Equipment IWCF Course

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

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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.


•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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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.


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.


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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

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Equipment IWCF Course