Face Seal

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Well Control Course Cameron Manual Lock

Cameron Wedge Lock

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Well Control Course Hydril MPL (Multiple Position Lock) Hydraulically-actuated mechanical clutch mechanism

Shaffer Ultralock

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Well Control Course Shaffer POSLOCK

(One Position Locking Mechanism)

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Well Control Course Mud Gas Separator Circulating through MGS, above design capacity, unloading gas to shakers

Circulating through MGS, no gas no pressure

Circulating gas through MGS, within design capacity

Typical Offshore Set-up

Possible improvement of mud seal height

Typical Land Rig Set-up

Typical Offshore Set-up

Typical Land Rig Set-up

The mud gas separator is a low pressure vessel

Baffle Plate

GAS

Mud Gas Separator

From Choke Manifold

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

Siphon Breaker

Mud To Shakers

3 - Height of the “U” tube control the working pressure and the fluid level to stop the gas going out of the MGS

Drain Line with valve

The function of the MGS is to mechanically separate gas from the mud.

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Well Control Course Mud Gas Separator 650 psi

Vent Line 0 psi • • • •

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.

Mud Seal : 20 ft

Mud Gas Separator 650 psi

Vent Line 0 psi •

• •

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 ppg mud it would take a gas pressure of 10.4 psi from within the separator to evacuate the mud seal.

Mud Seal : 20 ft

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Well Control Course MGS – Gas at Surface 1000 psi

Vent Line

• 8 psi •

•

Mud Seal

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.

MGS – Gas at Surface 1000 psi

Vent Line

• 8 psi •

•

Mud Seal

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.

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Well Control Course Gas Expansion Through Choke 1000 psi

Vent Line

• 8 psi • •

Gas expansion through the choke.

•

P1 = 1000 psi V1 = 4.76 bbl/min P2 = 14.72 psi

•

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.

Mud Seal

Gas Expansion Through Choke 1000 psi

•

Vent Line 8 psi

•

Gas expansion through the choke. P1 = 1000 psi V1 = 4.76 bbl/min P2 = 14.72 psi

•

1000 x 4.76 = 4760 4760 14.72 = 323 bbl/min

Mud Seal

•

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.

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Well Control Course Blow Down Line •

1000 psi

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.

8 psi

•

Blow Down line

•

Mud Seal

Mud Gas Separator Vent line

What is the maximum operating pressure of this MGS with 11.3 ppg mud ?

From Choke Manifold MGS

22’

To Shale Shakers

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Well Control Course Vacuum Degasser 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.

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