subsea - page 6

SurfaceWell Control

Equipment

Subsea Engineer’s Handbook Section 6

In-Spec Inc. 1999 Surface Well Control Equipment

Table Of ContentsSection 6

Page

1. Introduction 1

2. Chokes 2

3. Choke Manifold and Inspection Points 5

4. Diverters 6

5. Diverter, How the Hydril FS Operates 10

6. Diverter Operation and Inspection Points 14

7. High Pressure Mud Hoses 14


In-Spec Inc. 1999 1 Surface Well Control Equipment

The Complete Well Control System



The Choke and Kill Manifold

(1) IntroductionChoke Lines - Remember from our brief discussion earlier about circulating out akick, it is necessary to hold back pressure on the annulus in order to regulatebottom-hole pressure, usually within a fairly close margin. Outlets under the ramsallow us to circulate mud from the wellbore, through the subsea valves, and up highpressure choke and kill lines to the choke & kill manifold on the rig.

An adjustable choke can better regulate pressure than a positive choke that has afixed opening. Shale or lost-circulation material in the mud frequently plugs eithertype. Fluid abrasion causes rapid erosion of the metal seats. Two types ofadjustable chokes are available, manually adjustable and hydraulically operatedchokes. Hydraulic chokes are more easily adjusted and permit accurate regulationof choke pressure. A manual choke requires that the operator be physically close tothe manifold while making adjustments. This frequently is an uncomfortableposition. A 15,000 psi WP choke & kill manifold is shown on the opposite page. Forredundancy it contains 2 remote chokes and 2 manual chokes.

Well pressure, is first reduced through the choke, then passes through theatmospheric mud-gas separator (also called the poor boy separator) before gas isvented to the atmosphere through the vent line up the derrick.

Kill Lines - If drill pipe is not in the well we need another means to pump kill mud intothe hole. This function is very rarely used since it is not a practical method to kill thewell.

API Specification 16C, Specification for Choke and Kill Systems, outlines therequirements for a newly manufactured choke and kill manifold and associatedvalves to allow the equipment to receive the API monogram.

The following points should be noted when considering the Choke and Kill outlet lineand manifold arrangement.

1. Be able to choke flow from the choke line when pipe rams are closed.

2. Flow in the manifold when circulating out kick should be as direct as possible tothe remote choke primarily used for this.

3. Pumps, mud and cement unit, should be able to pump down the kill line.

4. When pipe is hung off with hang-off tool or after shearing pipe, the kill line shouldbe in position to pump down the drill pipe and choke line in position to takereturns through the remote choke.



5. The kill line should be easy to line up for use as a back-up choke line.

6. The back-up remote choke or manually adjusted choke should be easily lined upfor use if the primary remote choke plugs-up or becomes eroded.

7. Manual valves to be placed between each choke and the buffer tank behind it toallow opening the choke bonnet for service while continuing to circulate out thekick.

2) ChokesAn important feature of a remote choke is that the choking device can be placed inthe choke manifold, wherever the manifold is located, but casing and drill-pipepressures are read remotely on a panel that can also be used to control the choke.The remote panel contains an instrument panel for controlling a hydraulic chokewhen handling a well kick. Drill-pipe and casing pressures are read remotely, thepanel gauges being connected by hoses to pressure sending units, either hydraulicor air. Pump speed is read directly on a pump rate meter, and cumulative pumpstrokes are indicated by a counter. This unit makes it possible to hold back pressureon the casing within very precise limits while circulating out a kick. Two commonmanufacturers of hydraulic chokes for blowout-preventer service are Cameron andSwaco.

The inlet flange nominal size and pressure rating usually determine the nominal sizeand pressure of the choke bonnet assembly. Chokes, which have an inlet flange witha higher pressure rating than that of the outlet flange have a double pressure rating.The rating of the inlet flange, body, and bonnet assembly determine the maximumrating of the choke. The rating of the outlet flange may be a lower pressure. This isin API Spec 16C, section 9.9.5 & 9.9.9.

CAMERON 3-1/16” - 10,000 psi WP REMOTE CHOKE



Chokes are, by definition, devices to restrict and regulate the flow of well fluids andare not intended to be used as shut-off valves. For this reason, it is generally notconsidered necessary for manual chokes to provide a positive fluid tight shut off.The Cameron choke in the remote choke diagram has a reduction in the seatdiameter to make a metal to metal seal with the needle. It is a CSO choke(complete shut off). The same choke without the reduction in seat diameter in not aCSO choke and is not designed to form a leak tight seal. Which choke are youtrying to get a test on?

In manual chokes, such as the one below, it is imperative that the needle not beforced against the seat in an attempt to get a pressure test. To do so will generallyresult in damage to the brittle and expensive tungsten carbide needle and seats.They should not be forced closed in an attempt to get a fluid tight seal.



3) Choke Manifold Operation and Inspection Pointsa) Well control (manifold and drill pipe pressure) pressure gauges should be

calibrated on a regular schedule.b) Targets in subsea valves, choke & kill lines, and in the choke & kill manifold

should be inspected for erosion and secure lead content.c) A schedule should be in place to flow through the mud-gas separator to verify

open flow.d) A schedule should be in place to function test the chokes checking for rapid

operation and correct operation of the position indicator.



4) Diverter

The diverter is the upper most item in the riser string, under the rotary table, used tostop the flow of gas and mud in the event of a rapid gas release from the wellbore.

Traditionally, a diverter was used when taking returns to the surface while drillingsurface hole, prior to running the 20” casing string and BOP stack. This approach isnow used only when drilling on a template and surface cuttings can not be dumpedon the sea floor.

Remember, in deepwater we have 2 “wells”. One controlled by the BOP stack andthe other above the stack, controlled by the diverterAs the name implies, when closed the diverter diverts any wellbore fluid flow awayfrom the rig floor and does not attempt to contain it as does a BOP stack.



The diverted fluid flows through large diameter overboard lines. To avoid erosionthey are constructed large in diameter and as straight as possible. Any bendsshould be (in order of preference :

• Non-existent• Gradual with double wall thickness on outside wall• Targeted if not gradual

Typically diverter assemblies are rated to 200 to 500 psi and tested at the factoryduring initial manufacture. It is generally difficult to pressure test the system onceinstalled on the rig. Typically, the telescopic joint packer under the diverter will berated to a lower pressure than the diverter. As such it is usually the telescopic jointpacker which will then determine the system’s working pressure

API discusses recommended diverter installation and operation in 2 RecommendedPractices. API Recommended Practices for BOP Equipment, RP-53, brieflydiscusses diverter installations in section 5.0. API Recommended Practice forDiverter Equipment, RP- 64, provides more complete guidance. Highlights of thisRP are listed below :

a) RP-64 states that diverter lines 10” ID should be considered minimum diameterwith 12” ID or larger the preferred size. Section – 5.6

b) The valve actuators should be able to operate the valves in the diverter systemwith system’s minimum rated working pressure across the valve. Section – 3.4.2

c) For non-integral valve installations where the flow line is below the annularsealing device, the desire vent valve(s) should be opened (if not already open)while simultaneously closing the shale shaker (flow line) valve and the diverter.Regardless of the vent valve sequencing, at least one vent vales should remainopen at all times to prevent a complete shut in of the well. Section - 3.7.1.

d) Emergency action procedures should be prepared prior to spudding the well.Section - 6.1.2.2

e) After installation of the diverter and before use, operate the diverter whileactuating all diverter close and open sequences with pipe in the diverter to verifyproper operating sequences and interlocks. Sec. 6.1.3

f) Pump water through the diverter system at low pressure and high rates, checkingthe overboard vent lines for returns. Section – 6.1.3.6







5. Diverters, How the Hydril FS Operates

1. Located under the rig floor to divert the flow of kick fluids, mud and gas, out of theriser and down the selected overboard diverter (vent) line(s).

2. Closes in a similar manner to a large bore 20” annular preventer.

3. At the same time the operating ported piston closes the sealing element, a second

internal piston, the sleeve, rises to simultaneously open a diverter line outlet plusclose the flow line, trip tank, and fill-up line outlets. This prevents the possibility ofclosing the diverter and accidentally having the overboard diverter lines closed at thesame time. This accident would place the riser under pressure. The most likelyweak point to begin leaking would be the telescopic joint packer.



4. The anti rotation dog in thehandling tool must engage thediverter assembly after the toolis stabbed into the assembly.Then rotating the mandrel clock-wise approximately 10-turns willpull the cam ring upwards andengage the dogs into thecorresponding groove in thediverter assembly bore. Thedesign load rating is 750 tons.

5. Prior to installing the diverterassembly into the diverterhousing, ensure that thehydraulic stabs and diverterassembly latch dogs are in theretracted position.1 The latch dogs are hydraulically extended and retracted whilethe hydraulic stabs are spring extended and hydraulically retracted.

1 They should have already been placed into the retracted position while running the riser.



6. The extend/retract and hydraulic open/close circuits are shown in the diagrambelow.

The FS diverter packer is closed on drill pipe and opened with 1,500 psi operatingpressure. Hydril recommend that the lowest operating pressure be used which willachieve a seal. This pressure may be less than 1,500 psi. The diverter may beclosed on open hole2 if the need should arise.

7. The diverter should not be closed if pipe larger than 13 3/8” OD is in the diverter.The steel segments in the sealing element may indent the casing.

8. During normal drilling operations, tripping into the hole and pulling pipe out of thehole, the diverter should be maintained in the “open” position to ensure that the flowline, trip-tank line and fill line are all fully open.

2 “open hole” is when no pipe, tubing, or casing is in the diverter. It is also called CSO or complete shut-off.



6. Flow Selector

Downstream of the diverter in the diverter overboard line, the flow selector is used todetermine which overboard line is used when diverting fluids overboard.

The rotating plug in the flow selector replaces both the port and starboard diverter linevalves. As the flow selector plug rotates between the port and starboard positions thestarboard port is opened before the port opening is closed. The selector can not blockboth outlets at the same time.



6) Diverter Operation and Inspection Points• The KFDS diverter must never be closed on open hole or closed without an

insert packer installed.• Prior to drilling, function test every diverter line and flow line valve.• Function test the interlock which prevents the diverter from being closed without

the diverter packer lock down dogs being engaged.• Function test the interlocks/sequences which open the vent lines and close the

flow line when the diverter is closed.

7) High Pressure Mud Hoses

a) Choke & Kill Moon pool Drape Hoses and Flex Joint Hoses

Flexible high pressure hoses are robust and require little maintenance, but, theymust not be neglected. They need to be inspected and tested on a regular basisto ensure that they are capable of the duty which we expect of them. Internalhose damage and braid corrosion if left undetected can lead to hose failure.

The inspection and test requirements and frequencies for some commonly usedhoses are listed below :

ManufacturerCoflexip Copper State Goodall

Recommended visualinspection interval

Annual fullinspection

Monthly fieldinspection on

rigDaily 6-Month

Visual inspectionareas

Fullexternal

andinternalvisual

inspection

Full externalvisual

inspectionVisual inspection External and internal

tube

Pressure testingfrequency Annual Monthly

6-month orimmediately aftera gas kick (1.25xWP for 5minutes)

6-month orimmediately after a kick(1.25x WP for 5minutes)

Test pressure 1.5x WPfor 6 hr.

1.1x WPfor 1 hr.

1.25x WPfor 1 hr. 1.25x WP

Additional notes

If outer 2 layers ofbraid are cut or

corroded plan forhose replacement

Reference From User’ Guide, Rev. 3 from inspectionletter Aug. 3, 1989

From OperatingInstructions April 28,

1989

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subsea - page 6