An Overview to IWCF Well Control Certification Course

(DRILLER/SUPERVISOR LEVEL)

Day 3

Prepared by:

Engr. Muhammad Nauman Awan

Table of Contents DAY-3 ---- Session – I ................................................................................................................................. 1

Insider blowout preventer (IBOP) ................................................................................................................. 4

Full Open Safety Valve (FOSV) ................................................................................................................... 6

Bit Float (Float sub) ...................................................................................................................................... 7

Valve Pullers, Float Collar ............................................................................................................................ 8

Fast Shut off Coupling .................................................................................................................................. 9

Drop in check valve .................................................................................................................................... 10

Function testing of BOP .............................................................................................................................. 11

BOP testing period, Full BOP test .............................................................................................................. 12

High pressure test for RAMS and auxiliary equipment, Annular Preventer ............................................... 12

General Pressure Test Requirement ............................................................................................................ 13

Pressure tested with test Plug, With Cup type tester ................................................................................... 14

Casing pressure Test ................................................................................................................................... 15

Pressure Test Procedure, HCR (Valve #4) and Pipe rams test ................................................................... 16

Valve #3 and Annular Preventer Test, Blind rams, Choke manifold valves testing ................................... 17

Well Heads and BOP Equipment Testing ................................................................................................... 19

Pressure Test Frequencies, Pressure Test Casing Strings ........................................................................... 20

Functional Tests, Inspection and Precautions ............................................................................................. 22

Closing and opening ratios of BOP............................................................................................................. 23

Accumulator (Koomey) .............................................................................................................................. 24

Accumulator Capacity ................................................................................................................................ 26

4-Way Valve Operation in Blow Out Preventer Accumulator (Koomey) Unit .......................................... 28

DAY-3 ---- Session - II ........................................................................................................................... 31

Pressure test procedure for choke and kill manifold ................................................................................... 31

Choke Drill Steps ........................................................................................................................................ 31

BOP drills, Kick Drill While Drilling (Pit Drill) ........................................................................................ 32

Kick Drill While Tripping (Trip Drills), Volumetric Stripping Drill (Strip Drills) .................................... 33

After Completing the Strip Drill ................................................................................................................. 34

Reporting, Variable Bore Ram, Pipe Ram .................................................................................................. 35

Responsibilities for Well Control ............................................................................................................... 36

DAY-3 ---- Session - III ......................................................................................................................... 38

Rotating Head (RCDs), Gas or Air drilling ................................................................................................ 38

Flow drilling................................................................................................................................................ 39

Geothermal Drilling, Overbalanced Drilling .............................................................................................. 41

Workover Operations, Operating Guidelines .............................................................................................. 42

Rig Crew Training, High-Pressure Rotating Head ..................................................................................... 43

Cup Tester, Test Plug .................................................................................................................................. 45

PVT (Pit Volume Totalizer), Flow Sensor, Mud Gas Separator ................................................................. 46

Bore Protector, Retrievable Wear Bushing & Tie-Down Flange Assembly............................................... 48

Test Plug Assembly .................................................................................................................................... 48

DAY-3 ---- Session - IV ......................................................................................................................... 50

Ring joint gaskets ........................................................................................................................................ 50

DAY-3 --------------- Session – I

Special Equipment

Insider blowout preventer (IBOP)

Insider blowout preventer (IBOP) valves have several industrial names as drill pipe float valves,

Gray valves, Omsco valves and drop-in dart valves.

Figure - Inside BOP (Dart Type)

This valve is a non-return valve

(check valve) allowing pumping

through the valve into the drillstring

but it prevents upward flow and the

more widely used type is “dart-

type”. The dart is used to hold the

tool open therefore it is possible to

stab the valve while the fluid is

flowing through the drillpipe. With

the IBOP valve installed in the drill

string, it allows you to strip in hole

without mud flowing through the

drill sting. The IBOP valve should

not be used for shut the well in

while tripping.

IBOP Operation:

An IBOP is typically a ball valve or other type of valve that is connected in line with the drills

string. It can be closed to isolate the kick inside the drill string. Because an IBOP and its

associated actuator is connected in line with the drill string, it will rotate with the drill string

during drilling operations. Typically, IBOP's are pneumatically powered. The air source,

typically a pressurized cylinder, is generally stationary. Thus, the challenge is to get the air

power from the stationary source to the rotating IBOP actuator. It is noted that often drilling is

stopped before the IBOP is actuated, but for safety reasons, the IBOP must be connected to an air

supply at all times during drilling operations.

IBOP for top drive can be divided into Upper IBOP and Lower IBOP; they are control valves

which are used with the top drive system. Usually the two valves connected to the top drive

drilling device. The IBOP adopts high reliable metal seal. So it can bear high pressure upward

and downward. The working pressure can be achieved 10000 psi or 15000 psi. When well kick

occurring, the upper IBOP can be closed by remote controlled, but the lower IBOP will be

closed manually. Actuator for top drive is a subsidiary body which controls open and close of

Upper IBOP. It works with other accessories of the rig, so that control opening and closing of

Upper IBOP on any height of derrick driller console. Both the valve body cavity and accessories

have special anticorrosive processing, so that prolong the working life.

Inside Blowout Preventer (IBOP)

Applications

Packard’s Inside Blowout Preventer (IBOP)

is used to provide shutoff of backflow during

periods when the drill string is open. The

valve is held with the dart in the open

position to allow stabbing during backflow.

After stabbing the flow is shut off by turning

the release handle. The stab body is removed

and the drill string can be reconnected to re-

establish pressure stabilization. The valve

can then be removed and returned to its

ready state or it can be left in the drill string

to ensure downward flow only.

Features and Benefits

Easy Maintenance

The Packard International IBOP is

manufactured and tested in accordance with

API Specification 7 with NACE compliant

internal components. The integral seat design

minimizes repair time and costs.

Connection Flexibility

The Packard International IBOP can be

supplied with any API connection, including

many proprietary threads supplied by

licensed vendors and OEMs.

High and Low Pressure Sealing

High and low pressure sealing is assured by Packard’s unique elastomer and metal-to-metal

sealing systems. The IBOP is available in pressure ratings up to 15,000 psi working (22,500 psi

test pressure).

An inside BOP (Gray valve) is used when hanging off the drill string in the well head and is

installed one single below the hang-off tool. It shall not be installed when the string is hung off

with the bit in open hole, (so that wireline tools may be run). An inside BOP will also be used

when stripping in pipe. It should always be available on the drill floor ready for use.

Full Open Safety Valve (FOSV)

A full opening single or dual safety valve for wells,

in which each valve assembly has a rotary ball valve

having a flow passage as large as the flow passage

through the valve body. The ball valve is installed in

the body through a side window which is closed by a

member which cooperates with the ball valve to

move the latter between open and closed positions.

The dual safety valve has releasable latch means for

holding the safety valve in a receptacle of a tubing

hanger which supports producing tubing strings in

the well.

Ball Type Full Opening Safety Valve is designed

to be stabbed into the top joint of drill pipe or

tubing at the rig floor and closed quickly in case a

well kicks. After weight material is added to the

mud, the Kelly can be reconnected, the safety valve

opened, and circulation initiated.

Like the Kelly valve, the Safety Valve is full

opening. The ball-type design permits the valve to

be compact, easy to handle, and yet have great

strength. Standard test pressure is 10,000 pounds,

but higher pressure ratings are available.

Full Opening Safety Valve or TIW valve is a ball

valve designed for high pressure condition and it can

hold pressure from both directions. It is called “Full

Opening” because when the ball valve is opened; the

flow path through the valve has a smooth inside

diameter. One thing that you need to remember is

that the term “Full Opening” does not mean that the

ID of the valve is the same of drill pipe ID.

The valve should be always located on the rig floor and left in the open position. Additionally,

you need to ensure that personnel on the rig have a right wrench to close the valve. The valve left

in the open position is critical because the valve can be stab into drill string if the well flows

through drill pipe.

For good drilling practices, you must have all size full opening safety valves which can be

screwed into each size of drill pipe, drill collar, tubing, etc on the rig. When there is any string in

the hole, the correct connection of the valve must be ready on the rig floor to stab in.

Furthermore, it is a good practice to install the valve when there is a sting left on the rotary table

during rig performs any tasks. The full opening safety valve should be used for shutting the well

in while tripping.

Bit Float (Float sub)

Float subs are used to house a float valve, also known as a back pressure valve. The float valve

functions as a safety between the wellbore and the inside of the drillstring to prevent drilling

fluids from back flowing up to surface.

Float (check) valve is usually installed in

float subs (long subs bored out for a

specific float) and prevent fluids from

backing up in your drill string while

adding/removing rods. The type available

of float valve as below:

Model F (plunger valve):Instantaneous

shut off against high or low pressure,

assuring continuous control of fluid flow

during drilling.

Model FC (Automatic Fill valve)

Automatic feature allows drill pipe to fill

from the bottom, removing the mess,

hazards, and lost time from filing. When

running in the hole, automatic fill feature

eliminates the ‘ram effect’ preventing the

down hole pressure surges that can cause

formation damage.

Model G (Full open valve, flapper type):

When circulation stops, flapper closes

instantly to prevent cuttings from entering

drill string and plugging bit. Valve opens

when the first joint is raised out of hole

assuring the first joints drain and are not

pulled wet. Saves mud and avoids safety

hazard and downtime.

This Float Valve is normally installed in a standard bore-back of the bit sub, to provide fluid

flow control at the bottom of the drill stem. It also prevents backflow of cuttings from plugging

the drill bit jets while making connections. Its 70Mpa (10000psi) working pressure complements

today`s high pressure BOP stacks. When the flapper is held open by the built-in latch, the drill

pipe fills from the bottom.

This eliminates the mess and lost time of filling operations, Tuning in with the flapper

open also reduces the potential of formation damage from pressure surges caused by the bit

acting as a piston or ram as it is lowered into the hole. The flapper latch is automatically

released by initial circulation of drilling fluid through the valve. During normal

circulation, the flapper is fully open and out of the way. The large bore of the Valve provides

minimum flow restriction. When circulation is stopped. The flapper is closed by the flapper

spring .Preventing backflow through the bit.

When run in the closed position, the Valve allows the drill pipe to be floated in while

only partially filled with drilling fluid. This lowers the effective weight of the drill

string and reduces strain on rig equipment. The Float Valve Sub is a bit sub in which a float

valve is be installed.

Float subs are always used when drilling pilot holes, and can also be used when drilling 36", 26"

(or 22"), and 17 1/2" (or 16") hole sections.

When using float subs, the following procedures shall be carried out:

1. When running in hole, break circulation as soon as all the drill collars and one stand of drill

pipe are in the hole. This checks the correct operation of the float sub.

2. Fill up the drill pipe every ten stands.

3. Run in slowly and carefully to avoid excessive surging as the drill pipe has effectively a closed

end.

Valve Pullers

Valve pullers are an essential part in the

removal of float valves from the bit sub.

Model G pullers serve a dual purpose as they

are also used in the removing and installing of

the seal retainer ring when changing out the

valve seal.

Model F

Puller

MODEL F (TOP) PULLER

The Model F valve (top) puller is designed to remove float valves from the top of the sub.

Simply squeeze the forks together and press against the head of the valve plunger. Once the

forks are engaged with the cage the valve can be pulled. Disengage by sliding the separator

away from the valve and squeezing the forks together and the puller can be removed.

Float Collar

A component installed near the bottom of the

casing string on which cement plugs land

during the primary cementing operation. It

typically consists of a short length of casing

fitted with a check valve. This device may be a

flapper-valve type, a spring-loaded ball valve

or other type.

The check-valve assembly fixed within the float collar prevents flow back of the cement slurry

when pumping is stopped. Without a float collar, the cement slurry placed in the annulus could

U-tube, or reverse flow back into the casing. The greater density of cement slurries than the

displacement mud inside the casing causes the U-tube effect.

Fast Shut off Coupling

Fast shut-off couplings are used for emergency shut-off purposes when running in or pulling out

tubing, casing, or drill pipe. They are currently used by the Company in sizes to suit 3 ½" and 5"

drill pipe. The fast shut-off coupling is designed to be dropped over the drill pipe with an open

Kelly cock attached. The coupling automatically latches under and seals off around the tool joint

(or collar). The Kelly cock can then be closed, to stop the flow through the string.

A fast shut-off coupling corresponding to the size of pipe in use with an open kelly cock made up

on it shall be available on the drill floor at all times.

The Vetco Gray Rotating Fast Shut off Coupling (RFSOC) is especially designed for problem

holes.

Special features include:

The ability to circulate mud through the drill string while tripping out of the hole ensuring that

the formation pressure will not cause collapse and subsequent loss of the drillstring.

None return valve positioned in the neck of the tool allows mud to flow immediately when a 100

psi differential pressure across the valves is sensed.

Small check valve which allows bleed down of the string back to the mud manifold with the tool

locked onto the drill string.

Permits rotation of the drill string needed

when breaking out a tool joint while

suspended one stand of pipe above the drill

floor.

The load bearing dogs are in 320 degree

circumferential contact with the tool joint,

these are effectively actuated by four

pneumatically operated cylinders located in

the lower rotating outer casing. Bevel gears

attached to the end of the dog pivot pins

ensure that the dogs move smoothly and in

unison when releasing the drill string tool

joint.

The air control system, run by rig air is

mounted on the coupling body. This allows

easier access by both derrickman and drill

floor crew while ensuring minimum

down time between racking stands of drill pipe on even the most difficult of formations.

The RFSOC can be designed to suit any specific size of drillstring program. It can also include

two replaceable insert sleeves with their respective dogs to enable one tool to run two different

drill pipe size.

Drop in check valve

Check Valves are designed to control or prevent a backflow condition when the Kelly or top

drive is disconnected from the drill pipe, essentially a one-way check valve.

Drop-in check valve, as an important toll to prevent well kick and a BOP inside drilling string,

which is dropped into well and prevent well kick and blowout just as necessary, is used to

control the inner pressure of drilling rod as running retrieving drill is forced under well kick or a

certain pressure. For it is not connected with drilling rod, it is convenient to execute various

drilling operation.

As overflow happens underground, the check valve is dropped or pumped into the water hole of

the Kelly, and moves to be held against the shoulder of the stop ring connected with the bottom

of the on-station connector, the cone of the valve moves up, some hackle lock-teeth of on-station

connector and the teeth-block in the top of the check valve are locked each other, the cone

moving up forces packer to dilate so as to seal the bore-wall, in the bottom hole sets steel ball

and spring, the spring can load the steel ball into the sealing seat of the valve body, so that a

strict seal mechanism is formed, here the on-station connector and check valve assembly

composes a set of internal-BOP assembly.

Drop-in check valve is an internal preventer. When blowout is going to happen, the Kelly should

be removed immediately and the check pressure valve assembly should be put into the water

hole and then pumped downward to the required place. Thus, the blowout can be prevented. The

valve body connect on the drilling stem, Drop-in check valve is ball and seat of heavy duty, if

only drop in the valve core at the mouth of the well, it turn into the valve body.

1. Adapter Body

2. Thrust Ring

3. Valve Core

4. Seat

5.Slip Insert

6. Slip

7. Retainer

8. Lock Nut

9. Spring Seat

10. Spring

11. Ball

Function testing of BOP

Every week, personnel must perform function test BOP alternating between remote panels.

General BOP testing procedures

• Use water to test BOP’s. The reason is that water has less compressibility than mud.

• Make up testing assembly and set in into a wellhead profile. Ensure that the casing valve must

be left opened and there must be personnel monitoring the outlet of casing valve all time while

testing. You must ensure that personnel who monitor the outlet must stay for from the BOP

while it is being tested. The reason behind this step is to prevent pressure build up in the casing if

the test plug is leaking.

• Circulate through choke/kill lines, choke manifold, standpipe manifold, and valves to ensure

that all lines are full with water. This practice is for preventing pressure dropping off while

testing.

• Line up cement unit and rig team shut rams and valves as per each rig specific testing sequence

• Pressure test must be low and high, respectively, and the pressure should be stabilized with

minimum bleed off at least 5 minutes. Ensure that pressure recording on a chart is recorded

correctly.

• Ensure that any equipment does not pass a pressure test requirement must be reported to

supervisors.

• Continue pressure testing until all equipment is tested as per each rig specific.

• Rig down testing assembly.

BOP testing period

Function test BOP: Every week, personnel must perform function test BOP alternating between

remote panels.

Full BOP test: There are 3 categories that you should consider for full BOP test.

1. Prior to supping the well or the first time that BOP is installed on the well.

2. After repairing or disconnecting of any pressure sealing elements of BOP.

3. As per MMS, you can use BOP for 21 days (3 weeks) before you need to test it again. Or you

must follow the local regulations. For example, in the North Sea, they allow you only 14 days

before next BOP test.

High pressure test for RAMS and auxiliary equipment

High pressure test to rated working pressure of RAMS BOP and auxiliary equipment OR rated

working pressure of your wellhead. Select the lower number. For example, you BOP is rated for

10,000 psi and your wellhead is rated for 6500 psi. Your high pressure test for the RAMS BOP

and auxiliary equipment must be only 6500 psi.

High pressure test for Annular Preventer

High pressure test should apply to 70% of rated working pressure or RAMS test pressure. Select

the lower number. For example, you test your ram at 5,000 psi and the annular working pressure

is 6,500 psi. You need to test your annular to 3500 psi (70% of rams testing pressure).

Low pressure test for both annular and RAMs preventer

200 – 300 psi should be applied for a low pressure test and the period is 5 minutes.

Function testing

The function test should be carried out on each round trip but not more than once per day. The

test should be conducted while tripping the drill pipe with the bit inside casing.

Before applying pressure testing to Preventers, perform the following:

(1) Each Remote control panel should be used to operate the BOP & valves.

(2) Close and open all preventers, Annular preventer must never be closed in an empty hole.

(3) Blind ram should be operated for function test while string is out of hole.

(4) Pipe rams must be closed against correct size of pipe in the well.

(5) Annular preventers should not be operated on each round trip. They should, however, be

function tested once a week.

(6) Operations of shear ram, if available in the stack, should be kept to bare minimum.

(7) The valves on BOP stack, wellhead and choke / kill manifold (excluding the hydraulic and

adjustable chokes which are function tested on each round trip) should be function tested at least

once a week.

Pressure testing of BOP

General Pressure Test Requirement

All BOP equipment pressure tests should be conducted in accordance with following guidelines:

1) Test frequency -BOP equipment should be pressure tested as follow:

When installed.

Before drilling out each string of casing.

Following disconnection or repair any wellbore pressure seal in the Wellhead/BOP stack

(limited to the affected components only).

Note: when rams are changed, the casing/tubing rams (and annular preventer) should be tested to

lesser or the high pressure test or one half the rate working pressure. pressure tested with test

plug and casing/tubing joint to 80% of pipe burst rating of the casing or rated working pressure

of BOP (whichever is less).

All BOP test maximum of every 21 days.

2) All pressure tests should be performed using clear water.

3) Check and Record the nitrogen-pre-charge pressure of each accumulator bottle.

4) Keep the relevant well head side out let valves open while using test plug for all BOP pressure

test.

5) Test Pressure

The low-pressure test of each piece of BOP equipment should be conducted at a

pressure of 200-350 psi.

High pressure-test should be conducted at rated working pressure of the weakest

component.

Option1: pressure tested with test plug.

High pressure should be 70%rated work pressure of annular Preventer and 100% rated work

pressure of rams preventer and 100%rated work pressure of wellhead (whichever is less).

Option 2: pressure tested with cup type tester

High pressure should be 70%rated work pressure of annular Preventer and 100%rated work

pressure of wellhead and 80% of pipe burst rating of the casing (whichever is less).

6) Low-pressure test should be performed first. Do not test to the high-pressure and bleed down

to the low-pressure.

7) All the high pressure tests must be held to 7Mpa for 5 minutes, then maximum testing

pressure for 10 minutes, the observable pressure decline should be in allowed range. All pressure

test to be recorded and charted if available.

8) Choke manifold and kill manifold should be tested separately simultaneously with normal rig

operations if a test port is available.

9) Remote control panel (must have two one on rig floor and other or ground easy accessible

area) should be operated for all BOP pressure test. No BOP opening after BOP test should be

done before checking the Release of the pressure and the operating should be done by authorized

person

10) Only authorized personnel shall go in test area to inspect for leaks when equipment is under

pressure.

11) All the pressure test should be conducted with a test pump, rig pumps or the cement units

(the cost of the cement unit will be paid by the rig as result of no test pump provide by the rig).

12) All test results should be documented on a pressure record with following information:

Date of test

Well name

Driller

Toolpusher or Drilling Engineer

Drilling Supervisor

Casing pressure Test:

A casing test is generally conducted for testing DV and float equipment, along with the

scheduled BOP test.

To conduct the pressure test, perform the following:

Connect pressure source to the kill line and open kill line valve#1 and #2.

Open all valves and chokes on manifold, close valve J2a (see figure 2)

Close casing head valves.

Close blind rams (or pipe rams if pipe in the hole).

Pump into the well through kill line. Monitor and record the test pressure. For all the

casing strings other than drive pipe or structural casing conduct the test to 80% of the

minimum internal yield (or burst) of casing or well head’s or BOP’s rated working

pressure limits (whichever is less).

Bleed off pressure at choke line.( close J1,open J2a,then open J1 to bleed off)

Pressure Testing of Inside BOPs, Kelly Cocks, TDS, Swivel and Rotary Hoses

While carrying out pressure testing of above items also, it is recommended that test pressure

should be applied from the direction in which they would experience pressure during actual well

kick situation.

1) Pick up Kelly / TDS.

2) Make up Full Opening Safety Valve (FOSV) on bottom of lower Kelly cock.

3) Make up Inside BOP on the bottom of FOSV.

4) Make up adapter sub on bottom of inside BOP and complete connection of test line from

cementing unit or test pump to adapter sub.

5) Apply test pressure first up to 200-350 psi and then raise to rated working pressure of inside

BOP. Hold pressure 5 minutes.

6) Release pressure and disconnect adapter sub from inside BOP, disconnect inside BOP and

connect adapter sub to FOSV with test lines.

7) Close FOSV and apply test pressure up to 200-350psi. Watch for any leakage. If no leakage,

increase test pressure to rated working pressure of FOSV and hold pressure for 5 minutes. After

test is over release pressure.

8) Test lower Kelly cock, upper Kelly cock, swivel / TDS, rotary hose and stand pipe valves one

by one. Applied test pressure should not exceed rated working pressure of the item being tested

or the working pressure of the weakest member exposed to test pressure, whichever is less.

Note: Make sure that Kelly / TDS, stand pipe etc. are full with water (test fluid) and air is not

trapped in it.

Pressure Test Procedure

1. 21 1/4″ BOP Stack (17 1/2″ hole section):

1.1 HCR (Valve #4) and Pipe rams test

Pick up top drive, connect test plug on the bottom of 5-1/2″ DP, run test plug and seat in

wellhead.

Connect pressure source to the kill line and open kill line valve #1 and #2, valve #3, and

keep HCR (valve #4) close.

Close pipe rams.

Pump into the well through kill line. Monitor and record the test pressure. Conduct low-

pressure test and high-pressure test as above test requirement.

Bleed off pressure at choke line (close J1, open#4, then open J1 to bleed off). Open pipe

rams.

1.2 Valve #3 and Annular Preventer Test

Close annular preventer on the same 5-1/2″ DP. Close valve #3(see figure1.2)

Pump into the well through kill line. Monitor and record the test pressure.

Conduct low-pressure test and high-pressure test as mentioned above.

Bleed off pressure at choke line (close J1, open valve#3, then open J1 to bleed off). Open

annular preventer.

1.3 Blind rams testing

Unscrew Drill Pipe from Test Plug and lay down.

Close blind rams. Close j2a (see figure 1.3)

Pump into the well through kill line. Monitor and record the test pressure.

Conduct low-pressure test and high-pressure test as mentioned above.

Bleed off pressure at choke line (close j1, open j2a, then open j1 to bleed off). Open blind

rams.

1.4 Choke manifold valves testing

Note: Choke manifold should be tested separately simultaneously with normal rig operations if a

test port is available at choke manifold.

Connect test pump to choke manifold.

Keep Valve #3 close, Open all manifold valves, close the outermost valves J8, J9, J10

(see figure1.4a).

Pump into choke manifold. Monitor and record the test pressure at test pump.

Conduct low-pressure test and high-pressure test as elaborated above.

Open outermost choke manifold valves J8, J9, J10. Close valves J5, J6b, J7a (see figure

1.4b).

Pump into choke manifold. Monitor and record the test pressure.

Conduct low-pressure test and high-pressure test as elaborated above.

Pressure Testing of Well Control Equipment

Well Heads and BOP Equipment

Pressure tests on the ram type preventers, other BOP equipment, wellhead components and their

connections in general shall be made in line with API RP 53, but see Drilling Program for the

minimum required test pressures.

Where wellhead or BOP outlets are opened for testing or any other purposes they shall not be left

unattended under any circumstances.

Manufacturer's approved handles shall be securely fitted to all wellhead and BOP valves

During subsequent drilling operations, the equipment shall be pressure-tested at regular intervals

using a plug type or cup type tester. Test to at least the anticipated pressures or to the original

casing test pressure (in case a cup type tester is used), whichever is lower.

Plug and cup type testers suitable for pressure-testing the wellhead and BOP equipment on all

casing strings shall be available on the rig site.

Use proper cup size for various casing weights. Retrievable packers with large slip areas may

also be used if available.

The pressure test shall consist of:

Low pressure test - 500 psi

High pressure test to the full rated working pressure of the equipment

All equipment shall hold the low pressure test for 10 minutes and the high pressure test

for 10 minutes.

Pressure Test Wellhead Equipment

After each complete installation, the wellhead and ram type BOP equipment shall be pressure-

tested, using a plug type tester, to the rated working pressure of the wellhead, the ram type

preventers or the pressure detailed in the Drilling Program, whichever is lower. The wellhead

side outlets below the tester shall be open, to prevent pressuring the casing.

Seals and bushings around casing stubs shall be tested through the test port to only 50% of the

collapse rating of the casing provided that this does not exceed the manufacturers rating for the

casing hanger when piston forces and string weight are taken into account. These seals can later

be tested to 65% of the casing burst rating (or flange rating whichever is the lower) using a cup-

type tester (test port open). Ensure that the cup-type tester does not leak and the drill pipe is

open so that the cemented casing is not tested as well.

During the drilling and completion phase, the outer side outlets of the wellhead exposed to the

live annulus shall have manually operated side outlet valves.

Pressure Test BOP equipment

The annular preventer shall be pressure-tested to maximum 70% of its rated working pressure

unless specified differently in the Drilling Program, and then only when closed around the pipe.

The complete BOP operating unit shall be tested in accordance with Manufacturer's

recommendations and pressure-tested to its rated working pressure / well rated pressure,

whichever is lower.

The choke manifold, valves, kill and choke lines and valves on side outlets shall be pressure-

tested with water to the test pressure of the ram type preventers.

All lines shall be flushed to ensure they are not blocked. No tests shall be performed against

closed chokes.

The Kelly and Kelly stop-cocks shall be pressure-tested to their rated working pressure with a

test sub. Pumps, discharge lines standpipe manifold shall be pressure tested.

If the BOP has been pressure and function tested on the stump, or if a new spool has been

installed, only the new connections need testing.

If the BOP is moved between wells, the BOP shall be fully pressure/function tested prior to any

operations on that well.

Pressure Test Frequencies

The pressure tests of all blowout preventers, wellhead components and their connections, BOP

operating unit, choke manifold, kill and choke lines, kelly and kelly-cocks shall be made:

After installation of wellhead and BOP assembly and prior to drilling.

Every 14 days. This period between tests may be extended, depending on the type of

operation being carried out and yet to be carried out during that period, but only after

consultation with the Head of Operations.

Prior to drilling into a suspected high pressure zone.

After setting casing and re-nippling BOP.

When rough drilling conditions are experienced e.g. stack shaking.

After changing out rams.

Any time requested by the Drilling Supervisor.

The results of all pressure tests shall be recorded on the Test Sheet for Blowout Preventers and

Related Equipment.

Pressure Test Casing Strings

After Installation

Newly installed casing strings shall be pressure tested to pressures as given in the Drilling

Program. The test pressures will depend on the reservoir and the well location

(onshore/offshore). Ideally, this should be performed immediately once the cement slurry is in

place (i.e. immediately after bumping the top plug) to prevent the formation of a micro-annuli.

The test pressure shall be limited by the internal yield (burst) pressure of the casing (or coupling,

if lower) and/or the maximum collapse pressure of the cementing plugs. The effects of

differential pressure resulting from a difference in the fluid level and/or a difference in mud

density in the casing and annulus shall be considered when establishing the internal test pressure.

In the case of liners, the test pressure immediately after bump should not exceed 1500 psi unless

specifically authorized in the drilling program.

Note: The acceptance criteria for the test shall be a stable pressure (i.e. straight line on the

pressure recorder) for a minimum of 10 minutes.

Casing test pressures are predetermined due to drilling in known reservoirs.

In general the following equations may be used for casing pressure tests.

For Production Casing the maximum expected surface pressure shall consider closed in pressure

arising from complete evacuation of the string to hydrocarbon gas from the deepest TD:

Surface Pressuremax = Po - HHgas

Po = Reservoir Pore Pressure @ deepest section TD as per well proposal (psi)

HHgas = (TVD of Section TD) x (Expected Gas Gradient) (psi)

For Intermediate Casing the intermediate casing string shall be tested to the maximum expected

surface pressure as defined in its design criteria which shall be clearly identified in the Drilling

Program.

In general the maximum surface pressure shall be the lesser of:

a. Closed in casing head pressure arising from the casing being completely evacuated to

hydrocarbon gas from the casing shoe using the formation strength gradient criteria

Surface Pressuremax = Maximum Pressure at Shoe - HHgas

Max Pressure at Shoe = Max expected formation strength gradient at shoe x Shoe depth (psi)

b. Closed in casing head pressure arising from the casing being completely evacuated to

hydrocarbon gas from deepest section TD using the pore pressure gradient criteria.

Surface Pressuremax = Po - HHgas

Po= Reservoir Pore Pressure @ deepest section TD as per well proposal (psi)

HHgas = TVD of Section TD x expected gas gradient (psi)

Subsequent Casing Pressure Tests

Cemented casing shall not be tested to excessive pressure as this may lead to loss of zonal

isolation - ballooning of the casing can cause the formation of a micro-annulus after the test.

Note: In wells where casing wear or corrosion is experienced or expected, caliper logs should

be performed. The reduced strength of the casing can thus be calculated and if this value is less

than the operating (design) criteria then these criteria and pressure testing requirements will have

to be reviewed to prevent total failure of the casing. Operating (design) criteria and pressure

testing requirements may also be changed due to changes in downhole reservoir pressures

(depletion) or the installation of a straddle or tie-back string to cover detected weak spots in the

string. The basis for design of pressure tests shall be highlighted in the Drilling Program.

Functional Tests, Inspection and Precautions

BOP’s shall be function tested daily. All pressure and manually operated kill and choke line

valves and Kelly cocks shall be function tested every 7 days.

The blind rams or blind/shear rams shall be functioned each time the bit is pulled.

Should any of the above tests indicate faulty equipment, this equipment shall be repaired before

drilling or any other operation related thereto is continued.

Frequently inspect tightness of flange bolts and clamps, particularly before and after pressure

testing.

Pump through kill and choke lines at regular intervals. Do not leave weighted mud in choke

manifold and kill lines but ensure that they are kept full of fluid.

Closing and opening ratios of BOP:

Closing ratio is defined as the cross sectional area of the ram piston (cylinder) divided by the

cross sectional area of the ram shaft. The closing ratio is used to determine Ram closing pressure

which will overcome wellbore pressure acting to Ram body.

Closing Ratio = Ram Piston Area ÷ Ram Shaft Area

Before going into the detailed calculation, we would like to show you where the cylinder and the

ram shaft are in BOP. In Figure 1, the yellow shaded parts demonstrate these two areas which

will be used to calculate the closing ratio.

Figure 1 – Shaffer SL-Ram BOP

Example: Ram has a piston cylinder of 12 inch and 4” of ram shaft (see Figure 2).

Ram piston area = (π x 122) ÷ 4 = 113.1 square inch

Ram shaft area = (π x 42) ÷ 4 = 12.6 square inch

Closing Ratio = 113.1 ÷ 12.6 = 9.0

Figure 2 – Basic Diagram of Rams

How To Use Closing Ratio To Determine Minimum Operating Pressure

When you know the closing pressure of the BOP ram, you can use the figure to determine the

minimum operating pressure. The following equation is used to determine the minimum

operating pressure from the accumulator unit (Koomey).

Minimum Operating Pressure = Working Pressure ÷ Closing Ratio

Example: What is the minimum operating pressure would be needed to close the ram against

10,000 psi maximum anticipated pressure on BOP? Please use the ram details from the example

above.

Minimum Operating Pressure = 10,000 ÷ 9 = 1,111 psi

With operating pressure of 1,111 psi, hydraulic force will equal to force acting from the wellbore

in this case (see Figure 3).

Figure 3 – Force Acting at Ram Shaft and Force At Piston

In this case, a standard accumulator (3,000 psi system) with minimum operating pressure of

1,200 psi is good enough to shut the well in with 10,000 psi surface pressure.

Accumulator (Koomey)

An accumulator or Koomey unit is a unit used to hydraulically operate Rams BOP, Annular

BOP, HCR and some hydraulic equipment. There are several of high pressure cylinders that store

gas (in bladders) and hydraulic fluid or water under pressure for hydraulic activated systems. The

primary purpose of this unit is to supply hydraulic power to the BOP stack in order to close/open

BOP stack for both normal operational and emergency situation. Stored hydraulic in the system

can provide hydraulic power to close BOP’s in well control operation, therefore, kick volume

will be minimized. The accumulator should have sufficient volume to close/open all preventers

and accumulator pressure must be maintained all time. According to API RP53, your reservoir

tank should have a total volume at least 2 times of usable volume to close all BOP equipment.

Pressure based on 3,000 psi surface stack system that you should check on BOP remote

panel and Koomey unit is listed below:

• Manifold pressure at +/- 1,500 psi

• Accumulator pressure at +/- 3,000 psi

• Annular preventer at +/- 500 – 1,500 psi

• Rig Air at +/- 100 – 130 psi

There are 4 main components of the Koomey unit as follows:

• Accumulators

• Pumping system (electric and pneumatic pumps)

• Manifold system

• Reservoir tank

According to API RP 53, there must be 2 or 3 independent sources of power that will be

available for each closing unit. Typically, you will these following sources:

• Hydraulic with pressure charged in the bottles.

• Pneumatic • Electric

The diagram below demonstrates how the accumulator is lined up for the surface stack.

Please remember that the diagram is for learning purpose. It may or may not match with your rig

configuration. However, the concept of it is the same.

A: Pressure regulator is used to maintain pressure at annular side at 500-1500 psi

B: Pressure regulator is used to maintain the manifold pressure at 1,500 psi

Blue line for opening equipment as VBR’s, Blind/Shear Rams, Annular, HCR.

Red line for closing equipment as VBR’s, Blind/Shear Rams, Annular, HCR.

Accumulator Capacity – Usable Volume per Bottle Calculation (Surface Stack)

Accumulator (Koomey) is a unit used to hydraulically operate Rams BOP, Annular BOP, HCR

and some hydraulic equipment. There are several of high pressure cylinders that store gas (in

bladders) and hydraulic fluid or water under pressure for hydraulic activated systems. The

primary purpose of this unit is to supply hydraulic power to the BOP stack in order to close/open

BOP stack for both normal operational and emergency situation. Stored hydraulic in the system

can provide hydraulic power to close BOP’s in well control operation, therefore, kick volume

will be minimize. Accumulators should have sufficient volume to close/open all preventers and

accumulator pressure must be maintained all time.

This post you will learn how to calculate usable volume per bottle by applying Boyle’s gas law:

Use following information as guideline for calculation:

Volume per bottle = 10 gal

Pre-charge pressure = 1000 psi

Operating pressure = 3000 psi

Minimum system pressure = 1200 psi

Pressure gradient of hydraulic fluid = 0.445 psi/ft

For surface application

Step 1 Determine hydraulic fluid required to increase pressure from pre-charge pressure to

minimum:

Boyle’s Law for ideal gases: P1 V1 = P2 V2

P1 V1 = P2 V2

1000 psi x 10 gal = 1200 psi x V2

10,000 ÷ 1200 = V2

V2 = 8.3 gal

It means that N2 will be compressed from 10 gal to 8.3 gal in order to reach minimum operating

pressure. Therefore, 1.7 gal (10.0 – 8.3 = 1.7 gal) of hydraulic fluid is used for compressing to

minimum system pressure.

Step 2 Determine hydraulic required increasing pressure from pre-charge to operating

pressure:

P1 V1 = P2 V2

1000 psi x 10 gals = 3000 psi x V2

10,000 ÷3000 = V2

V2= 3.3 gal

It means that N2 will be compressed from 10 gal to 3.3 gal. Therefore, 6.7 gal (10.0 – 3.3 = 6.7

gal) of hydraulic fluid is used for compressing to operating pressure.

Step 3 Determine usable fluid volume per bottle:

Usable volume per bottle = Hydraulic used to compress fluid to operating pressure – hydraulic

volume used to compress fluid to minimum pressure

Usable volume per bottle = 6.7 – 1.7

Usable volume per bottle = 5.0 gallons

4-Way Valve Operation in Blow Out Preventer Accumulator (Koomey) Unit

4-way valves in the accumulator (Koomey) unit are used to control the position of Blow Out

Preventer (BOP). Today we will go into the detail of 3 positions of 4-way vales in order to see

how each position affects to the BOP.

Four-Way Vale in Open Position

When the valve is turned into the open position, it directs hydraulic pressure from the manifold

into the BOP opening port therefore the BOP is in the open position. The hydraulic fluid in the

ram closing chamber will return back to the reservoir tank. Figure 1 illustrates how the hydraulic

pressure is lined up to open the BOP.

Figure 1 - Open position of the 4-way valve

Four-Way Vale in Closed Position

The valve is turned into the close position. It means that the hydraulic pressure from the

manifold is transferred into the BOP close port. The hydraulic from the opening chamber will

return back to the reservoir tank. Figure 2 shows how the hydraulic pressure is lined up to close

the BOP.

Figure 2 - Closed position of the 4-way valve

Four-Way Vale in Block Position

When the four-way valve is left in the block position (central position – Figure 3), there is no

hydraulic pressure going into either the “close” or “open” port in the BOP. You might not know

exactly the position of the rams with the block position.

Figure 3 – Block position of the 4-way valve

In normal drilling operation, you should never leave in the block position. However, the valves

can be left in the block position during rig move and repairing operation.

There is one special thing which personnel must consider about the handle of 4-way valve used

to operation the blind/shear rams (Figure 4). The control handle must be protected to mitigate

unintentional operation however it still allows to be remotely operated from the BOP remote

control panel.

Figure 4 - Blind/shear ram 4-way valve handle

DAY-3 --------------- Session - II

Pressure test procedure for choke and kill manifold

The choke manifold is then tested by:

Closing the manual valve next to the BOP on the choke line.

Attach test line to choke manifold.

Test all valves in the proper sequence.

Make sure header (watermelon, etc.) is open-ended.

When filling stack, ensure that the choke manifold can be pumped through.

Once a test is achieved, close the next set of valves, open valves behind the set that was

closed and continue this process until all valves have been tested.

Importance of Choke Drill and Its Procedure

Choke drill is one of well control drills that will improve crew competency in driller’s method.

The advantages from the choke drill are as follows:

• Get more familiar to practice controlling the pressure via a choke on the rig

• Get more understanding about lag time

• Practice the procedure to obtain the shut-in drill pipe pressure

• Ensure the surface well control equipment as pressure gauges, choke, BOP is ready for work

• Get more practices when attempting to bring the pump up to kill speed, slow the pump down

and change the pump rate

Choke Drill Steps are listed below:

1. Trip in hole above top of cement

2. Fill the pipe and circulate seawater or mud around for few minutes

3. Close annular preventer or upper rams preventer

4. Pressure up annulus to 200 psi (the pressure may be different depending on the company

policy.)

5. Line up the pump

6. Pump slowly to bump the float and obtain shut in drill pipe pressure

7. Bring the pump to kill rate by holding casing pressure constant – personnel need to adjust the

choke

8. Measure lag time for the drill pipe gage after the adjustment of choke is made.

9. Change circulation rate by holding casing pressure constant. Crew needs to adjust choke to

achieve this.

10. Shut the pump down by holding casing pressure constant.

11. Bleed off pressure and line up for drilling operation

BOP drills

Three types of drills are to be exercised, one while drilling with the kelly on the string, one

normally while tripping without the kelly on the string and one with the bit off bottom ie.:

Kick Drill While Drilling (pit drill)

Kick Drill While Tripping (trip drill)

Kick Drill While Bit off Bottom (strip drill).

General Requirements

The following guidelines shall be followed for well control drills:

Well control drills shall be initiated by the contractor or the Drilling Supervisor and

performed under the supervision of the Drilling Supervisor to ensure that the crews are

adequately trained and prepared to implement well control procedures correctly.

Well control drills shall only be conducted when they do not complicate ongoing

operations. A kick should be simulated by manipulation of a primary kick indicator such

as the tank level indicator or the flow line indicator.

The drills described in the above section include the full sequence of shutting in a well.

The critical reaction time shall be measured up to the point when the well is closed in.

Trip drills shall only be conducted if the BHA is inside the casing shoe.

Out-of-hole drills may be conducted at any time when out of hole with no tools or

wireline through the BOP stack.

Kick Drill While Drilling - Pit Drills Procedure

Before drilling out to any shoe, and at the discretion of the Drilling Supervisor, but not less than

once every week per crew while normal drilling operations are in progress.

1. INITIATE kick verbally or by raising a float (normally Drilling Supervisor or Toolpusher).

2. On initiation the crew leader is to ALERT the crew and STOP the rotary.

3. PULL Kelly above the rotary table until the lower Kelly cock is above the drilling floor, at

same time SLOW DOWN the pump.

4. STOP the pumps.

5. CLOSE the annular preventer

6. OPEN the hydraulic operated valve in the side outlet from the BOP stack to the choke

manifold (The inner valve is always open under normal conditions).

Note: A diagram with all relevant measurement relating to tool joint position should be

available to the driller at the BOP control panel.

7. TAKE readings of the closed-in annulus and drillpipe pressures.

8. MEASURE the ‘gain’ in the active mud tank.

9. END drill, RETURN all settings to normal operating mode.

Kick Drill While Tripping – Trip Drills Procedure

At the discretion of the Drilling Supervisor, but not less than once every two weeks per crew

while normal drilling operations are in progress.

1. Initiate kick verbally or by raising a float in the trip tank.

2. On initiation the crew leader (Driller/Assistant driller) is to alert the crew.

3. Bring tool joint to rotary level.

4. Install stabbing valve in open position (hand tight).

5. Close stabbing valve.

6. Close the annular preventer.

7. Open hydraulic operated valve in the side outlet from the BOP stack to the choke manifold.

Note: A diagram with all relevant measurements relating to tool joint position shall be available

to the driller at the BOP control panel.

8. Install circulating head, make up correct torque, open stabbing valve and take readings of the

closed-in annulus and drillpipe pressure.

9. Read gain in trip tank.

10. End drill, return all settings to normal operating mode.

Volumetric Stripping Drill - Procedure

Strip Drills

A combined volumetric/stripping drill should preferably be performed once per week per crew.

The drill shall only be conducted after a casing string (ideally the 9 5/8" or Production string) has

been cemented and pressure tested and prior to drilling out the shoe track.

Note: The Annular Preventer shall be pressure tested following the stripping drill.

1. Hold a “strip drill” in the casing before drilling out the shoe track.

2. RIH to 1 000 ft above top cement.

3. Hold a kick drill. Close annular preventer

4. Install inside BOP. Open stabbing valve.

5. Apply 500 psi pressure on the annulus through the kill line

6. Reduce closing pressure of the annular preventer to minimum avoiding leakage (make sure

bushings are locked!).

7. Open valve to surge bottle in annular closing line.

8. Connect line from choke manifold to trip tank. Trip tank to be half full. Check if trip tank

drains into strip tank.

9. Set up flow line so that any fluid that leaks through annular preventer goes into trip tank.

10. Make up next stand. (Have a good file on the floor to remove tong and slip marks on the

pipe.)

11. Strip stand in hole and maintain pressure on annulus constant by bleeding off through the

choke. Run pipe slowly to avoid pressure surges. Measure volume of mud bleed off and ensure

total volume is equal to closed end volume of stand stripped into hole.

12. When complete stand is run in, Close In at choke manifold by closing valve behind the

choke.

13. Drain closed end volume of one stand out of trip tank into stripping tank.

14. Install next stand.

15. Continue stripping until crew is familiar with operation.

Note: Check if all equipment is working properly and calibrations of tanks is correct. Ensure

crews are fully aware that Kelly Cock has to be put on before the inside BOP.

After Completing the Strip Drill

1. Bleed Off annulus pressure through choke.

2. Close valve to surge bottle in annular preventer closing line.

3. Increase annular pressure to normal operating pressure.

4. Open annular preventer.

5. Close HCR. Set up choke manifold for normal drilling.

6. Pull back to remove inside BOP and Kelly cock.

7. Close Kelly cock (in case pressure trapped in below Inside BOP).

8. Remove inside BOP.

9. Open Kelly cock carefully to check for pressure.

10. Remove Kelly cock.

11. Test bag type preventer prior to continuing operations.

Reporting

The Driller is to document the drill in the IADC report under remarks. The following shall be

recorded.

Type of drill.

Time of drill.

Reaction time in seconds from the moment the kick is simulated until the well is closed

in. The designated crew member is a member of the drill crew who is present on the drill

floor at the time of a BOP drill or well control situation. All drill crew members must be

capable and able to react correctly to the drill or real well control situation.

The total time taken for the drill. The time taken should be less than a pre-determined

benchmark. If not, the drill shall be repeated.

The following shall be recorded on the DDR:

The reaction time from the moment the kick is simulated until the designated crew

member is ready to start the closing procedure.

The total time it takes to complete the entire drill.

Time drill was held (to determine which crew performed the drill).

Variable Bore Ram

A ram type blowout preventer includes variable ram packers for sealing about tubular of

different outside diameters in the bore of the preventer housing or about a single tubular having a

variable outside diameter. Each ram packer includes a body of elastomeric material formed about

vertical ribs to conform to tubular having variable OD within a certain range.

Pipe Ram

A type of sealing element in high-pressure split seal blowout preventers that is manufactured

with a half-circle hole on the edge (to mate with another horizontally opposed pipe ram) sized to

fit around drillpipe. Most pipe rams fit only one size or a small range of drillpipe sizes and do not

close properly around drillpipe tool joints or drill collars. A relatively new style is the variable

bore ram, which is designed and manufactured to properly seal on a wider range of pipe sizes.

Responsibilities for Well Control

Primary well control shall be maintained at all times. In the event secondary control becomes

necessary, the well shall be brought back under control as safely as possible.

For each well control operation all personnel shall have a pre-assigned task appropriate to their

function. All personnel shall also ensure familiarity with Company well control procedures.

The well control responsibilities during well killing operations are given in the following table.

Activity Execution Quality Control

Ensure all preparations,

personnel certification

and drills meet

Company requirements

Drilling Contractor

Drilling Supervisor

Drilling Supervisor

Operations Engineer

Ensure emergency barite

stocks are on site

Mud Engineer Drilling Supervisor

Ensure well control

equipment tested and

fully functional

Drilling Contractor Drilling Supervisor

Ensure all personnel are

informed of their pre-

assigned tasks

Drilling Contractor Drilling Supervisor

Ensure kick drills are

carried out routinely

Drilling Contractor Drilling Supervisor

Record slow circulating

rates as required (after

mud wt. change or every

500 ft drilled)

Drilling Contractor Drilling Supervisor

Identify and shut in well

flow, inform Drilling

Supervisor

Driller Drilling Supervisor

Monitor shut-in and

record kick data

Drilling Contractor Drilling Supervisor

Perform calculations and

plan kill procedure

Drilling Supervisor

Drilling Contractor

Toolpusher

Drilling Supervisor

Preparation of kill mud Mud Engineer Drilling Supervisor

Ensure well is secure,

kill data collected and

kill calculations are

properly performed

Drilling Supervisor

Drilling Contractor

Toolpusher

Drilling Supervisor

Hold a pre-kill meeting

with key personnel

Drilling Supervisor

Drilling Contractor

Drilling Supervisor

Supervise rig crew

during kill

Drilling Contractor Drilling Supervisor

Co-ordinate activities of

Drilling Contractor and

3rd party contractor

personnel throughout

operation

Drilling Supervisor

Drilling Contractor

Drilling Supervisor

Responsibilities of the Drilling Supervisor

The ultimate authority and final decisions in well control situations lies with the Company

Drilling supervisor.

The Drilling Supervisor shall take charge and shall have overall responsibility for well control

emergencies. He shall work in close co-operations with the Drilling Contractor Toolpusher

during the emergency.

Types of emergencies include a kick, hydrogen sulphide encountered, blow out, fire/explosion

and evacuation offshore/onshore.

Responsibilities of the Drilling Contractor Toolpusher

The Drilling Contractor Toolpusher has the primary responsibility for the implementation of

policies and procedures on well control form instructions given by the Company Drilling

Supervisor.

DAY-3 --------------- Session - III

Rotating Head (RCDs)

A rotating, low pressure sealing device used in drilling operations utilizing air, gas, or foam (or

any other drilling fluid whose hydrostatic pressure is less than the formation pressure) to seal

around the drill stem above the top of the BOP stack.

Rotating head” means a rotating, pressure sealing device used in drilling operations utilizing air,

gas, foam, or any other drilling fluid whose hydrostatic pressure is less than the formation

pressure.

A rotating control head functions as a rotating flow diverter and diverts the drilling flow of

lubricants and drill clippings away from the drill stack. The rotating flow diverter is mounted on

top of the BOP stack beneath the drilling floor of the drilling rig (typically on top of the annular

preventer).

The main purpose of a rotating control head is to enhance personnel safety and environmental

protection. In many applications, the well is being drilled underbalanced (the formation pore

pressure exceeds the well bore pressure). If a permeable zone is encountered, the rotating control

head provides the primary barrier shielding the rig floor from a release of formation fluids. The

BOP stack provides additional barriers if the rotating control head fails or if its working pressure

rating is reached.

Example underbalanced drilling applications include drilling with natural gas, air, foams, or mist

in impermeable rock; flow drilling (also called producing while drilling); and geothermal drilling

(steam wells).

In other drilling applications, the well is drilled with sufficient mud density to control formation

pressure, and the rotating control head provides a secondary barrier to the release of well fluids

at the rig floor. Example overbalanced drilling applications include drilling in an

environmentally sensitive area with a closed loop system, drilling with oil-based muds, drilling

in an area known to contain H2S, drilling while reverse-circulating, and drilling in extremely

cold climates.

In addition to these drilling applications, workover operations involving the use of nitrogen or

other gases also sometimes call for the use of a rotating control head.

Gas or Air drilling

Air and natural gas drilling were some of the first applications of rotating control heads, and

these applications continue to account for a significant number of the units in service. Air or gas

drilling can be used for intervals of a borehole that have a high rock strength and a very low

permeability, such that the borehole will not collapse and the well cannot flow. The drilling rate

possible with air or natural gas is usually at least twice as fast as that with clear water and four

times as fast as that with mud.

A typical equipment arrangement for this application. A rotating control head diverts potentially

hazardous gas and dust away from the rig floor through a blooie line to a reserve pit that is

located at least 200 ft from the rig.

If natural gas is used, the gas is burned continuously at the end of the blooie line. When natural

gas is not available in the field, air can be used as the circulating fluid. Multiple compressors

may be needed to provide the necessary air pressure and flow rate. Small amounts of formation

hydrocarbons mixed with compressed air can be explosive. Also, spontaneous combustion can

occur downhole.

During air drilling, the rotating control head is an essential safety device needed to protect the rig

floor area from explosions and fire. A rotating control head working pressure of 500 psi is

generally used for this application. A conventional blooieout preventer stack is used below the

rotating control head to allow the well to be shut in if an unexpected permeable formation is

encountered, and the well begins to flow.

When formations that produce small volumes of water are encountered, the rock cuttings tend to

stick together and no longer can be easily blooien from the well. This problem can sometimes be

solved by injecting a mixture of soap and water into the gas stream to make a foam-type drilling

fluid. Drilling rates with foam are generally less than with air but more than with water or mud.

Depending on the capability of the formations to produce water, a mist-type flow pattern could

be more economical than foam.

Flow drilling

The fastest growing application of rotating control head technology is flow drilling or producing

while drilling. This technique often is used in horizontal wells drilled into fractured formations

having a low permeability matrix, such as the Austin chalk or the Bakkan shale. Flow drilling

has also been practiced in horizontal wells to exploit coal gas methane.

One of the most difficult problems to solve in drilling a horizontal well is to prevent formation

damage or plugging of fractures during drilling and completing the well. If these problems are

not addressed, the productivity of a horizontal well will be much less than expected from

theoretical calculations and could be uneconomical.

In flow drilling, the productive zone is drilled underbalanced so that flow is from the formation

to the well. The formation must be competent enough so the borehole will not collapse because

of the pressure underbalance.

Because maintaining underbalance during tripping operations may not be possible, clear fluids

are usually used to minimize damage during these periods. If clear fluids are not economically

feasible for the density range needed, then the mud should be designed to minimize formation

damage to the extent possible.

A typical surface equipment layout for flow drilling. A rotating control head is used to divert the

flow from the wellhead through the surface separation facility. The sizing and configuration of

the surface equipment must be carefully designed to allow drilling to proceed safely. The size of

the separators and flare lines must be large enough to handle the maximum anticipated peak gas

rate from the well. Flow drilling should not be attempted if an upper limit of gas flow rate cannot

be estimated and designed for with a high degree of confidence.

The maximum operating pressure of the separator is set by the depth of the liquid seal (U-tube)

placed in the ground downstream of the separator and the density of the drilling fluid. The liquid

seal design shown has been found to be much more dependable than float-controlled valves

previously used for this application.

The working pressure of the rotating control head or equivalent safety device must be large

enough to prevent too much liquid from being unloaded from the well when a highly gas-

contaminated region of fluid is pumped to the surface.

During flow drilling, a kick is usually taken when a fractured portion of the reservoir is

penetrated. Drilling is not stopped to circulate the kick to the surface in the conventional manner,

however. Instead, drilling continues with the choke wide open and the well bore pressure below

formation pressure by the desired amount of underbalance.

When cross flow between different fracture systems is not too severe, a constant underbalance

can be maintained while the kick is circulated to the surface if the drilling fluid density, pump

rate, and circulating drill pipe pressure are held constant. The flow from the fractures tends to

decrease with time as the compressed fluid in the fracture is depleted or the fracture zone is

drilled through.

As the kick is circulated to the surface and begins to expand, it is usually necessary to gradually

close the choke to hold the circulating drill pipe pressure constant and prevent excessive

unloading of the drilling fluid from the annulus. The wellhead pressure then increases.

The higher the working pressure of the rotating control head or equivalent device, the larger the

range of control afforded the choke operator. Also, the higher the circulating rate, the higher is

the needed wellhead pressure to prevent excessive unloading. Thus, flow drilling is especially

challenging in large diameter boreholes.

Underground cross flow within the lateral section of the well often occurs when a new fracture

system is encountered. This cross flow greatly complicates the well control strategy and often

leads to a trial and error approach, in which circulating bottom hole pressure and drilling fluid

density are varied in an attempt to again find the best operating conditions for the available

surface equipment.

The returns from the well must be constantly monitored to assist in detecting the downhole loss

of fluids. The vertical part of the well can act as a separator, with much of the drilling fluid being

lost to one fracture system while hydrocarbons preferentially flow to the surface. In many cases

in the Austin chalk, drilling continues even without returns to the surface. Cuttings are very fine

and are taken by the lower-pressured fractures.

Ideally, the entire lateral in a horizontal well should be drilled with one bottom hole assembly to

avoid tripping operations during which the underbalanced pressure condition opposite the

productive formation is usually lost. Failure of one of the components in the bottom hole

assembly (such as the mud motor, measurement while drilling tool, or bit), however, is common

before the lateral is completed.

The following is one technique used to top-kill the well during trips:

Strip back into the casing under pressure using the rotating control head.

Begin pumping a heavy fluid down the annulus while stripping out of the hole using the

rotating control head.

Pump at a rate that will fill the annulus with a volume of mud equal to the displacement

plus the capacity of the pipe being removed from the well.

The casing pressure will continually decline as pipe is pulled, and the well is usually dead by the

time the top drill collar is reached. The density increase of the kill slug can be based on the

observed casing pressure when pumping is started and the effective length of the total kill slug

volume to be placed in the well.

Another alternative is to bullhead heavy mud into the well, but this method may increase the risk

of formation damage.

Geothermal drilling

Rotating control heads are also an important component for drilling steam wells in a geothermal

field. These wells are allowed to produce steam during drilling operations.

Because the location of the fractures and hot rock are often difficult to predict, the quality of

steam coming from the well is continuously monitored. Drilling is stopped when steam of

sufficient quality is produced.

A high working pressure is not needed for geothermal drilling, and dual rubber sealing elements

(with dual clamps) are available that will allow a seal to be maintained on both the drill pipe and

the drill collars.

The top seal is removed when the top drill collar is reached, and the lower seal becomes

effective. When the bit reaches the surface, the blind rams can be closed below the bit to seal

against steam production while the bit is changed.

Overbalanced drilling

Flow through the rotary table is also possible during overbalanced drilling. The gas contained

within the pore space of the rock being destroyed by the bit will always become mixed with the

drilling fluid. This gas is often called drilled gas. If an oil-based drilling fluid is used, the drilled

gas will normally dissolve in the mud. When the mud containing the dissolved gas is pumped

near the surface, however, the release in hydrostatic pressure allows the gas to come out of

solution.

Hazardous situations can result in which the gas/mud mixture is violently spewed through the

rotary table. Cases have been reported in which oil mud and gas spewed to the crown block

while the blooie out preventers were being closed.

Even when a water-based mud is being used, drilled gas can cause severe gas cutting at the

surface. This gas cutting is particularly dangerous in H2S areas. Rotating control heads can

provide a secondary barrier in addition to the mud hydrostatic pressure to provide additional

personnel safety and environmental protection. In environmentally sensitive areas with zero-

discharge requirements, a rotating control head helps to maintain a closed loop system.

One recommended arrangement for containing drilled gas is to use a flow line degasser upstream

of the shale shaker. This arrangement also provides a convenient location for sampling and

monitoring mud gas composition.

Rotating control heads can also function as an annular pack-off device in a diverter system

designed to handle unexpected shallow gas flows. In some cases, the shallow gas kicks reach the

rig floor before the rig crew has time to close the diverter head.

Some operators use a rotating control head as a backup system to a diverter head in extremely

cold climates where the hydraulic control lines to the diverter head have an increased risk of

freezing.

Workover operations

Many workover operations are conducted with snubbing units with coiled tubing or small

diameter drill pipe. The new high-pressure rotating control heads offer economical conventional

methods of well re-entry for some of these applications that do not require extremely high

surface pressures.

The high-pressure rotating heads offer some advantages for making bit trips or running fishing

tools which require stripping and rotating the drill pipe to complete the workover task

successfully.

Rotating control heads can also be used for special drilling or milling situations which call for

reverse circulation of the cuttings up the work string while the pipe is rotated from the surface.

Rotating control heads have also been used when nitrogen or other gases were injected into the

well bore.

Operating guidelines

Sealing elements used in rotating control heads have a finite service life. Hard banding on drill

pipe, tong marks on drill pipe and saver subs, sharp edges on Kellys and Kelly cocks, and BOP

stack misalignments all reduce sealing element life.

The three-sided design of the tri-kelly is better for rotating heads than a hex-kelly because of the

larger radius used to round the corners. The hex-kelly is better than a square Kelly for increased

sealing element life, however. A square Kelly cannot be used with the high-pressure rotating

control heads.

There is no means for rotating the sealing elements of a rotating control head with the pipe when

a top drive is used to rotate the drillstring. This slightly reduces the life of the sealing element in

a rotating control head. Because drill pipe is round, however, the rate of wear is not as great as

would be present if the Kelly were rotated inside a stationary sealing element.

Periodic inspections should be conducted to ensure that the center line of the BOP stack is

maintained within 1/2 in. of alignment with the center line of free hanging pipe. The drillstring

(including all components to be stripped through the stripper rubbers), kelly, and kelly cock

should also be inspected periodically for external damage and tong marks.

Changing sealing elements only after a leak develops is bad practice. Each sealing element

should be inspected during every trip and at least once a day. For flow drilling operations, it is a

good idea to inspect the sealing elements at least once per tour.

The elements should be changed whenever uneven wear is detected or when about 50% of the

useful life has been expended. In addition, the rotating control head should be pressure tested to

its working pressure whenever the BOP stack is tested.

In H2S areas, it is imperative that H2S monitors be used and maintained in calibration. Flow

drilling should be stopped if H2S is detected in the air.

Rig Crew Training

It is important to include the rotating control head in the routine training program used for field

personnel. Operation and inspection procedures should be established before drilling begins.

BOP drills must address the type of operations conducted. In underbalanced drilling, emphasis

must be placed on monitoring pressures while drilling and during stripping operations. It is

important for field personnel to understand the pressure criteria being used to discontinue drilling

and the additional pressure barriers afforded by the BOP stack. Contingency plans for various

potential problems, such as seal failures, H2S detection, and fires, should be developed and

practiced.

The standard kill sheets and procedures usually taught in well control schools do not apply to

flow drilling operations. Prior to becoming involved in flow drilling operations, the crew should

have more specialized training in the kick circulation procedures to be used.

High-Pressure Rotating Head

In a high-pressure rotating control head, steel-reinforced rubber elements provide the seal around

the Kelly or drillstring, allowing all of the annular well fluid to be diverted to the flow line or

choke manifold. The use of multiple rubber sealing elements provides redundant protection

against a sudden large leak and allows a higher working pressure.

The type of rubber used can be varied to provide optimal protection for the fluid composition and

temperature expected in the return flow. The shape of the sealing element can be selected to

cause the closing forces pressing the seal against the Kelly or pipe to be assisted by wellhead

pressure.

Wear because of Kelly rotation can be eliminated by allowing the sealing elements to rotate with

the Kelly. The rotary force is transmitted to the sealing assembly by means of a kelly-driven

bushing that has an inner passage matched to the shape of the Kelly.

The bushing rides on the Kelly and drops into the rotary drive of the control head when the kelly

is lowered. Dogs on the kelly-driven bushing engage the rotary drive of the rotating control head

when the Kelly is rotated. Wear of the sealing elements still occurs from vertical pipe movement

through the sealing elements and is caused primarily by the tool joints, rough hard banding,

sharp edges on the Kelly, and tong marks.

The difficulty of manufacturing an effective high-pressure seal with an acceptable operating life

increases tremendously with the diameter of the tool joints. Drill pipe with a 4.5-in. OD is most

commonly used in high-pressure rotating head applications; however, newer designs that can

also accommodate 5-in. drill pipe are becoming available.

A bearing assembly allows rotation of the inner seal assembly within a stationary outer housing

or bowl. The bearing assembly must resist and operate under a large upward thrust caused by the

wellhead pressure. For example, an operating pressure of 1,500 psi in an 11-in. bore containing

4.5-in. pipe would cause an upward force of 118,000 lb.

An oil lubricating system maintains a constant flow of filtered oil through the bearing assembly.

In addition, a chilled-water circulating system removes heat caused by rotation under a high

thrust load. A power unit skid contains the water chiller, the oil and cooling-water reservoirs, the

circulating pumps, and controls.

The bearing and seal assembly lock into a lower bowl. Connections to the flow line and blooie

out preventer stack are also an integral part of the bowl.

A hydraulically operated clamp at the top of the bowl allows the bearing and seal assembly to be

inserted or removed quickly from the bowl. Typically, the bearing and seal assembly are lowered

into place through the rotary table by riding on the last joint of drill pipe (just above the top drill

collar) when the drillstring is run in the well.

Similarly, the bearing and seal assembly are removed through the rotary table above the top

collar when the drillstring is tripped out of the well. A remote monitoring console is generally

used on the rig floor to provide the driller with wellhead pressure, oil pressure, and hydraulic

clamp pressure information. The control system for operating the hydraulic clamp is also located

in this rig floor unit.

Usually the well is dead when the bottom hole assembly is tripped. Killing the well during trips

is not thought to cause significant formation damage as long as clear fluids are being used to drill

the well.

A typical blooie out preventer (BOP) stack containing a rotating control head. The rotating

control head is located at the top of the stack and provides a barrier to release of fluids beneath

the rig floor when the seal assembly is in place.

Flow from the well could be routed either through the atmospheric pressure flow line (blooie

line) or through the high-pressure choke line to surface separation equipment. An annular

preventer is usually placed just below the rotating control head and provides the next barrier in

case the working pressure of the rotating control head is exceeded or if the stripper rubbers in the

rotating control head begin to leak under wellhead pressure. The annular preventer provides a

barrier regardless of the size or shape of the pipe in the wellhead.

Pipe rams with a higher working pressure provide a third redundant barrier available to stop flow

when drill pipe is in the well. The blind rams provide a redundant barrier that backs up the

annular preventer if no pipe is in the well.

The lower pipe rams are the last line of defense and should be used only to repair or replace

worn or leaking components in the stack above this point. This example arrangement in would

not permit high-pressure ram-to-ram stripping operations unless an auxiliary BOP stack were

added on top of the existing preventers.

Cup Tester

Cup Type Tester assembly consists of a Mandrel, Sub

and F cup type Tester. The F cup type tester assembly

is attached to the drill pipe and lowered into the casing

below the well-head to test the strength of the annular

blow-out preventer in pressure.

The Cup Tester is designed for the pressure test of

casing string and blowout preventer stack in drilling.

When the casing has been run and well bead equipment

has been installed in the oil or gas well, it works for

primary laying pressure testing for casing and blowout

preventer stack in an easy and reliable manner. The

leather cup of plug is made of special super rubber

materials; the sealing working pressure is up to 70

MPa.

Test Plug

It used for same purpose but different in shape.

PVT (Pit Volume Totalizer)

A device that combines all of the individual pit volume indicators and registers the total drilling

fluid volume in the various tanks.

A volume monitoring system that measures, calculates, and displays readings from the mud

system on the rig to alert the rig crew of impending gas kicks and lost circulation issues.

Changes in pit volume during the drilling of a well can indicate possible well control or related

problems. A PVT with high/low alarm can detect an increase in fluid volume in the pit caused by

formation fluid or gas invading the wellbore. These invading fluids displace mud from the

wellbore which shows up proportionately as a mud volume increase in the drilling pit. Gradual

formation fluid invasion into the wellbore which may not be noticeable during drilling can also

be detected by a PVT. This is valuable information, considering that any change in the mud

properties can affect primary well control. Gradual fluid loss into porous or weak zones is also

important in formation that may be detectable only on a PVT. Figure 20is a PVT chart recording

of pit mud volume changes.

Flow Sensor

The mud flowing back from the borehole is filled with solid matter that gets dragged along. This

solid matter can cause blockage in the return line, which can interrupt production or damage the

drilling head. For this reason, the entire mud return system must be closely monitored.

A flow sensor is very much like a PVT, showing increases or decreases in amount of mud

coming from the wellbore. Unlike a PVT, which indicates total volume in barrels, a flow sensor

records percent of mud flow coming from the well. The flow sensor also records on a time chart

and can be installed with high/low alarms. Changes in flow occur normally during drilling

operations when making connections, increasing circulating pressure, and during other

operations. Although these flow changes are normal, a sudden increase or decrease during

drilling, tripping, or circulating can alert crews to an unpredicted change inflow which may relate

to primary well control. Figure 21 is a flow sensor chart recording of flow variations during

drilling operations. The use of trip tanks, PVTs, and flow sensors is not generally required in

Michigan operations, although many prudent operators use some or all of them. Special

requirements for drilling in particular areas call for their use.

Mud Gas Separator

Mud Gas Separator is commonly called a gas-buster or poor boy degasser. It captures and

separates large volume of free gas within the drilling fluid. If there is a "KICK" situation, this

vessel separates the mud and the gas by allowing it to flow over baffle plates. The gas then is

forced to flow through a line and vent it to a flare. A "KICK" situation happens when the annular

hydrostatic pressure in a drilling well temporarily (and usually relatively suddenly) falls below

that of the formation, or pore, pressure in a permeable section downhole, and before control of

the situation is lost.

It is always safe to design the mud/gas separator that will handle the maximum possible gas flow

that can occur.

The principle of mud/gas separation for different types of vessels is the same.[3]

Closed bottom type

Open bottom type

Float type

The closed-bottom separator, as the name implies, is closed at the vessel bottom with the mud

return line directed back to the mud tanks. Commonly called the poor boy, the open-bottom mud

gas separator is typically mounted on a mud tank or trip tank with the bottom of the separator

body submerged in the mud. Fluid level (mud leg) is maintained in a float-type mud gas

separator by a float/valve configuration. The float opens and closes a valve on the mud return

line to maintain the mud-leg level. According to pedestal or base type there are

Fixed type

Elevating type

Poor boy degasser in China is usually named according to vessel diameter.

Principle of operation

The principle behind the mud gas separator is relatively simple. On the figure, the mud and gas

mixture is fed at the inlet allowing it to impinge on a series of baffles designed to separate gas

and mud. The free gas then is moved into the flare line to reduce the threat of toxic and

hazardous gases and the mud then discharges to the shale shaker and to the tank.

Bore Protector and Bore Protector Handling Tool

During the drilling cycle, when drill bits or other service tools are landed or retrieved, damage

can be incurred to the bore of the casing suspension housing. Because of this, many operators opt

to preserve the internal preparation of the suspension housing with a bore protector. The bore

protector is retained inside the casing suspension housing and is isolated from the housing bore

by means of elastomer O-rings. The bore protector is manufactured close to tolerance of the

casing suspension housing and features dove-tailed seal grooves; for more secure retention of the

O-rings during landing and retrieving operations. Bore protectors are available for type "GC- 22"

and type "GSB" casing suspension housings.

Retrievable Wear Bushing & Tie-Down Flange Assembly

Like the bore protector, a wear bushing is available for all Galaxy "GC-22" and "GSB" series

casing suspension housings. Its purpose is the same as that of a bore protector - to preserve the

internal preparation of the casing suspension housing. Unlike the bore protector, the wear

bushing is retained in a tie-down flange assembly. Therefore, tie-down flanges must be

employed whenever wear bushings are employed.

Test Plug Assembly

The primary purpose of this tool is for testing of the blow out preventer stack above the casing

head housing. The Galaxy design test plug is a four part assembly consisting of:

1. Test plug body with seal rings

2. Test plug bushing with seal rings

3. Retaining nut

4. Inner plug (when operator specified)

The test plug assembly is lowered on the drilling string to its seating position in the casing head

housing or casing head spool. Galaxy's test plugs are normally equipped with a 4 1/2" female

internal flush (IF) threaded connection on top and a 4 1/2" male internal flush (IF) threaded

connection on the bottom. Connections with other thread profiles in 4 1/2" can be provided upon

request. Frequent inspection and service is recommended.

All drilling assistance tools including: bore protector handling tools, wear bushing tie-down

flanges, double studded or drilled pack-off flanges, spacer flanges and test plug assemblies, are

available from Galaxy on a rental basis. Due to the expendable nature of bore protectors and

wear bushings, these items are not available on a rental basis.

DAY-3 --------------- Session - IV

Ring joint gaskets

There are several API types of ring gaskets used in BOP connections and this is very important

to personnel involving in drilling operation to know about it. API 6A: Specification for Wellhead

and Christmas Tree Equipment is the standard which every manufacture refers to their

equipment.

API Type R Ring Gasket

The API type “R” rig gasket is not a pressure energized gasket therefore this type does NOT

recommend for BOP equipment or safety critical equipment as x-mas tree, wellhead valves, etc.

Sealing area is along small bands of contact between the gasket and the ring gasket on both ID

and OD of the gasket. Shape of type “R” may be oval or octagonal in cross section (see Figure

1). Additionally, face to face between flanges will not touch when the flanges are tightened (see

Figure 2). The “R” gasket is compatible for 6B flanges.

Figure 1 - Type R ring gaskets (shape and groove)

Figure 2 - Type “R” Gasket When Energized

API Type “RX” Ring Gasket

RX ring gasket is a pressure energized ring joint gasket and sealing area when energized is along

small bands of contact between the groove and the OD of the ring gasket (see Figure 3). This

gasket is manufactured a little bit bigger in diameter than the ring groove therefore when it is

compressed, it will deform and seal the pressure. The “RX” is also not a face to face contact (see

Figure 4). This gasket must be utilized only one time. The “RX” gasket is compatible for 6BX

flanges and 16B hubs.

Figure 3 - Type RX Ring Gasket (Shape and Groove)

Figure 4 - Type “RX” Gasket When Energized

API Face-to-Face Type “RX” Ring Gasket

The face-to-face “RX” ring gasket is similar to “RX” gasket except it has increased groove width

to ensure face to face contact between flanges or hubs (see Figure 5). However, this leaves the

gasket unsupported on its ID. It is pressure-energized gasket which was adopted by API. This

gasket may not remain in a perfect round shape when it is tightened because it does not have the

support from ID of the ring groove.

Figure 5 – Face-to-Face Type “RX” Ring Gasket

API Type “BX” Ring Gasket

API Type “BX” (Figure 6) is a pressure energized ring and it is designed for face-to-face contact

between hubs or flanges. When energized, small contact bands between OD of the ring gasket

and the rig groove is the sealing area. This ring gasket is slightly bigger than the ring groove.

Therefore, when the hubs or flanges are tightened, the gasket will be slightly compressed into the

rig groove to seal pressure (see Figure 7). Since this is face-to-face contact type, the tolerance of

the gasket and ring groove is vital. If you have the gasket at the high side of tolerance and the

groove at the low side of tolerance, it will be quite difficult to achieve face-to-face contact. The

“BX” gasket is compatible for 6BX flanges and 16BX hubs.

Figure 6 - API Type “BX” Ring Gasket

Figure 7 – API Type “BX” Ring Gasket When Energized