Iranian Classification Society Rules

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SECTION 2 Well Control System

201. General

1. The well control systems are consist of the following systems.

(1) Blowout preventer system

(2) Lower marine riser package (LMRP)

(3) Choke and Kill system

(4) Diverter system

(5) Auxiliary well control system

2. The well control systems are to be in compliance with recognized national standards or interna- tional standards in addition to requirements of this Annex.

202. Blowout preventer system

1. The BOP system typically consists of ram and annular type BOPs, BOP stack structural frame, ac- cumulators, connectors, clamps, drilling spools, spacer spools, control systems/consoles/panels, control pods, umbilical, flexible hoses (choke, kill, mud booster and hydraulic), hydraulic hoses, MUX , ca- ble reels, rigid piping, hydraulic power units, manifold, ROV interface, test stump and testing equipment.

2. Blowout preventer stack

(1) BOP stack configurations are to be in accordance with API RP 53 and requirements below.

(2) As a minimum, the BOP stack is to consist of the following preventers.

(A) One (1) annular preventer

(B) One (1) blind-shear ram preventer with mechanical locking device for fixed units

(D) Two (2) shear rams for moored or dynamically-positioned units, one being a blind shear ram and the other to be a casing shear ram.

(E) All ram preventers are to be provided with locking devices

(3) The BOP stack configuration is to be able to close BOPs on all sizes of drill pipe, drill collars and casing that may be used within a drilling operation.

(4)

The ram-type BOP positions and outlet arrangements on subsea BOP stacks are to provide reli- able means to handle potential well control events. Specifically for floating operations, the ar-

rangement is to provide means to:

(A) Close in on the drill string and on casing or liner and allow circulation

(B) Close and seal on open hole and allow volumetric well control operations

40 Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015

(D) Hang off the drill pipe on a ram-type BOP and control the wellbore

(E) Shear logging cable or the drill pipe and seal the wellbore

(F) Disconnect the riser from the BOP stack

(G) Circulate the well after drill pipe disconnect

(H) Circulate across the BOP stack to remove trapped gas

(5) Systems of valves are to comply with the requirements of Par 4.

(6)

(7)

For subsea BOP, the use of drilling spools is not recommended in order to reduce the overall height of the subsea BOP stack arrangements.

Spacer spools are used to provide separation between two (2) drill-through components with equal sized end connections (nominal size designation and pressure rating). Typically, they are

used to allow additional space between preventers to facilitate stripping, hang off, and/or shear

operations but may serve other purposes in a stack as well.

(8) Spacer spools for BOP stacks are to meet the following minimum specifications:

(A) Have a vertical bore diameter the same internal diameter as the mating equipment

(B) Have a rated working pressure equal to the rated working pressure of the mating equipment

(C) Are not to have any penetrations capable of exposing the wellbore to the environment, without dual isolation capabilities

(9)

The BOP equipment is to be designed for the specific drilling envelope, and suitable for the intended facility. BOP manufacturer is to specify and to attest BOP stack minimum and max-

imum capability with regard to the following including shearing and, pressure/temperature capa-

bilities:

(A) Drill pipe, tool joint, casing sizes

(B) Wire lines

(D) Pressure

(F) Temperature

(10) The BOP structural frame and lifting attachments are to be designed considering applicable loads as specified in Ch 1, 104. and in accordance with the requirements of API RP 2A-WSD or other recognized standards. Allowable stresses are to be in accordance with design standards and/or AISC.

3. Well control systems for blowout preventers

(1) The control systems and components (hydraulic, pneumatic, electric, electro-hydraulic, etc.) are to comply with Ch 6, Sec 2 and are to be in compliance with API Spec 16D, and API RP

53. This also includes response time, volumetric capacity of the accumulator system, hydraulic reservoir, pump system sizing and arrangements.

(2) the hydraulic fluids volumetric capacity of the accumulator system, pump system and reservoir

capacity for well control systems are to be in compliance with API Spec 16D, and API RP 53.

(3) Well control systems and components are to comply with the functional requirements of API RP 53 for response time, pump system arrangements, and charging of accumulator systems.

(4) BOP accumulators are to have sufficient usable hydraulic fluid volume to perform the following functions and after performing the following functions, the remaining pressure is to be 1.38

MPa(200 psi) or more above the minimum precharge pressure.

(A) For subsea BOP systems

(a) to close and open one annular-type preventer and all ram-type preventers from full-open position against zero wellbore pressure, and

(b) to open hydraulic control remote valve

(B) For surface BOP systems

(a) to close one annular-type preventer, all ram-type preventers from a full-open position, and

(b) to open hydraulic control remote valve

(5) The minimum precharge pressure for the BOP system is to be determined based on the follow- ing in accordance with API Spec 16D and API RP 53.

(A) BOP stack configuration and minimum required operator pressure

(B) Water depth

(D) Local regulations

(F) Operational sequence

Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015 41

(6) Floating installations or dynamically-positioned units require the following independent secondary

well control systems

API Spec 16D.

(A) Deadman system

(B) Autoshear system

and safety features. These systems are to be designed in accordance with

(7) If installation is provided with acoustic control system, the system is to be designed in accord- ance with API Spec 16D. The acoustic control is to be a portable control unit, which can be handled by one person, and is to be available for the closing of the BOP in the event of evac- uation from the facility.

(8)

For surface well control systems, a reserve supply of pressurized nitrogen gas can serve as a backup means to operate functions in the event that the pump system power supply is lost.

(9) As a minimum, two (2) full-functioning well control

(A) One (1) well control panel is to be at driller's from drilling activities.

(B) A second well control panel is to be located in

8 of the Rules and API RP 505, without having

panels are to be provided:

station or cabin and where it is protected

a nonhazardous area, as defined in the Ch

to cross the drill floor or cellar deck, and

is to be arranged for easy access in case of emergency.

(10) Well control panels are to be accessible and operable at all times.

(11) Well control panels are to be mutually independent and simultaneously functional (i.e., directly connected to the control system, and not connected in series).

(12) Control systems are to be arranged to ensure the operational capability upon loss of any single

component. This will include the use of functionally independent actuation lines, input/output de- vices and the provision of system isolation.

(13) The well control panels are to include controls for at least:

(A) Close or open of all rams, annular preventers, and choke and kill valves (hydraulic control remote valve) at BOP

(B) Diverter operations

(D) Emergency disconnect (DP units)

(E) Mechanical locking of rams

(14) BOP stack is to be equipped with remotely operated vehicles(ROV) intervention equipment, which at the minimum allows the closing of one set of pipe ram, closing of one each blind-shear rams, and unlatching of the LMRP. These functions are to operate independently of the primary BOP control system.

(15) ROV interface and/or receptacles are to mate with API 17H high-low stabs. Operated control systems and interventions are to be provided for subsea BOP stack for all installations.

(16) For subsea BOP stack, adequate measure is to be provided to prevent accidental unlatching of the wellhead connector until the well is secure, such as two-hand function, two-step action, pro-

tective cover or equivalent.

4. Design requirements of blowout preventer equipment

(1) Surface and subsea, ram and annular blowout preventers, including workover and well servicing BOPs, ram blocks, annular packing units, valves, wellhead connectors, drilling spools, adapter spools and clamps are to be designed, fabricated and tested by the respective manufacturers for compliance with API Spec 6A, Spec 16A, Spec 16C, Spec 16D and the additional requirements of this Annex.

(2) The working pressure of ram-type BOPs is to exceed the maximum anticipated surface pressure.

(3) Hydraulically-operated wellhead, riser and choke and kill line connectors are to have redundant mechanisms for unlock and disconnect.

(4) The secondary unlock and disconnect mechanism may be hydraulic or mechanical, but must op-

erate independently of the primary unlocking and disconnect mechanism.

(5)

In addition to the design conditions/loads listed in Ch 1, 104., the design of preventers is to consider the following loads, as applicable:

(A) The weight of a specified length of drill string suspended in the pipe ram preventer

(B) Loads induced from the marine drilling riser

(6) On fixed units, if the tool joints cannot be sheared, the following is to be considered.

(A) Two (2) shear rams must be installed as for DP units, or

(B) Lifting or lowering of main hoisting system is to be possible in all operational conditions, including emergency operation. The main hoisting system is to be included in the emer- gency power source.

42 Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015

(7) The blind-shear rams are to be capable to seal after shearing operation.

(8) The shear rams are to be capable of shearing the largest section and highest-grade of tubulars (drill pipe, casing, wireline, etc) under the design conditions and at the rated working pressure.

(9) The annular, pipe and blind ram BOP operator design pressure is to consider the following.

(A) Well bore pressure

(B) Rated working pressure of BOP

(10) Procedures to test preventers during manufacturing and "on-site" are to be developed and sub- mitted to the Society for review.

(11) For subsea BOP and associated components such as valves, control system components, sealing

components, elastomeric components, etc., are to be designed with consideration to marine con- ditions and external pressure gradient due to rated water depth.

(12) All nonmetallic materials are to be suitable for the intended service conditions, such as tem-

perature and fluid compatibility.

(13) Materials are to be in accordance with Ch 3, Sec 1.

(14) Welding and non-destructive examination are to be in accordance with Ch 3, Sec 2.

5. Operations and maintenance manuals for blowout preventer

(1) Blowout preventer manufacturers are to provide the Owner with product operations and main- tenance manuals to assist in the safe operation of each assembly on each installation.

(2) The manufacturer's recommended maintenance schedules are to be available for each component

of the assembly. These schedules are to prescribe maintenance routines.

203.

Lower marine riser package(LMRP)

1. Components of the lower marine riser package, including connectors, flex joints, and adapter spools are to be designed, fabricated, and tested by the respective manufacturers for compliance with API Spec 16F, API Spec 16R and API RP 16Q and the additional requirements of this Annex.

2. An annular BOP that is included in the LMRP is to be designed, fabricated, and tested in accord- ance with 202. and API Spec 16A, API Spec 16D and API RP 53, and the additional require- ments of this Annex.

3. Lower marine riser package disconnect arrangements are to be designed for all possible operating and loading conditions. The loading conditions of the LMRP are to consider the followings.

(1) Min/max riser angle

(2) External pressure due to static head

(3) Side loads

(4) Internal pressure

(5) Bending loads

(6) Min/max top tension

(7) Currents

4. The LMRP design is to consider the induced loads as defined in API Spec 16F and API RP 16Q, as a minimum, for the following modes.

(1) Installation

(2) Storage and maintenance

(3) Drilling

(4) Hang off

(5) Retrieval

(6) Drifting

5. For dynamically-positioned floating units, an emergency disconnect is to be provided.

6. The emergency disconnect is to initiate and complete disconnection in following sequence.

(1) Blind-shear drill string and/or casing

(2) Disconnect LMRP

(3) Close well

7. For the LMRP and associated components such as valves, control system components, sealing com- ponents, elastomeric components, etc., are to be designed with consideration to marine conditions and external pressure gradient due to rated water depth.

8. Adapter spools are used to connect drill-through equipment with different end connections, nominal size designation and/or pressure ratings to each other. Typical applications in a subsea stack are as

Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015 43

followings.

(1) The connection between the LMRP and the lower stack

(2) The connection between the lowermost BOP and the wellhead connector

9. Adapter spools for BOP stacks are to meet the following minimum specifications.

(1) A minimum vertical bore diameter equal to the internal diameter of the mating equipment

(2) A rated working pressure equal to the lowest rated end connection of the mating equipment

10. LMRP structural frame and lifting attachments are to be designed with consideration to all appli- cable loading conditions. Applicable structural design code and standard including loading conditions are provided in 202. 2 (10).

204.

Choke and kill systems

1. General

(1) The choke and kill system typically consist of would include the choke and kill manifolds, in- cluding their chokes, spools, flanges and valves, choke and kill lines, connectors and flexible hoses (drape hoses at moonpool area and jumper lines at LMRP), BOP stack fail-close valves, connecting piping from the cementing unit and drilling fluid manifold to the choke manifold, buffer tanks and control systems.

(2) Piping, flexible hoses are to be in accordance with the applicable standards for chock and kill system listed Ch 1, 101. 3 and Ch 5.

(3) Materials are to be in accordance with the applicable standards for chock and kill system listed

Ch 1, 101. 3 and Ch 3, Sec 1.

(4) Welding and non-destructive examination are to be in accordance with the applicable standards for chock and kill system listed Ch 1, 101. 3 and Ch 3, Sec 2.

2. Choke and kill lines

(1) Each choke and kill line from the BOP stack to the choke manifold is to be equipped with two (2) valves installed on the BOP stack.

(A) For surface BOP stacks, one of these two valves is to be arranged for remote hydraulic operation.

(B) For subsea BOP stacks, these two valves are to be arranged for remote hydraulic operation.

(2) The design pressure of the pipes, valves, flexible hoses, connectors, fittings, and the choke manifolds from the BOP stack to the isolation valve downstream of the choke is to be the

same as that of the ram-type BOPs or greater.

(3)

(4)

The line connected to the lowermost outlet of the BOP is to be designated as the kill line.

Placement of this outlet is to be below the lowermost pipe ram, or below the test ram, if installed.

One (1) choke line and one (1) kill line connection is to be located above the lower most ram

BOP.

(5) The choke line, that connects the BOP stack to the choke manifold, and lines downstream of the choke are to:

(A) Be as straight as practicable; turns, if required, are to be targeted

(B) Be firmly anchored to prevent excessive dynamic effect of fluid flow and the impact of drilling solids and/or vibration

(C) Supports and fasteners located at points where piping changes direction are to be capable of restraining pipe deflection in all operating conditions

(D) Have bore of sufficient size to prevent excessive erosion or fluid friction due to velocity

3. Components of choke and kill

(1) For rated working pressure of 20.7 MPa(3000 psi) and above, only flanged, welded or clamped connections, and rated hammer unions are to be used. However. for choke end connections, on- ly flanged, welded or clamped connections, and rated hammer unions are to be used, regardless of rated working pressure. Requirements in Ch 5 are to apply to piping component.

(2) For rated working pressure less than 69 MPa(10000 psi), the minimum size for the choke lines is to be 50.8 mm (2.0 inch) nominal diameter.

(3) For rated working pressure of 69 MPa(10000 psi) and higher, the minimum size for the choke lines is to be 76.2 mm (3.0 inch) nominal diameter.

44 Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015

(4) For high volume gas drilling operations, the minimum nominal diameter pipe size is to be

101.6 mm (4.0 inch) nominal diameter.

(5) Minimum size for vent lines downstream of the choke is to be at least the same internal diam-

eter as for the chokes end connections.

(6) When buffer tanks are utilized, provisions are to be made to isolate a failure or malfunction without interrupting flow control.

(7) All choke manifold valves subject to erosion from well control are to be full-opening and de- signed to operate in high pressure gas and abrasive fluid service.

4. Arrangement of choke manifold

(1) The choke and kill manifold assembly is to include the following:

(A) The choke manifold is to be designed for a minimum of three (3) chokes, of which at least one (1) is remotely controlled and one (1) is manual.

(B) Any one of the chokes is to be capable of being isolated and replaced while the manifold

is in use.

(2)

(D) A remotely controlled adjustable choke and a manual choke through either the choke or kill line.

(E) Tie-ins to both drilling fluid and cement unit pump systems.

Where changes in direction cannot be avoided downstream of the choke and kill lines are to be provided with targeted tees or elbows

system to permit control

choke and kill manifolds, fitted with a doubler plate

on the outside radius or elbows with a radius of 20 times the diameter of the pipe.

(3) Each of the manifolds' inlet and outlet lines is to be fitted

with a valve. A valve immediately

upstream of each choke is to be provided on the manifolds. All valves are to be in compliance

with API Spec 16C, API Spec 6A, and API RP 53, and the additional requirements of this Annex.

(4)

Lines downstream of the choke manifold are to permit flow

direction either to a mud-gas sepa-

rator, degasser, vent lines, or to test facilities, or emergency storage.

(5) Alternate flow and flare routes downstream of the choke line are to be provided so that eroded, plugged, or malfunctioning parts can be isolated for repair without interrupting flow control.

(6)

In the event the capacity of the mud-gas separator is exceeded, the choke manifold is to have

the capability to divert flow to alternate locations for safe discharge, such as vent lines, flare or overboard.

(7) The bleed line (the vent line that bypasses the choke) is to be at least equal to or greater than the diameter to the choke line.

(8)

Additional provisions such as targeted flanges are to be provided to minimize erosion or abra- sion from high velocity flow.

(9) The Joule-Thompson effects are to be considered in the design and material selections of choke and kill manifold and downstream piping and associated components.

5. Mud-gas separator

(1) Mud-gas separator is be designed and manufactured in accordance with ASME Boiler and Pressure Vessel Code, Section VIII and Sec 8.

(2) Piping is to be in accordance with Ch 5.

(3) Materials are to be in accordance with Ch 3, Sec 1.

(4) Welding and non-destructive examination are to be in accordance with Ch 3, Sec 2.

(5) Precautions are to be taken to prevent erosion at the point the drilling fluid and gas flow im- pinges on the vessel wall.

(6) Mud-gas separator is to be vented to atmosphere through the vent line.

(7) The vent line is be sized and designed to minimize back pressure in order to assist with max- imum separation of gas from the mud.

(8) Mud-gas separator is to be provided with high level sensor or equivalent for notification of di- verting flow to overboard or alternate route.

(9) Mud-gas separator is to be equipped with the following means to prevent gas ingress through

the mud discharge line and to monitor gas ingress.

(A) Means for pressure and temperature monitoring

(B) liquid seal of the following hight

(a) a minimum of 3 m for general purpose drilling operations.

(b) a minimum 6 m for high pressure and high temperature operations,

(10) For monitoring of liquid seals, the following means is to be provided.

(A) Measuring means for the differential pressure at the liquid seal, or

(B) Monitoring means for low-level of the mud-gas separator

Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015 45

(11) Drain is to be provided at lowest point of the mud-gas separator

(12) Sizing of the mud-gas separator is to be performed in accordance with SPE Paper No. 20430: Mud-Gas Separator Sizing and Evaluation.

(13) Design pressure of the mud-gas separator is to be determined by the vent line being filled with mud at 2.2 SG, or the specified maximum mud weight.

6. Gas vents

(1) Vent lines from mud-gas separator are to extend 4 m above the crown block.

(2) The vent system is to be as straight as possible, free of obstructions, and is to be sized and arranged to minimize back pressure in the upstream equipment of vent line.

(3) A bypass line to alternate locations for safe discharge, such as vent lines, flare or overboard

(port and starboard), as applicable, must be provided in case of malfunction or in the event the capacity of the mud-gas separator is exceeded.

(4) Overboard lines are to be directed for discharge in downwind directions and safe distance away

from facility.

7. Choke and kill flexible hoses

(1) Refer to the requirements contained in Ch 5, 203.

(2) End connectors are to be in accordance with the applicable parts of Ch 5.

8. Control systems for choke and kill system

(1) The control systems and components (hydraulic, pneumatic, electric, electro-hydraulic, etc.) are to comply with Ch 6, Sec 2 and are to be in compliance with API Spec 16C, API Spec 16D, and API RP 53, and the additional requirements of this Chapter.

(2) The choke control station is to be easily accessible and is to include all monitors necessary to furnish an overview of the well control situation.

(3) A minimum of one remote control station is to be away from the choke manifold and pro- tected to avoid any human and equipment hazards caused by leakage from the manifold.

(4) Any remotely operated valve or choke is to be equipped with an emergency backup power

source.

(5) All remote control valves are to be provided with "open" and "close" indicators on the control panel.

(6) Electrical systems are to be in accordance Ch 6, Sec 1.

205. Diverter system

1. The diverter system typically consists of annular sealing device (packer, housing), vent outlets, valves, power unit and piping, control systems/consoles/panels.

2. Diverters

(1) A diverter with a securing element for closing around the drill string in the wellbore or open hole is to be provided when it is desired to divert wellbore fluids away from the rig floor.

(2) The diverter is to be equipped with two (2) 254 mm (10 in) or larger lines that are to be pip- ed to opposite sides of the rig floor. Alternative arrangements will be specially considered and

justification in accordance with Ch 1, 103.

3. Diverter valve assembly

(1) Valves in the discharge piping are to be of the full opening and full bore type.

(2) Valves and their actuators are to be sized to be capable of operating the diverter valve under all design conditions.

(3) During the operational tests at the manufacturer’s plant, a full design differential pressure open-

ing test is to be carried out for each valve and actuator combination.

(4) The diverter valve assembly and a control system are to be designed to safely vent well bore fluids at the surface or subsea.

4. Control systems for diverters

(1) The diverter control systems and components (hydraulic, pneumatic, electric, electrohydraulic, etc.) are to comply with Ch 6, Sec 2 and are to be in compliance with API RP 64, API RP 53 and API Spec 16D. This also includes response time, volumetric capacity of the accumulator system, hydraulic reservoir, pump system sizing and arrangements.

(2) Any remotely operated valve or choke is to be equipped with an emergency backup power source.

46 Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015

(3) The diverter system is to be controlled from two (2) locations; one is to be located near the driller's console/workstation and the other is to be located at an accessible location away from the well activity area and reasonably protected from physical damage from drilling activities on the drill floor. Both controls are to be arranged for ready operation by the driller.

(4) The control systems are to have interlocks so that the diverter valve opens before the annular element closes around the drill string.

(5) When the diverter element close function is activated, the return flow to the mud system is to be isolated.

(6) The range of diverter elements is to be suitable to seal on all sizes of drill string elements on

which the diverter is required to operate.

(7) A relief valve is required to prevent overpressurization of the diverter packer.

(8) All valves are to be provided with "open" and "close" indicators.

(9) Electrical systems are to be in accordance with Ch 6, Sec 1.

5. Diverter piping

(1) Pipe size, arrangement and support is to be determined with due consideration given to max- imum pressure and maximum reaction loads, erosion resistance and the range of temperatures likely to be encountered in service.

(2) Discharge pipe slope downward from the diverter valves.

(3) Piping is to run as straight as practicable. Where changes in direction cannot be avoided, they are to be accomplished by employing targeted tees or elbows fitted with a doubler plate on the outside radius or elbows with a radius of 20 times the diameter of the pipe.

(4) Piping is to run as straight as practicable. Where changes in direction cannot be avoided, they are to be accomplished by employing targeted tees or elbows fitted with a doubler plate on the outside radius or elbows with a radius of 20 times the diameter of the pipe.

(5) Piping is to be in accordance with Ch 5.

(6) Materials are to be in accordance with Ch 3, Sec 1.

(7) Welding and non-destructive examination are to be in accordance with Ch 3, Sec 2.

(8) Suitable pipe supports in accordance with ASME B31.3.

206. Auxiliary well control system

1. Auxiliary well control equipment includes the upper and lower kelly valves, drill pipe safety valves, IBOPs, drill string float valves and kelly.

2. For drilling installation using a top drive system, an automated or manual drill pipe safety valve must be installed.

3. Materials are to be in accordance with Ch 3, Sec 1.

4. Auxiliary well control equipment is to be in compliance with API Spec 7-1, API RP 53 and Sec 5.

5. Kelly valves

(1) The drill string is to be equipped with two (2) kelly cocks, one of which is to be mounted be- low the swivel (upper kelly cock), and the other at the bottom of the power swivel or kelly (lower kelly cock).

(2) The lower kelly cock is to be sized so that it can be run through the when the blowout preventers are not installed on the seabed.

(3) Testing of kelly cocks are to be performed bi-directionally and at a with the low pressure tests first.

6. Drill pipe safety valves

(1) A full-opening manual safety valve is to be available on the rig floor drill string immediately in the event of a kick occurring during a trip.

blowout preventer stack low and high pressure,

to be installed into the

(2) The wrench to operate the valve is to be readily accessible to the crew to perform this operation.

7. Internal blowout preventer (IBOP)

(1) An internal blowout preventer or check valve that sustains a back pressure is to be provided in the drill string.

(2) IBOP is spring operated and is locked in the open position with a removable rod lock screw.

Guidance Relating to the Rules for the Classification of Mobile Offshore Drilling Units 2015 47

8. Drill string float valve

A float valve is to be installed just above the drill bit to protect the drill string from back flow or inside blowouts.

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