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TABLE OF CONTENTS
RESPONSIBILITIES ..................................................................................................................................2
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DEFINITIONS .............................................................................................................................................2
3.0
PROCEDURE...............................................................................................................................................2
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INTRODUCTION ...........................................................................................................................................2 BLOW OUT PREVENTER STACK CONFIGURATION ......................................................................................3 CHOKE AND KILL LINES .............................................................................................................................4 BURP VALVES ............................................................................................................................................5 CHOKE MANIFOLD .....................................................................................................................................5 MUD/GAS SEPARATOR ...............................................................................................................................6 DIVERTER SYSTEM .....................................................................................................................................7 BLOW OUT PREVENTER AND DIVERTER CONTROL SYSTEMS .....................................................................8 DRILL STRING SAFETY DEVICES ................................................................................................................9 STANDPIPE MANIFOLD, MUD HOSE AND SWIVEL .....................................................................................10 WELL CONTROL MONITORING SYSTEMS..................................................................................................11 DRILLING FLUID MATERIAL REQUIREMENTS ...........................................................................................11
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3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 3.12
REFERENCES ...........................................................................................................................................12
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LINKED DOCUMENTS ...........................................................................................................................12
6.0
ENCLOSURES...........................................................................................................................................12
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Prepared By: n/a
Date: n/a
Reviewed by: n/a
Date: n/a
Approved by: P Bathgate
Reason for Revision: Input into new Company Management System. See Tracking Reference ___0686__ ____
Date: 25/07/07
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Responsibilities None.
2.0
Definitions
Procedure
3.1
Introduction
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See L4-DOC-MAX-0954 – General Information.
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Subsea well control systems for deep water work are more complex than conventional systems. They are hydraulically actuated as are BOP stacks used in shallow water. The primary element of the hydraulic control system is the subsea control pod mounted on the BOP stack.
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The control pod contains hydraulic control valves which on command from the surface direct the flow of hydraulic power fluid to and from the blowout preventers, hydraulic connectors and valves etc on the BOP. In most deep water control systems, pilot command signals are transmitted electrically through a mini conductor cable, instead of through hydraulic pilot lines. This allows far quicker response times to be achieved.
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The power fluid is supplied through a rigid conduit 4 1/2" in diameter instead of down a 1" line through the pod hose. The subsea well control system must be capable of performing the following functions. The transmission of electrical signals is referred to as Multiplex, the system transmits coded command and data signals through a small multi conductor cable. Command signals are decoded, verified by reciprocal transmission to surface, and then executed in a fraction of a second. In addition to the above the multiplex control cable transmits television signals from the cameras mounted on the LMRP. • Closure around:
•
1.
All drill string components.
2.
All casing and tubing diameters.
3.
All completion equipment.
4.
All drill stem test tools.
Allow emergency disconnect from the well during DP failure.
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Allow venting of trapped gas from BOP.
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Permit stripping of drill pipe.
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Shear maximum diameter drill pipe in use on rig.
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Shear casing up to 13 3/8"
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Enable shut-in of well with no pipe in hole.
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Allow controlled release of high pressure well fluids.
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Allow pumping into the well.
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Enable the well to be shut-in if the choke line flow cuts during well kill operations.
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Permit controlled emergency move-off of rig.
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Blow Out Preventer Stack Configuration
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The blowout preventer stack on Stena Drillmax contains the following components: Two annular preventers.
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Certification Requirements - All components of well control system must meet or exceed the requirements of "Offshore Installations: Guidance on Design, Construction and Certification, Fourth Edition, Section 43: Well Control Equipment, January 1990", issued by the HSE. In addition, it must be ensured that the equipment complies with any applicable revisions to this document.
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One blind/shear ram
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One casing shear ram.
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Three pipe rams
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Two choke line outlets, each fitted with two fail-safe valves.
• •
Two kill line outlet fitted with two fail-safe valves. Choke and Kill isolation valves.
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Riser Burp valves to allow removal of trapped gas from BOP.
In addition, the following requirements must be met: •
The pipe rams, shear rams, spool pieces, gate valves, and any component attached to the BOP stack which is designed to contain well pressure, must have a working
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pressure rating that exceeds the maximum anticipated surface pressure under the worst case operating conditions. Once a ram preventer has been selected for a particular application, the pressure rating of all other pressure containing components of the well control system shall not be less than the working pressure rating of the ram preventers. The only exception will be the annular preventers. The working pressure rating for all pressure containing components of the well control system shall be applicable at the continuous service temperature rating for the particular component.
•
The continuous service temperature rating of BOP stack components must meet or exceed the maximum anticipated continuous exposure temperature during drilling operations. This includes all elastomeric and metallic components.
•
The fluid wetted elastomeric and metallic components of the BOP stack must be compatible with the anticipated well fluids. This includes H2S, CO2, formation hydrocarbons, treating chemicals, and any other foreign material that may contact the BOP under service conditions.
•
The minimum inside diameter through the BOP stack, diverter, spool pieces connectors, and any other component concentric to the wellhead, must not be less than the inside diameter of the wellhead equipment to which the system is attached.
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The side outlets on the ram type preventers and drilling spools for all service applications must be flanged, clamped, or studded.
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All elbows and bends in the BOP stack outlets are to be of sufficient wall thickness to resist erosion wear while flowing abrasive well fluids. Where possible, 90 degree elbows are to be fitted with targeted, flange type unions.
3.3
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Choke and Kill Lines The well control system is equipped with a minimum of one choke line and one kill line. In addition, the choke and kill lines must meet the following requirements. • The working pressure rating of the choke and kill lines shall meet or exceed the working pressure rating of the BOP ram type preventers. • Each choke and kill line outlet on the BOP stack is to be fitted with a minimum of two full opening gate valves oriented at 90 degrees from the through bore of the BOP stack. The valves are to be located as close as possible to the BOP stack. In addition, both valves are to be equipped with fail-safe close hydraulic operators capable of closing the valve against a wellbore pressure equivalent to the working pressure rating of the valve. The failsafe close feature must be completely functional with the lower marine riser package unlatched.
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• All unions in each choke and kill line are to be either welded flanged, studded, or clamp type connections. The only exception will be sections of the choke and kill lines which are attached to the marine drilling- riser. These unions may be an acceptable stab-in design. • The choke and kill lines are to be adequately secured to the marine drilling riser, and rig structure to prevent excessive movement during well kill and pressure testing operations. This includes flexible lines.
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• The continuous service temperature rating of the choke and kill lines must meet or exceed the maximum anticipated continuous exposure temperature during drilling or well control operations. This includes all elastomeric and metallic components.
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• All fluid wetted components of the choke and kill lines must be compatible with the anticipated well fluids. This includes H2S, CO2, formation hydrocarbons, drilling fluids and additives, completion fluids, treating chemicals, and any other foreign material that may contact the choke and kill lines under service conditions.
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Burp Valves
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• All elbows and bends in the choke and kill lines are to be of sufficient wall thickness to resist erosion wear while flowing abrasive well fluids. Where possible, 90 degree elbows are to be fitted with targeted, flange type unions.
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These valves are installed below the upper annular and lead through two hydraulically actuated valves into the choke line above the choke line isolation valve. The purpose of these valves is to allow the removal of trapped gas from the BOP. See Removal of Trapped Gas from BOP in the Rig Specific Work Methods Manual.
3.5
Choke Manifold The choke manifold is positioned on the rig floor and firmly secured. The unit is designed to accept high pressure fluids from the well and enable de-pressurizing to atmospheric conditions. In addition, the choke manifold has the facility to accept high pressure fluids from the cementing unit or mud pumps, and appropriate valves to permit pumping into the choke and kill lines individually or simultaneously. Furthermore, the following features are incorporated: • The choke manifold has a minimum working pressure rating equivalent to the working pressure rating of the BOP ram preventers. • The manifold has a continuous service temperature rating that meets or exceeds the maximum anticipated exposure temperature at the unit.
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• The choke manifold is fitted with four drilling chokes. Two of the chokes are remotely power operated. The remote choke control panel is located in the drilling control room. The valve configuration of the manifold allows for the facility to alternate between chokes, as required, without interrupting flow from the well. • The manifold contains only flanged, studded, and clamp type unions between all integral components.
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• The manifold allows the discharge of depressurized well fluids to the mud/gas separator, mud return flowline, and in an emergency to the direct overboard vent lines.
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• The choke manifold is equipped with the facility to by-pass the drilling choke and divert the flow of well fluids to port and starboard emergency vent lines. The vent lines are as straight as possible, bends and elbows are of sufficient wall thickness to resist erosion wear if flowing abrasive well fluids. The purpose of this emergency vent line is to permit venting of well fluids to a safe, downwind location in the event the mud/gas separator becomes overloaded and the well cannot be adequately controlled or shut-in with sufficient speed to alleviate the condition.
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• Valves integral to the choke manifold are of the full opening type and have a working pressure rating not less than the working pressure rating of the BOP ram preventers.
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• The valve configuration allows for isolation of flow paths through the choke manifold to permit replacement of faulty components.
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• All fluid wetted components of the choke manifold are compatible with the anticipated well fluids. This includes H2S, CO2, formation hydrocarbons, drilling fluids and additives, completion fluids, treating chemicals, and any other foreign material that may contact the BOP under service conditions. • All elbows and bends in the choke manifold are of sufficient wall thickness to resist erosion wear while flowing abrasive well fluids.
3.6
Mud/Gas Separator The mud/gas separator is capable of accepting the flow of depressurised well fluids through an inlet from the choke manifold through a baffle, discharging whole mud to the active mud system, while venting gas to a flare line. The working pressure is in the range 0 - 6 psi and max pressure of 150psi. The layout of the separator is shown below in figure 1. The system must also meet the following requirements:
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• The inlet line to the mud/gas separator from the choke manifold is a high pressure line with a working pressure rating equivalent to the rating of the choke manifold buffer chamber to which it is connected. This is to ensure the mechanical integrity of the line while flowing abrasive fluids for extended periods. • The gas flare line exiting the top of the separator has a diameter of 10". The flare line open ended with no valves. • The mud discharge line has a diameter sufficient to allow drainage of mud without gas entrainment at a minimum of 6 bbl/ min.
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• The separator incorporates a baffle chamber to deflect inlet fluids away from the outer wall of the vessel.
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• Under normal operating conditions the separator maintains a minimum seal height equivalent to the maximum permissible backpressure in the vent line. (3 meter seal height).
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• The separator must be designed as a pressure vessel according to the guidelines established by the ASME Boiler and Pressure Vessel Code, Section VIII.
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• The separator has two sea water flush lines and an inspection hatch to allow for cleaning and periodic inspections.
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• The facility exists for by-passing the mud/gas separator in the event of system overload or malfunction. Well fluids may be directed overboard through the emergency vent lines.
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Figure 1 Mud/Gas Separator - Subsea Well Control Systems (30/03/07 Drawing not available. To be inserted when drawing is available.)
3.7
Diverter System The diverter system is capable of rapidly diverting the flow of well fluids away from the rig through low pressure vent lines. The system meets the following requirements. • The diverter system has a maximum working pressure rating of 500 psi. • The two overboard vent lines have a nominal diameter of 13 5/8. Valves positioned in the lines are full opening. • The diverter is capable of closure on all diameters of tubulars and drilling tools that will be run through the system. • When the diverter system is functioned the. The master overboard line opens, (Port and Stbd Overboards are normally open). The hole fill line closes, The trip
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tank valve closes, The shaker valve closes, and the Complete shut off diverter element closes. • The diverter housing and vent lines are adequately secured to prevent excessive movement while flowing well fluids overboard. • All elbows and bends on the diverter lines are of sufficient wall thickness to resist erosion wear while flowing abrasive well fluids.
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Blow Out Preventer and Diverter Control Systems
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Operating control systems for subsea well control equipment are significantly more complex than for surface BOP stack. In addition to controls for basic BOP functions, a whole range of features must be incorporated to facilitate attachment to the wellhead emergency release, redundancy of control lines, compensation for water depth, etc. Add to this the requirements of the diverter system, and the need for thorough design planning cannot be overstated.
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Acceptable control systems must meet or exceed the following requirements:
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• Three remote control panels for the BOP and diverter functions are provided. One panel is positioned on the drill floor as close as practicable to the Driller’s station and remote choke control panel. The second panel is located in the Toolpushers office away from the rig floor to allow operation of the well control system in the event the drill floor must be evacuated. The third control panel is to be located at the BOP control room. These remote control panels allow for operation of each hydraulically operated BOP function.
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• All hoses on the inside (wellbore) of the diverter system should be constructed of flame proof material.
• The closing unit must be capable of supplying sufficient usable fluid volume from the accumulators to close and open all ram preventers and one annular preventer while maintaining a 50% reserve. Following completion of this operation, the accumulator pressure is not to be less than 200 psi above the precharge pressure. This must be performed with the accumulator charge pumps turned off. • The closing system is capable of closing each ram preventer in 12 - 18 secs. • The control system allows regulation of the closing pressure on the ram preventers and annular prevents to enable stripping operations. • The pressure rating of the charge pumps is to be equivalent to the working pressure rating of the closing unit. Operating power and hydraulic communication to the accumulator system must be available to the charge pumps at all times such that the pumps will begin pumping when the closing unit manifold pressure decreases to 90% of the accumulator operating pressure.
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• The closing unit is capable of operation using a minimum of three independent power sources. Air operated pumps are in the system along with electrically powered triplex pumps. All power sourced must be capable of simultaneously furnishing sufficient power to charge the entire accumulator system from the precharge pressure to the maximum rated charge pressure in 15 minutes or less. • All valves, fittings, lines, and manifolds between the closing unit and the conduit are to be of steel construction with a fire resistant hose with a working pressure rating not less than the working pressure rating of the closing unit manifold.
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• The closing unit should be fitted with sufficient valves to permit isolation of the charge pumps and accumulators from the closing unit manifold.
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• Pressure sensors are fitted both upstream and downstream of the annular preventer regulators to permit monitoring of the regulated annular preventer operating pressure.
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• The closing unit is equipped with a fluid reservoir of a capacity not less than twice the usable fluid capacity of the accumulator system. The fluid reservoir should be capable of being circulated. An additional slug tank for concentrated mixtures; and a bulk storage tank for either glycol or neat concentrate.
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• Control of subsea stack functions is provided by two completely redundant MUX hoses running from the surface to subsea control pods. The control pods are not retrievable due to the guideline-less system.
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• Operation of all stack functions is possible using either of the two control pods.
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• The closing unit must be sized to take account of the maximum water depth in which the BOP stack will be operated. The system operates at 500psi to increase the useable fluid capacity at depth. The bottles are pre-charged with Helium instead of Nitrogen which becomes sluggish under these conditions of pressure and temperature.
3.9
Drill String Safety Devices Drill string safety devices refer to those elements of the drill string that are used to close in or contain well pressure. The requirements for this equipment are detailed below.
3.9.1
Top Drive - IBOP (Inside Blow Out Preventer) Two BOP's are installed between the drill string and the Top drive. One is remotely controlled from the drillers console, the other is a manual valve. The valves are selected to be compatible with the intended service environment taking account of temperature, pressure, and well fluid exposure. The valves have a minimum
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working pressure equivalent to the working pressure rating of the ram preventers. The valve is of the full opening type to the inside diameter of the Topdrive stem. 3.9.2
Drill Pipe Safety Valve
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If a drilling assembly is being used, A drill pipe safety valve must be installed near the bottom of this assembly at all times. The valve must be compatible with the intended service environment taking account of temperature, pressure, and well fluid exposure. The valve must have a working pressure rating equivalent to the working pressure rating of the ram preventers. The valve must be full opening to the inside diameter of the drill pipe.
Inside Blow Out Preventer
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A spare drill pipe safety valve must be on the rig floor at all times to accommodate each size of drill pipe in use. The valve should be a full opening ball type valve with a minimum inside diameter not less than the minimum inside diameter of the drill pipe in use. The valve must be selected to be compatible with the intended service environment taking account of temperature, pressure, and well fluid exposure. The valve must have a working pressure rating not less than the working pressure rating of the ram preventers.
Float Valve
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3.9.4
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An inside blowout preventer must be available on the drill floor at all times. This device may be installed in the drill string to permit stripping operations. The valve must be selected to be compatible with the intended service environment taking account of temperature, pressure, and well fluid exposure. The valve must have a working pressure rating not less than the working pressure rating of the ram preventers.
The drill string should be dressed with a float valve (normally placed directly above the bit) to prevent backflow or entry of kick fluids into the drill string. This should be non-ported for riserless drilling and ported at other times. 3.9.5
Drop In Back Pressure Valve ( DIBPV) A DIBPV sub should be run in the drillstring, near the base of the hevi-wate drillpipe. It should be selected with regard to drillstring dimensions, pressures and types of fluid it may come in contact with. It must have a working pressure not less than the rating of the ram preventers. The proper dart for the sub (i.e. suitable outside diameter that will pass through the drillstring) must be ready for use and stored on the drill floor.
3.10
Standpipe Manifold, Mud Hose and Swivel The pressure rating of the standpipe manifold, mud hose and swivel is rated to 7500psi working pressure:
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The installation is equipped with a high pressure cement pump and a Cement / Testing standpipe on the drillfloor with a working pressure rating equivalent to the working pressure rating of the BOP pipe rams. It is coupled to a suitable length of high pressure flexible hose to allow for attachment to the drill string above the manual safety valve during well control operations.
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In cases where the maximum anticipated surface pressure during well control operations could result in pressures greater than 5,000 psi, the following equipment requirements are to be adopted once the well is approx 1000' above the top of any high pressure zone.
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A manually operated ball type kelly valve is to be installed on the bottom of a "working single" of drill pipe.
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The Kelly valve is to have a working pressure rating not less than the working pressure rating of the BOP pipe rams. The minimum I.D. through the valve shall not be less than the minimum I.D. through the drill pipe tool joints.
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The Kelly valve is not to be used as a mud saver valve. If conditions dictate that a mud saver valve is required then a dedicated mud saver valve should be installed in the working stand. In all cases the mud saver valve must be positioned above the Kelly valve.
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Well Control Monitoring Systems
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Well control monitoring systems refers to equipment employed for the monitoring and recording of drilling data, pit levels, gas levels, etc. The following equipment is required as a minimum: • Pit level monitors for all active and passive pits, and a flow sensing device in the mud return flowline. Level indicators and alarms are located in the drilling control room and accessed through the SDI package in the Cyber Base Unit. The mud logging unit also monitors the above parameters. • Total mud gas. To be monitored in the drilling control room and accessed through the SDI package in the Cyber Base Unit and in the mud logging unit. • Trip tank fluid level. To be monitored in the drilling control room and accessed through the SDI package in the Cyber Base Unit and in the mud logging unit. • H2S sensors. To be positioned and monitored according to the H2S contingency plan. (These may not be permanently fitted).
3.12
Drilling Fluid Material Requirements Sufficient drilling fluid materials are to be maintained on the installation to effect well control operations. The quantity of material required at any time will be dictated by the hole section being drilled and any well specific contingency plans. In
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general, the following minimum stock levels are to be maintained on the installation at all times. • Surface Hole - Returns to Seabed - No specific material requirements unless dictated by well specific drilling programme. If a well flow is experienced in this hole section, pump sea water down drill string at highest possible rate. • All Other Hole Sections - Exploration and Development Wells - The following criteria may be used to determine necessary drilling fluid supplies: Type of mud system to be used.
2.
Estimated time on well.
3.
Volume requirements (eg. hole size and surface system).
4.
Contingency requirements in case of drive off an emergency disconnect.
5.
Anticipated problems (eg. overpressure, lost circulation, shale instability, contamination, make-up water).
6.
Logistics of location (eg. location size and configuration, distance to nearest warehouse).
7.
Previous experience in the area.
8.
Weather conditions (ie. delivery time, material damage possibilities etc.).
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9. Weight material stocks on board should not be allowed to fall below a minimum sufficient to weigh up the mud system by 1 ppg.
References Well Control equipment manuals.
5.0
Linked Documents Not applicable.
6.0
Enclosures Not applicable.