1. Well Control Equipment
2. Extracts from API
3. Well Control Principles & Procedures
4. Spare
5. Spare
6. Various
WELL CONTROL MANUAL
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WELL CONTROL MANUAL
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Table of content:
Chapter 1 Well Control Equipment... Page 15
Chapter 2 Extract from API...Page 83
Chapter 3 Well Control Principles & Procedures... Page 113
Chapter 4 Spare... Page 249
Chapter 5 Spare... Page 251
Chapter 6 Various... Page 253
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WELL CONTROL MANUAL
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Manual standard clause
This manual is the property of Maersk Training Centre A/S (hereinafter “MTC A/S) and is only for the use of Course participants conducting courses at MTC A/S.
This manual shall not affect the legal relationship or liability of MTC A/S with or to any third party and neither shall such third party be entitled to reply upon it.
MTC A/S shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use.
No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of MTC A/S.
Copyright MTC 2004-02-04 Prepared by: JOA & NLN Modified & printed: 01/01/2004 Modified by: Maersk Training Centre
Internal reference: M:\DRILLING IWCF Surface\Course material\Manual OPS\Class room Manual\040101_Update Project\040101_Updated Manual01.doc
Contact MTC
Maersk Training Centre A/S Dyrekredsen 4 Rantzausminde 5700 Svendborg Denmark Phone: +45 63 21 99 99 Telefax: +45 63 21 99 49 Telex: SVBMTC E-mail: [email protected] Homepage: http://www.maersktrainingcentre.com Managing Director: Claus Bihl
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WELL CONTROL MANUAL
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Index
&
Abbreviations:
Page 07Chapter 1:
Well Control Equipment
Page 15Section 01 Well control barrier Page 17
01.01 Primary well control barrier 02.01 Secondary well control barrier
Section 02 BOP configuration Page 18
01.02 Bop stack arrangements 02.02 Stack components codes 03.02 Drilling spool
Section 03 Diverter systems Page 21
01.03 Purpose of diverter system 02.03 Diverter equipment
03.03 Guidelines for diverting with string on bottom 04.03 Guidelines for diverting with string off bottom
05.03 Rotating head
06.03 Diverter control system
Section 04 Annular preventer Page 27
01.04 General
02.04 Testing
03.04 Pressure test frequency
04.04 Response time
05.04 Hydril annular preventers 06.04 Shaffer annular preventers 07.04 Cameron annular preventers
08.04 Packing unit
Section 05 Cameron ram preventers Page 37
01.05 General
02.05 Testing
03.05 Pressure test frequency
04.05 Response time
05.05 Cameron ram preventer 06.05 Cameron ram assembly 07.05 Operating ratio
08.05 BOP and side outlet connections 09.05 API type flanges
10.05 Ring joint gaskets and grooves
Section 06 Choke manifolds Page 55
01.06 General
02.06 Choke Manifold - Installation 03.06 Choke Lines - Installation 04.06 Kill Lines - Installation 05.06 BOP side outlet valves
06.06 Chokes
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08.06 Mud/gas separator
09.06 Vacuum degasser
Section 07 Control System Page 63
01.07 General
02.07 Response time
03.07 Storage equipment
04.07 Pump requirements
05.07 Accumulator cylinders and manifolds 06.07 Hydraulic control manifold
07.07 Schematic of BOP control system 08.07 Fluid flow diagramme 09.07 Remote control panel
10.07 Accumulator volumetric requirements 11.07 Accumulator volumetric capacity
Section 08 Auxiliary equipment Page 78
01.08 Kelly valves
02.08 Top drive valves 03.08 Drillpipe safety valve 04.08 Inside blowout preventer 05.08 Drillstring float valve 06.08 Hanger type test plug 07.08 Cup type test plug
08.08 Trip tank
09.08 Pit volume measuring devices 10.08 Flow rate sensor
Chapter
2:
Extracts
from
API
Page 83
Section 01 Diverter systems - purpose Page 85
Installation and equipment requirements Air, aerated fluid or gas drilling operations
Section 02 Blowout preventer equipment selection Page 86
Section 03 Classification of blowout preventers Page 87
Stack component codes Drilling spools
Section 04 BOP operational characteristics tests Page 88
General
Ram-type BOP
Applicable operating characteristics test Sealing characteristics test
Fatigue test
Stripping life test
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Ram access test
Annular-type BOP
Sealing characteristics test A. Constant wellbore pressure test B. Constant closing pressure test C. Full closure pressure test
Fatigue test
Packer access test
Stripping life test
Operating manual requirements Hydrostatic proof testing Procedure
Test pressures
Acceptance
Section 05 BOP closing ratio (ram BOP) Page 94
BOP opening ratio (ram BOP)
Ram locks
Section 06 Periodic field testing Page 94
Blowout preventer operating test Blowout preventer hydraulic tests
Auxiliary equipment testing Recommended pressure test practices
Section 07 Choke manifolds – purpose Page 100
Design considerations
Installation guidelines Choke control station
Maintenance
Section 08 Kill lines Page 103
Installation guidelines
Section 09 Control systems for surface mounted BOP stacks Page 104
General
Response time
Hydraulic fluid and storage equipment Pump requirements
Accumulator bottles and manifolds
Accumulator types and interconnection of accumulator banks
Precharging accumulators
Accumulator volumetric requirements Volumetric capacity calculations Hydraulic control manifold
Hydraulic control manifold annular BOP circuit
Hydraulic manifold circuit for common pressure functions
Hydraulic control manifold valves
Section 10 Remote control panels Page 109
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Electro-pneumatic remote control
Requirements for BOP control system valves, Fittings, lines and manifold
Conformity of piping systems
Electrical power supplies
Section 11 Closing-in kicks Page 111
Soft close-in procedure Hard close-in procedure
Chapter 3:
Well Control Training Manual
Page 113Section 01 Pressure in the earth crust Page 115
01.01 Sedimentation 02.01 Compression 03.01 Pressure 04.01 Pressure in fluids 05.01 Pressure gradient 06.01 Abnormal/subnormal pressure
Section 02 Pressure balance in the well bore Page 127
01.02 Pressure balance
02.02 Overbalance and underbalance 03.02 Lost circulation
04.02 Rate of penetration versus overbalance 05.02 Drilling break
06.02 Necessary overbalance 07.02 Trip margin
08.02 Riser margin 09.02 Relationship
10.02 Equivalent drilling fluid density
Section 03 Dynamic pressure regime when circulating Page 135
01.03 Circulation of drilling fluid
02.03 Dynamic pressure in the well bore
Section 04 Consideration with a closed in well Page 140
01.04 Closed in well 02.04 U-tube
Section 05 Properties of gasses and gas laws Page 143
01.05 Drilling with underbalance 02.05 Properties of gas and gas laws 03.05 Expansion of gas 04.05 Formation strength 05.05 Leak-off test
06.05 Maximum allowable annular surface pressure
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02.06 Drilling fluid volume and capacities from tables 03.06 Surface to bit strokes & bit to surface strokes 04.06 Use of barite to increase drilling fluid volume 05.06 Volume increase due to barite addition
Section 07 Wellbore kicks Page 158
01.07 Kick occurrences 02.07 Warning signals 03.07 Warning signals while drilling
04.07 Warning signals while tripping or making connection 05.07 Procedure for shutting in the well
06.07 Pressure after shut in
Section 08 Circulating a kick out of the well bore Page 174
01.08 General points
02.08 Circulating out an influx using driller’s method 03.08 Wait and weight method or engineer’s method 04.08 The concurrent method
05.08 Advantages and disadvantages of the three methods 06.08 Pressure control schemes
Section 09 Calculations of density and pressure gradient of an influx Page 199
01.09 General points 02.09 Example
Section 10 Lost circulation Page 202
01.10 General
02.10 Causes of lost circulation 03.10 Well control with partly lost circulation 04.10 Well control with total lost circulation
Section 11 Volumetric well control and other Page 207
01.11 General
02.11 Volumetric method – specification required 03.11 Volumetric method – handling
04.11 Lubrication technique
05.11 Volumetric method – example 06.11 Low choke method – dynamic Kill
07.11 Bullheading
Section 12 Kick with bit off bottom Page 218
01.12 Introduction
02.12 Stripping
03.12 Closing procedures
04.12 Rig layout for combined stripping and volumetric method
05.12 Procedure
06.12 Snubbing
Section 13 Gas cut drilling fluid Page 224
01.13 General
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03.13 Gas kicks in oil based mud
04.13 Influx volume
Section 14 Deviated and Horizontal well control Page 230
01.14 Introduction
02.14 Complications
03.14 Horizontal well control example 04.14 Wait and weight method
05.14 Driller’s Method
06.14 Horizontal well kill method
Section 15 Pulling Pipe Page 242
01.15 Introduction
02.15 Pumping slug
03.15 Inadequate hole filling
04.15 Hole not taking correct amount of fluid 05.15 Hole not giving correct amount of fluid
Chapter
4:
Spare
Page 249Chapter
5:
Spare
Page 251WELL CONTROL MANUAL
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Abbreviations:
A Annular preventer A Area
API American Petroleum Institute
Atm Atmosphere
BHA Bottom hole assembly
BHP Bottom hole pressure
BOP Blow out preventer
C Hydraulic connector
Cap Capacity
CSO Complete shut off
DC Drill collar
DP Drill pipe
DPSV Drill pipe safety valve
EDC Equivalent circulating density
EFD Equivalent formation density
EOB End of build
ºF Fahrenheit
FCP Final circulating pressure
Ft Feet
G Pressure gradient psi/ft
Gal Gallons
GMD Gas migration distance
GMR Gas migration rate
GPM Gallons per minute
K Kilo=1000 units
HCR High closing ratio
HPHT High pressure/high temperature
H2S Hydrogen sulfide Gas
IBOP Inside blow-out preventer
ICP Initial circulating pressure
ID Internal diameter
KMW Kill mud weight
KOP Kick off point
lb Pound
lb/ft Pounds per feet
LOT Leak off test
FIT Formation integrity test
MAASP Maximum allowable annular surface pressure
MD Measured depth
MGS Mud/Gas Separator
MTC Maersk Training Centre
MW Mud weight
MWF Final mud weight
NDE Non destructive examination
NDT Non destructive testing
OBM Oil base mud
OD Outside diameter
OH Open hole
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P Pressure
PA Pressure annulus
Pc Pressure circulating (dynamic)
PDP Pressure drill pipe
Pf Pressure formation (pore pressure)
Ph Pressure hydrostatic
PL Pressure loss
PL Reduced rate circulating pressure Loss (SCR, RRCP)
PPG Pound per gallon
PSI Pound per inch square
PPM Part per million
PWD Pressure while drilling
R Ram preventer (single)
Rd Ram preventer (double)
ROP Rate of penetration
RPM Rotation per minute
Rt Ram preventer (tripple)
RP Recommended practice
S Drilling spool
SF Safety factor
SICP Shut in casing pressure
SIDPP Shut in drill pipe pressure
SPM Strokes per minute
SX Sacks
SCF Standard cubic feet
T Temperature
TVD True vertical depth
V Volume
WBM Water base mud
WELL CONTROL MANUAL
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Maersk Training Centre
Drilling Section
Chapter 1 Well Control Equipment
Copyright © Maersk Training Centre a/s.
All rights reserved. No part of this publication may be reproduced, stored in or introduced into a retrieval system, or transmitted, in any form, or by any means (electronic, mechanical, photocopying, recording or otherwise) without the prior written permission of Maersk Training Centre a/s.
The basic of this well control manual is found according to recommendation in API 16E and API²RP 53. Well control equipment and control system according to API³RP 53 and API (spec) 16a.
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Section 01
Well control barriers.
01.01 Primary well control barrier.
During normal drilling operation it will always be the hydrostatic pressure of the drilling fluid that creates the primary barrier to avoid any flow of formation fluid into the well bore. If for any reason the primary barrier is lost the well control equipment together with the drilling fluid in the well bore will be the secondary barrier. This will allow us to re-establish the primary barrier on a safe and efficient way.
01.02 Secondary well control barrier.
The well control equipment must be able to close and secure the well under all circumstances. Further to that circulation of heavy drilling fluid into the well bore and formation fluid out of the well bore under controlled manner must be possible.
The well control equipment should be able to close on open hole(without tubular), around BHA and other tubular used in the drilling operation. It should also be able to cut the drill string or lighter tubular and seal the well bore and allow the drill string to be hanged off on the pipe rams or stripped into the well bore.
To avoid single components to create total failure of the system a contingency (back up) function should be build into the system.
All well control equipment must be maintained, function- and pressure tested according to company policy and procedures to assured correct function and integrity when required. With the well closed in and the drill string in the well bore, formation pressure can be obtained through the drill string by adding SIDPP with pressure hydrostatic.
To secure the drill string and obtain integrity following barriers can be used: DPSV (drill pipe safety valve)
DIBPV (drop In back pressure valve (dart, landing sub and retrieving tool) IBOP (inside blow-out preventer)
Fast shut off coupling with DPSV Check valves (Drill pipe floats)
To secure the annulus and obtain integrity following barriers can be used: Annular Preventer
Ram Preventer Shear/Blind Ram
During normal drilling operation two barriers must always be in place where the hydrostatic head of the drilling fluid is one and the BOP stack the other.
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Section 02
BOP configuration
02.01 Bop stack arrangements
Example arrangements for BOP equipment are based on rated working pressures. Example stack arrangements shown in Figures 1 and 2 should prove adequate in normal environments, for rated working pressures of 2K, 3K, 5K,IOK, 15K, and 20K. Arrangements other than those illustrated may be equally adequate in meeting well requirements and promoting safety and efficiency.
Rated working pressure
2K 2000 psi (13.8 MPa) 3K 3000 psi (20.7 MPa) 5K 5000 psi (34.5 MPa) 10K 10000 psi (69.0 MPa) 15K 15000 psi (103.5 MPa) 20K 20000 psi (138.0 MPa) Fig 01 Fig 02
02.02 Stack component codes
Every installed ram BOP should have, as a minimum, a working pressure equal to the maximum anticipated surface pressure to be encountered. The recommended component codes for designation of BOP stack arrangement are as follows:
G = Rotating head. A = Annular type BOP.
R = Single ram type BOP with one set of rams, either blank or for pipe, as operator prefers.
RD = Double ram type BOP with two sets of rams, positioned in accordance with
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RT = Triple ram type BOP with three sets of rams, positioned in accordance with
operator's choice.
S = Drilling spool with side outlet connection for choke and kill lines.
C = Hydraulic well head connector with a minimum rated working pressure equal to the BOP stack rated working pressure.
K = 1000 psi rated working pressure.
BOP components are typically described upward from the uppermost piece of permanent wellhead equipment, or from the bottom of the BOP stack. A BOP stack may be fully iden-tified by a very simple designation, such as:
15K - 13 5/8 – RSRRAG
This BOP stack would be rated 15.000 psi (103,5 MPa) working pressure, with throughbore of 13-5/8 inch (34,61 cm) and would be arranged as in Figure 02B.
Annular BOPs may have a lower rated working pressure than the ram BOPs. 02.03 Drilling spools
Choke and kill lines may be connected either to side outlets of the BOPs, or to a drilling spool installed below at least one BOP capable of closing on pipe. Utilization of the BOP side outlets reduces the number of stack connections and overall BOP stack height. However, a drilling spool is used to provide stack outlets (to localize possible erosion in the less expensive spool) and to allow additional space between preventers to facilitate stripping, hang off, and/or shear operations. See Fig 03
Fig 03
Drilling spools for BOP stacks should meet the following minimum specifications: a. 3K and 5K arrangements should have two side outlets no smaller than a 2-inch
(5.08 cm) nominal diameter and be flanged, studded, or hubbed. IOK, 15K, and 20K arrangements should have two side outlets, one 3-inch (7.62 cm) and one
2-inch (5.08 cm) nominal diameter as a minimum, and be flanged, studded, or hubbed.
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b. Have a vertical bore diameter the same internal diameter as the mating BOPs and at least equal to the maximum bore of the uppermost casing/tubing head.
c. Have a rated working pressure equal to the rated working pressure of the installed ram BOP.
Note: For drilling operations, wellhead outlets should not be employed for choke- or kill lines.
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Section 03
Diverter systems
Fig 04
03.01 Purpose of diverter system (API RP 53 4.1)
A diverter system is often used during top-hole drilling. A diverter is not designed to shut in or halt flow, but rather permits routing of the flow away from the rig. The diverter is used to protect the personnel and equipment by re-routing the flow of shallow gas and wellbore fluids emanating from the well to a remote vent line (see Fig 04). The system deals with the potentially hazardous flows that can be experienced prior to setting the casing string on which the BOP stack and choke manifold will be installed. The system is designed to pack-off around the Kelly, drill string, or casing to divert flow in a safe direction. Diverters having annular packing units can also close on wire line and open hole. Valves in the system direct the well flow when the diverter is actuated. The function of the valves may be integral to the diverter unit.
03.02 Diverter equipment (API RP 53 4.2.2)
The diverter system consists of a low pressure diverter or an annular preventer of sufficient internal bore to pass the bit required for subsequent drilling. Vent line(s) of adequate size [6 inches (15.24 cm) or larger] are attached to outlets below the diverter and extended to a location(s) sufficiently distant from the well to permit safe venting.
Conventional annular BOPs (see Fig 05), insert-type diverters (see Fig 06), or rotating heads (see Fig 10) can be used as diverters. The rated working pressure of the diverter and vent line(s) are designed and sized to permit diverting of well bore fluids while minimizing wellbore back pressure. Vent lines are typically 10 inches (25.4 cm) or larger ID for offshore and 6 inches (15.24 cm) or larger ID for onshore operations.
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Fig 06
Fig 05
If the diverter system incorporates a valve(s) on the vent line(s), (refer to API Recommended practice 64), this valve(s) should be full opening and full bore (have at least the same opening as the line in which they are installed). The system should be hydraulically controlled such that at least one vent line valve is in the open position before the diverter packer closes.
Diverter testing (API RP 53 4.2.5)
The diverter and all valves should be function tested when installed and at appropriate times during operations to determine that the system will function properly.
(See also API RP 53 17.4)
CAUTION: Fluid should be pumped through the diverter and each diverter vent line at
appropriate times during operations to ascertain the line(s) is not plugged. Inspection and clean-out ports should be provided at all low points in the system. Drains and/or heat tracings may he required in colder climates.
The hydraulic supply pressure to the diverter control panel is routed directly from the hydraulic control unit with 3.000 psi.
Older types of diverter systems have separate operating handles for each components as seen in Fig 07, but most have now been changed so the valves is integral to the diverter unit.
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Fig 07
To operate the system in Fig 07 the following sequence must be used to avoid shutting in or halt the flow from the well bore:
a. Open B or C depending on wind direction
b. Close E
c. Close A
In the Hydril model FS21-500 the diverter is integral to an annular preventer and is only equipped with one diverter line witch is diverted into two lines by a DS12-500 Flow Selector valve that makes it possible to divert fluid and gas to either side of the rig depending of wind direction or to both side at the same time. See Fig 08 and 08a.
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03.03 Guidelines for diverting with string on bottom
1. Route returns to downwind vent line and close diverter
2. Pump at maximum rate and switch to kill fluid without stopping the pumps. If no kill fluid available, use sea water. (Do not stop the pumps)
3. If the diverter system fails before control of the well is regained or broaching to surface occurs, evacuate all personnel and leave the mud pumps running on sea water at maximum pump rate.
03.04 Guidelines for diverting with string off bottom
If it becomes necessary to divert gas, water and/or sand debris, route returns to downwind vent line and close diverter.
1. Do not stop pumping and if mud reserves run out, keep pumping seawater at maximum rate. Do not stop the pumps.
2. Arrange emergency evacuation of all non-essential personnel and prepare evacuation of remaining personnel.
3. If the diverter system fails before control of the well is regained, or broaching to surface occurs, evacuate all personnel and leave the mud pumps running on seawater at maximum pump rate.
03.05 Rotating head
API RP 64 section 3- 3.1.2.3
A rotating head can be used as a diverter to complement a blowout preventer system. The stripper rubber is energized by the wellbore pressure to seal against the drill pipe, kelly, or other pipe to facilitate diverting returned well fluids and can be used to permit pipe movement (reciprocating and or rotation).
The original equipment was designed for air drilling and later used for mud, gas and geothermal applications. Later generation equipment was applied by industry for the flow drilling applications that causes high pressures at the wellhead. The original design and engineering principles for its use still applies today. Within the BOP system the API recognizes the rotating head as a diverter. See Fig 09.
The rotating BOP is used on top of a regular BOP stack consisting of ram and annular BOPs.
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The rotating head seals off any shape of kelly and will also seal on any type of drill pipe whether flush joint, upset or coupled. No special operations are required for handling the pipe.
As the various elements of the drill string are raised or lowered, the “stripper rubber” changes shape to conform to the OD of these elements. In this way the hole is closed at all times. A flanged outlet below the stripper rubber allows flow under pressure to be directed out through the flow line.
Fig 09 The rotating blow-out preventer is ideal for use when:
• Drilling in H2S areas. • Circulating with air or gas. • Drilling under balanced. (UBD) • Drilling with reverse circulation.
• Drilling in areas susceptible to blow-outs. • Drilling geothermal wells.
The rotating blow-out preventer consists of three major assemblies. See Fig 10.
• The rotating assembly Fig 10
• The body • Kelly drive unit
The body is flanged to the top of the blow-out preventer and the rotating assembly is locked in with a quick release mechanism. The kelly drive unit is installed on the kelly and turns the rotating sleeve that has the stripper rubber attached to the lower end. The stripper rubber seals off the well pressure between the annulus of the hole and the outside of the drill pipe. The rotating sleeve packing effectively seals between the outside of the rotating sleeve and rotating assembly housing.
The stripper rubber is constructed in such manner that as the well pressure increase, the stripper forms a tighter seal.
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Underbalanced drilling is now being more widely reborn in the oil and gas industry. The major advances of underbalanced drilling is to lower costs, reduce drilling days, reduce differential sticking problems and hole drag caused by mud cake.
Because underbalanced drilling creates the condition for fluid to flow from the formation into the well bore, successful underbalanced drilling must include the selection of proper control equipment to handle the drilling fluid and formation fluids at surface. The rotating control head is one of the major elements of the system.
03.06 Diverter control system
The diverter control system should be designed to preclude closing-in the well with the diverter. This requires opening one or more vent lines prior to closing the diverter as well as closing normally open mud system valves.
A diverter control system should be capable of operating the vent line and flow line valves (if any) and closing the annular packing element on pipe or open hole within thirty seconds of actuation if the packing element has a nominal bore of twenty inches or less. For elements of more than twenty inches nominal bore, the diverter control system should be capable of operating the vent line and flow line valves (if any) and closing on pipe in use within forty-five seconds.
The diverter control system may be supplied with hydraulic control pressure from the BOP control system. In this case there is usually more accumulator capacity, pump capacity and reservoir capacity than is required for the diverter system. These should, however, comply with the recommendations which follow for a self-contained diverter control system. An isolation valve should be installed in the line from the main hydraulic supply to shut off the supply to the diverter control system when it is not in use. The function of this valve should be clearly labeled and its position status should be clearly visible.
All of the diverter control functions should be operable from the rig floor. A second control panel should be provided in an area remote from the rig floor. The remote area panel should be capable of operating all diverter system functions including any necessary sequencing and control of the direction of the diverted flow.
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Section 04
Annular preventers
04.00 Definition (API RP 53 3.1.2):
An Annular Preventer is a device that can seal around any object in the wellbore or upon itself. Compression of reinforced elastomer packing element by hydraulic pressure effects the seal.
Note: This definition statement is wrong and will be adjusted in the future by API.
Annular preventers will not seal around blades of very large stabilizers, bit cones and rollers on roller reamers.
04.01 General
In this manual we are going to look at of some commonly used types of annular preventers in the industry. These preventers are used for subsea and/or surface applications and they are fabricated by three different manufactures:
Cameron Cooper: Type “D”
Type “DL”
Hydril: Model “GK”
Model “GL”
Model “GX”
Model “MSP
Shaffer: Shaffer Spherical.
04.02 Testing – Surface BOP stacks API RP 53
Visual Inspection of annular preventers:
1. Packer
Visually inspect condition of packer. Check for gouges in seal area. Verify and record age of packer. Ensure within shelf life of manufacturer. Record drilling fluid and inquire about compatible.
2. Throughbore
Ensure no key seat damage in annular cap wear band. Record if any. 3. Drift
Ensure that the packer is fully open and not protruding into the wellbore. 4. Surge Bottle
Check for proper nitrogen pre-charge in accumulator bottle. Consider water depth for sub-sea application.
5. Milling
Check for metal shavings if milling operations have been performed. 6. Operating Pressures
Ensure that a operating range pressure chart in relation to pipe size and wellbore pressure is posted.
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7. Drift test
Drift test the annular preventer to ensure that it returns to full open bore within 30 min.
Function test: API RP53 17.3.1
All operational components of the BOP equipment systems should be functioned at least once a week to verify the component's intended operations. Function tests may or may not include pressure tests.
• Function tests should be alternated from the driller's panel and from mini-remote panels, if on location.
• Actuation times should be recorded as a data base for evaluating trends.
Pressure tests: API 17.3.2.1
All blowout prevention components that may be exposed to well pressure should be tested first to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to a high pressure.
• When performing the low pressure test, do not apply a higher pressure and bleed down to the low test pressure. The higher pressure could initiate a seal that may continue to seal after the pressure is lowered and therefore misrepresenting a low pressure condition.
• A stable low test pressure should be maintained for at least 5 minutes.
The initial high pressure test: Annular BOPs, with a joint of drill pipe installed, may be
tested to the test pressure applied to the ram BOP’s or to a minimum of 70 percent of the annular preventer working pressure, whichever is the lesser.
Initial pressure tests are defined as those tests that should be performed on location before the well is spudded or before the equipment is put into operational service.
Subsequent high pressure tests: Annular BOP’s, with a joint of drill pipe installed,
should be tested to a minimum of 70 percent of their working pressure or to the test pressure of the ram BOP’s, whichever is less.
Subsequent pressure tests are tests that should be performed at identified periods during drilling and completion activity on a well.
A stable high test pressure should be maintained for at least 5 minutes.
With larger size annular BOPs some small movement typically continues within the large rubber mass for prolonged periods after pressure is applied. This packer creep movement should be considered when monitoring the pressure test of the annular.
Pressure test operations should be alternately controlled from the various control stations.
Pressure tests of hydraulic chambers API RP 53 17.3.2.4
The pressure test performed on hydraulic chambers of annular BOP’s should be to at least 1,500 psi (10.3 MPa).
The tests should be run on both the opening and the closing chambers. Pressure should be stabilized for at least 5 minutes.
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Subsequent pressure tests are typically performed on hydraulic chambers only between wells or when the equipment is reassembled.
04.03 Pressure test frequency
Pressure tests on the well control equipment should be conducted at least: • Prior to spud or upon installation.
• After the disconnection or repair of any pressure containment seal in the BOP stack, choke line, or choke manifold, but limited to the affected component.
• Not to exceed 21 days.
04.04 Accumulator response time
Response time between activation and complete operation of a function is based on BOP or valve closure and seal off. Closing time should not exceed 30 seconds for annular preventers smaller than 18-3/4” nominal bore and 45 seconds for annular preventers of 18-3/4” and larger. Measurement of closing response time begins at pushing the button or turning the control valve handle to operate the function and ends when the BOP or valve is closed affecting a seal. A BOP may be considered closed when the regulated operating pressure has recovered to its nominal setting.
04.05 Hydril annular preventers
Hydril GK annular preventer (See Fig 11)
The “GK” annular blow-out preventer was designed especially for surface installations and is also used on offshore platforms and sub-sea. The “GK” is a universal annular blow-out preventer with a long record of proven performance.
• Only three major components. • Only two moving parts.
Closing pressure should be reduced as wellbore pressure increases in order to prevent excessive closing force.
Standard operation requires both opening and closing pressure. Seal off is effected by hydraulic pressure applied to the closing chamber which raises the piston, forcing the packing unit into a sealing engagement.
The “GK” is designed to be well pressure assisted in maintaining packing unit seal off once initial seal off has been affected. As well bore pressure further increase closure is maintained by well pressure alone.
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Hydril GL annular preventer (See Fig 12)
Hydril “GL” annular preventer are designed and developed both for subsea and surface operations. The proven packing unit provides full closure at maximum working pressure on open hole and vitually anything in the bore - casing, drill pipe, tool joints, Kelly or tubing. Screwed or latched head are available. Opening chamber head separates sealing element from hydraulic opening chamber.
Closing pressure depends upon the manner in which the secondary port is connected into the hydraulic operating system.
The secondary chamber, which is unique to the “GL” BOP, provides this unit with great flexibility of control hook-up and acts as backup closing chamber to cut operation cost and increase safety factors in critical situations.
Hydril GX annular preventer (See Fig 13)
The Hydril “GX” offers extra performance and serviceability while retaining the field proven features of Hydril annular BOP’s.
The “GX” will close on virtually any drill stem member and seal off the open bore.
This feature is called CSO (complete shut off).
Operating volumes are lower, resulting in faster closing times and smaller accumulator requirements. No secondary chamber.
Latched head design.
Fig 13
Opening chamber head separates sealing element from the hydraulic opening chamber. Reduce closing pressure proportionally as well pressure is increased.
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Hydril GX annular preventer closing chart.
Fig 14 shows the relationship of closing pressure and well bore pressure for minimum seal off for GX 18-3/4” –10.000 psi annular preventer. Closing pressures are average and will vary slightly with each packing unit. Use closing pressure shown at initial closure to establish seal off, and reduce closing pressure proportionally as well pressure is increased. Well pressure will maintain closure after exceeding the required level. See Fig 14. Fig 14 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 0 1000 2000 3000 4000 5000 6000 7000 8000 WELL PRESSURE C L OS IN G PR ESSU R E CSO 3-1/2” Ø 5” Ø 7” Ø 9-5/8” Ø 13-5/8” Ø
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04.06 Shaffer annular preventers
Wedge cover spherical BOP (See Fig 15)
Spherical contour of the sealing element gives a long lasting element life.
Element able to close on open hole (CSO). Small amount of seals and components.
Adapter ring separates the wellbore pressure from the hydraulic area.
The preventer is balanced - wellbore pressure does not assist the preventer to remain closed. Hydraulic pressure must be maintained on the closing chamber to force the preventer to seal.
Fig 15 Bolted cover spherical BOP (See Fig 16)
Spherical contour of the sealing element gives a long lasting element life.
Element is able to close on open hole (CSO).
Contains few seals and components. Adapter ring separates the wellbore pressure from the hydraulic area.
The preventer is balanced - that is wellbore pressure does not assist the preventer to remain closed. Hydraulic pressure must be maintained on the closing chamber to force the preventer to seal.
Fig 16
As the preventer is balanced it require 1500 psi closing pressure for all size pipe smaller than 7” and reduced pressure for pipe larger than 7”. See Fig 17.
For stripping operation the size of the pipe being stripped into the well bore and the well bore pressure have to taking into consideration. See Fig 17.
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Fig 17
04.07 Cameron annular preventer
Cameron Cooper type “D” and “DL” (See Fig 18)
In the unique design of the Cameron “DL” annular preventer, closing pressure forces the operating piston and pusher plate upward to displace the solid elastomer donut and force the packer to close inward. As the packer closes, steel reinforcing inserts rotate inwards to form a continuous support ring of steel at the top and bottom of the packer. The inserts remain in contact with each other whether the packer is open, closed on pipe or closed on open hole.
• Replaceable liners around operating piston.
• Weep hole between the wellbore pressure seals and the hydraulic system seals. • A two piece packer. See Fig 19
• Operates at higher pressures than most other annular BOP’s.
• The preventer is balanced - that is wellbore pressure does not assist the preventer closed. Hydraulic pressure must be maintained on the closing chamber to force the preventer to seal.
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Fig 18
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The graph in Fig 20 allow determination of the approximate closing pressure required to seal a given well bore pressure when stripping into the well.
As a new packer wears during stripping, sealing is improved and the closing pressure required to seal on pipe will decrease. For this reason, closing pressure should be reduced as often as is necessary to maintain slight leakage for lubrication of the packer.
Fig 20
04.08 Packing unit
Packing units for the annular BOP’s are available in NITRILE, NEOPRENE or NATURAL rubber. See Fig 21
NITRILE rubber is for use with oil base or oil additive drilling fluids, provides the best
overall service life when operated at temperatures between + 20 deg F to + 190 deg F.
NEOPRENE rubber is for low temperature operating service and oil base drilling fluids. It
can be used at operating temperatures between - 30 deg F to + 170 deg F.
NATURAL rubber is for use in non-oil base drilling fluids and can be used at operating
temperatures between - 30 deg F to + 225 deg F. In extreme emergencies and when no other alternatives are available sealing elements can be replaced while drill pipe is in the hole.
However, this potentially hazardous procedure involves a high degree of risk unacceptable in any circumstances other than emergency.
The packing units consist of two components as steel segments and rubber compound.
The steel segments are moulded into the rubber and will partially close over the rubber to prevent excessive extrusion when sealing under high pressure.
W ELL BORE PRESSURE
CL OS ING PRES SU RE Fig 21
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The segment will ensure the element maintains it shape. When the element is closed the steel segment will compress the rubber out against the well bore and create a seal. When the element is opened up the compressed rubber will expand and bring the element to full open position again within 30 min.
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Section 05
Ram preventers
05.01 General
In the industry to-day we are normally taking about four different manufactures of Ram Preventers used both for Sub-Sea or Surface application:
Cameron Cooper:
Type “U”
Type “U-II”
Model “T”
Hydril: Hydril Ram Preventer
Shaffer: Model “SL”
Model “LWS”
Koomey: J-line
Visual Inspection:
After each well open the Ram Bonnets (doors). The ram cavity and ram block should be cleaned prior to the following visual inspection. This visual examination is generic and valid for all ram preventers. A few additional areas are required when inspecting the Cameron or Koomey “J” line ram preventer.
Ram packers.
Ram packers and top seals should be in good condition. Rubber should not be missing from the pipe contact area on the front packer or sheared off on the top seal
Bonnet seals.
Bonnet seals are generally replaced each time the bonnets are opened.
Top seals.
When top seals are not proud above ram block, in order of .075” to .140” for manufactures in general, the low pressure integrity of the preventer is jeopardized.
Ram cavity
Visually inspect cavity upper seal seat for damage. The surface finish at the top of the cavity is the most critical aspect of this inspection. Sharp scratches make it difficult for top seal rubber to flow into these grooves for pressure integrity.
Ram blocks
If rams are to be used for hanging off the string, record the part number of the ram blocks and verify their capabilities for hanging off. Tagging (hitting) the rams with drill string is the usual cause of damage to the top of a ram block.
Connecting rods/ram shaft packing
To visually examine the connecting rod, the operating piston must be stroked to the closed position when the bonnets or doors are open.
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Power ram change piston
Cameron and Koomey rams use PRC pistons to open and close the bonnets. The surface finish of these chrome rods should also be checked to assure that the operating system has good pressure integrity.
Packing injection
Check to ensure that secondary packing has not been energized. Check weep hole to ensure it is free of sealant. Sealant could prevent a primary wellbore seal from leaking during a stump test which is performed to find such leaks.
Through bore
Visually inspect through bore for key seating record. Repairs should be initiated when this bore wear exceeds 3/16”.
05.02 Testing
Hang-off test (API Spec. 16A 4.7.2.5)
This test shal determine the ability of the ram assembly to maintain a 200-300 psi and full rated working pressure seal while supporting drill pipe loads. This test shall apply to 11 inch and larger blowout preventers. Any hang-off test performed with a variable bore ram shall use drill pipe diameter sizes of the minimum and the maximum diameter designed for that ram. Documentation shall include:
• Nondestructive examination (NDE) of ram blocks in accordance with manufacturers written procedure.
• Load at which leaks develop or 600.000 lb for 5 inch and larger pipe, or 425.000 lb for pipe smaller than 5 inch, whichever is less.
MTC Note: For variable rams always check with manufacturer for correct value.
Function tests (API RP 53 17.3.1)
All operational components of the BOP equipment systems should be functioned at least once a week to verify the component's intended operations. Function tests may or may not include pressure tests.
Function tests should be alternated from the driller's panel and from mini-remote panels, if on location.
Pressure tests (API RP53 17.3.2)
17.3.2.1 All blowout prevention components that may be exposed to well pressure should
be tested first to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to a high pressure.
• When performing the low pressure test, do not apply a higher pressure and bleed down to the low test pressure. The higher pressure could initiate a seal that may continue to seal after the pressure is lowered and therefore misrepresenting a low pressure condition.
• A stable low test pressure should be maintained for at least 5 minutes.
17.3.2.2 The initial high pressure test on components that could be exposed to well
pressure (BOP stack, choke manifold, and choke/kill lines) should be to the rated working pressure of the ram BOP’s or to the rated working pressure of the wellhead that the stack
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should be performed on location before the well is spudded or before the equipment is put into operational service.
There may be instances when the available BOP stack and/or the wellhead have higher working pressures than are required for the specific wellbore conditions due to equipment availability. Special conditions such as these should be covered in the site-specific well control pressure test program.
17.3.2.3 Subsequent high pressure tests on the well control components should be to a
pressure greater than the maximum anticipated surface pressure, but not to exceed the working pressure of the ram BOP's. The maximum anticipated surface pressure should be determined by the operator based on specific anticipated well conditions.
Subsequent pressure tests are tests that should be performed at identified periods during drilling and completion activity on a well.
A stable high test pressure should be maintained for at least 5 minutes.
Pressure test operations should be alternately controlled from the various control stations.
17.3.2.4 Initial pressure tests on hydraulic chambers of ram BOP’s and hydraulically
operated valves should be to the maximum operating pressure recommended by the manufacturer. The tests should be run on both the opening and the closing chambers. Pressure should be stabilized for at least 5 minutes.
Subsequent pressure tests are typically performed on hydraulic chambers only between wells or when the equipment is reassembled.
Test fluids
17.3.5 Well control equipment should be tested with water. Air should be removed from
the system before the test pressure is applied. Control systems and hydraulic chambers should be tested using clean control fluids with lubricity and corrosion additives for the intended service and operating temperatures.
05.03 Pressure test frequency
Pressure tests on the well control equipment should be conducted at least: 1. Prior to spud or upon installation.
2. After the disconnection or repair of any pressure containment seal in the BOP stack, choke line, or choke manifold, but limited to the affected component.
3. Not to exceed 21 days.
05.04 Accumulator response time (API RP53 12.3.3)
Response time between activation and complete operation of a function is based on BOP or valve closure and seal off. For surface installations, the BOP control system should be
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capable of closing each ram BOP within 30 seconds. Response time for choke and kill valves (either open or close) should not exceed the minimum observed ram close response time.
Measurement of closing response time begins at pushing the button or turning the control valve handle to operate the function and ends when the BOP or valve is closed affecting a seal. A BOP is considered closed when the regulated operating pressure has recovered to its nominal setting. If confirmation of seal off is required, pressure testing below the BOP or across the valve is necessary.
05.05 Cameron ram preventer
Fig 22
Cameron (C.C.C.) manufactures three models of ram preventers specifically designed for sub-sea and surface applications. See Fig 22
They are the type “U” - “U-II” – “T”.
In all three products the following features are incorporated: • Power ram change ( PRC system).
• Four bonnet bolts or studs used per bonnet.
• Wedgelock - ram locking system (Optional for type U) • Ram cavities are parallel, top and bottom.
• Bonnet and body are forged.
Specific model features: Type “U”:
Can be fitted with hydraulic bonnet bolts
Plastic ram shaft packing and weep hole standard
Type “U-II”:
Hydraulic bonnet studs as standard.
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Model “T”:
Hydraulic bonnet studs
Replaceable wear pad fitted beneath ram block
In this manual we only look at Cameron type U and U-II
The Cameron “U-II” ram type blow-out preventer includes an internally ported hydraulic bonnet tensioning system, a short stroke bonnet, bore type bonnet seals and the proven advance of the “U” BOP design. The “U-II” can be provided in single and double configurations with API flange, hubbed or studded connections, and flanged or hubbed outlets.
In Fig 23 the single components of a Cameron type U single ram BOP is shown.
Fig 23
A: Bonnet bolt B: Ram change cylinder C: Ram assembly
D: Body E: Bonnet seal F: Ram change piston
G: Locking screw H: Operating cylinder I: Locking screw housing
J: Intermediate flange K: Bonnet L: Operating piston The short stroke bonnet reduces the opening stroke by about 30%, reduces the length of the BOP and reduces the weight supported by the ram change pistons. The bore type bonnet seal fits into a seal counter bore in the body and has a metal anti-extrusion ring. When talking about Shear rams large bore shear bonnets provides the largest capacity operating piston to increase shearing force. This means that the operating cylinder is removed and the piston size increased to obtain higher pressure area.
Due to the shear rams operating piston needs longer travel the intermediate flange is increased in thickness to facilitate this requirement.
The U and U-II blowout preventers are designed so that hydraulic pressure opens and closes the rams, and provides the means for quick ram change out. See Fig 24
Ram closing pressure, shown in red in Fig 24 closes the rams. When the bonnet bolts are removed, closing pressure opens the bonnet. When the bonnet has moved to the fully
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extended position, the ram is clear of the body. An eyebolt can be installed into the top of each ram to lift it out of the preventer.
Ram opening pressure, shown in blue in Fig 24 opens the rams and closes the bonnets after ram change out. The rams are opened fully before the bonnets begin moving toward the preventer body. This assures that the rams never obstruct the bore or interfere with pipe in the hole. Hydraulic pressure draws the bonnets tightly against the preventer body and the bonnet bolts are reinstalled to hold the bonnets closed.
Fig 24
The four bonnet studs are simultaneously stretched to the correct pre-load by hydraulic pressure applied behind a piston which acts on a load rod in the stud. The nut is then tightened and pressure is released. Pressure is supplied by an air powered hydraulic pump via internal porting in the BOP body. See Fig 25
Fig 25
The intermediate flange is the barrier between the well bore and the hydraulic operating chamber and contains the seals around the operating shaft. In the bottom of the intermediate flange a weep or vent hole is positioned witch must always be clean. The weep hole has several functions:
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1. During pressure test of the ram BOP leakage through the weep hole indicates worn seals against the wellbore and require immediately change out prior to commence operation.
2. Leakage during pressure test of the hydraulic chamber indicates worn seal against the hydraulic operating side and require immediately change out prior to commence operation.
3. The weep hole avoids well bore pressure on the opening side of the hydraulic chamber.
A secondary seal is installed in the top of the intermediate flange. In the event of leakage during a well control situation the secondary can be engaged by injecting plastic packing through a packing ring that will seal against the well bore. See Fig 26.
Fig 26
Fig 26
All ram BOP’s must be equipped with a ram lock system that can either be manual operated or hydraulic operated to assure that the ram does not open if the hydraulic closing pressure is lost. If it is a manuel system it should be equipped with extension hand wells.
For hydraulic operated system Cameron is using the wedge-lock system.
The wedge-lock acts directly on the operating piston tailrod. The operating system can be interlocked using sequence caps to ensure that the wedge-lock is opened before pressure is applied to open the BOP. See Fig 27.
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1. Locking Head 2. Locking Piston 3 Wedge Piston 4. Wedgelock Housing 5. Unlocking Head 6. Open Port7. Ram Change Assembly 8. Bonnet
9. Operating Piston 10. Tail Rod Extension 11. To Balance Chamber 12. Close Port
05.06 Cameron ram assembly
All BOP manufactures supply three different types of rams: Fixed ram assemblies.
Variable ram assemblies. Shear/Blind ram assemblies.
Fixed ram assembly
The ram assembly consist of Ram Body, Front Packer and Top Seal. To dress the ram body the front packer must be installed first. The top seal is then installed and locks the front packer in place. See Fig 28.
The fixed ram assembly can be obtained in different sizes from 2-3/8” to 6-5/8”.
Fig 28
Ram packers and top seals should be in good condition. Rubber should not be missing from the pipe contact area on the front packer or sheared off on the top seal. As a general rule, ram packers should be considered acceptable when 80% of the rubber in the pipe contact area is still in place.
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Variable ram assembly Fig 29
One set of variable bore rams can be used to seal on a range of pipe. A set of variable bore rams installed in a BOP saves a round trip of a SubSea BOP stack by eliminating the need to change rams when different diameter drill strings are in use. A set of variable bore rams in a BOP stack provides backup for two or more sizes of standard pipe rams or serves as the primary ram for one size and the backup for the other. See Fig 29.
Shear/Blind ram assembly
Shear/Blind rams are designed to shear drill pipe and lighter tubular like tubing and establish a seal against wellbore pressure using high hydraulic closing pressure.
The Shear/Blind rams consist of a upper and lower ram body. To dress a Shear/Blind ram body (C) the blade or front packer (F) is installed first. The side packers (B) is then installed to keep the blade packer in place and finally the top packer (E) is inserted to lock the side packers. See Fig 30.
Fig 30
Importance of ram packer pressure
Packer pressure is the internal elastomer compressive force generated in the ram packers when closing hydraulic pressure drives the ram assemblies into contact with each other. For a ram assembly to contain wellbore pressure the packer pressure must be higher than the wellbore pressure trying to get past the rubbers. Typically, closing hydraulic operating pressure generates several thousand psi elastomer pressure inside the ram packers. This is sufficient to initially contain wellbore pressure. See Fig 31. As wellbore pressure rises,
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the packer pressure rises as well due to the closing effect that the wellbore pressure has upon
the ram blocks. See Fig 32. With this mechanism, packer pressure is maintained above wellbore pressure.
Fig 31 Fig 32
When we have a worn out ram cavity or worn ram rubbers, the closing operating pressure is not able to generate the required packer pressure with a leak resulting.
Feedable rubber
All major ram type BOP manufacturers use the feedable rubber design concept in their ram packers. This includes Cameron, Hydril, Shaffer and MH Koomey. Extrusion plates moulded into the front packer into the front packer serves several purposes:
To support the rubber to prevent unwanted extrusion due to wellbore forces in the vertical direction.
Act as pistons to extrude feedable rubber to the point of pipe contact. See Fig 33.
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A new front packer contains large volume of feedable rubber. When seal off is obtained, a large clearance exists between the ram and pipe.
A moderately worn packer still retains a large but reduced volume of feedable rubber. The clearance between the ram and pipe is reduced at the seal off position.
The extensively worn front packer has used almost all of the feedable rubber volume, but still able to effect a full rated seal off. The clearance between the ram and pipe is now approaching zero, indicating completion of the useful life of the front packer.
Note: All ram type BOP’s are only designed to contain and seal Rated Working Pressure from below the ram.
07.05 Operating ratio
The first ram preventers used in drilling operations were manually operated. Threaded stems were provided to move ram blocks back and forth between the open and close position. It soon became apparent that a faster operating method was needed to close the rams when a well kicked. This led to the development of hydraulic operated pistons to close or open the rams.
In Fig 34 is showed a simplified sketch of a hydraulic operated ram preventer. Fluid operating on the operating piston closes or opens the rams. Each type and size of ram preventer has a specified closing and opening ratio, which is a function of that rams particular geometry.
Fig 34 Closing Ratio.
Definition: A dimensionless factor equal to the wellbore pressure divided by the
operating pressure necessary to close the ram BOP against wellbore pressure.
When closing the rams, hydraulic closing pressure acting on the ram operating piston area must overcome the wellbore pressure acting on the ram shaft area which is attempting to force the ram in to open position. This ratio exists because of difference in areas that the closing hydraulic pressure acts upon compared to the ram rod area exposed to wellbore pressure. See Fig 35.
RAM PISTON
RAM SHAFT
CLOSING CHAMBER OPENING CHAMBER
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Closing ratios are generally in the range from 6:1 to 9:1. This means that it takes 1 psi of closing hydraulic pressure per 6 to 9 psi wellbore pressure to close the preventer. Stated in another way, on a preventer with closing ratio of 6:1, if the wellbore pressure is 3000 psi it should take 500 psi hydraulic pressure to close the preventer.
Fig 35
The extreme case is closing the ram preventer while it is exposed to maximum rated pressure in the wellbore. This required closing pressure is calculated by the following formula:
Opening ratio.
Definition: A dimensionless factor equal to the wellbore pressure divided by operating
pressure necessary to open a ram BOP containing wellbore pressure.
Opening rams under pressure is not recommended. The following are for information and understanding purposes only!
When opening rams, hydraulic opening pressure acting on the ram operating piston area must overcome the wellbore pressure acting on the back side of the ram blocks. This wellbore pressure is holding the rams in the closed position. The area behind the ram blocks is fairly large, so the opening ratios are much lower. Opening ratios between 1:1 and 4:1 are common. Some preventers have opening ratios less than 1:1 which means that the opening pressure must exceed the wellbore pressure.
In Fig 36 is an exposed view showing forces on a ram block and ram shaft while containing pressure below the ram cavity. The packer is sealed on pipe and opening force is being applied to the operating piston.
Fig 36
The extreme case is opening the ram preventer while it is exposed to maximum rated pressure in the wellbore. This required opening pressure is calculated by the following formula: WELL PRESSURE RAM SHAFT AREA CLOSING AREA CLOSING PRESSURE
Closing pressure required to Rated Working Pressure
close ram with rated wellbore =
---pressure in the bore Closing Ratio
RAM BLOCK RESULTANT
RAM SHAFT RESULTANT
Opening pressure required to Rated Working Pressure
open rams with rated working =
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08.05 BOP end and side outlet Connections
On all type of BOP’s three different types of connections is used both as end connections and side outlet connections. This includes ram preventer, annular preventer, drilling spools, casing spools and hydraulic connectors. The three types are Studded, Clamp Hub and flanged connection. See Fig 36,37,38.
Studded Connection Fig 36
Clamp Hub Connection
Fig 37
Flanged Connection
Fig 38
09.05 API type flanges
Two types of flanges are used in wellcontrol equipment according to API. API Type 6B Flange and API Type 6 BX Flange.
API type 6B flange.
API Type 6B flange is a “low” pressured flange with maximum pressure rating of 5000 psi. API Type R or RX ring gaskets are used for this type flange and does not allow face to face contact between hubs or flanges, so external loads are transmitted through the sealing surfaces of the ring.
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Fig 39
API type 6 BX flange.
API Type 6 BX flange is a “high” pressure flange with maximum pressure rating of 20000 psi.
API Type BX ring gaskets are used for this type of flange allowing face to face contact of the flanges.
The flange face shall be raised except for studded flanges which may have flat faces. See Fig 40.
Fig 40
FLANGE SECTION
INTERGRAL FLANGE TOP VIEW
FLANGE SECTION
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RATED
WORKING PRESSURE
FLANGE SIZE RANGE
TYPE 6 B TYPE 6 BX 2000 3000 5000 10000 15000 20000 2-1/16” – 21-1/4” 2-1/16” – 20-3/4” 2-1/16” – 11” 26-3/4” – 30” 26-3/4” – 30” 13-5/8” – 21-1/4” 1-13/16” – 21-1/4” 1-13/16” – 18-3/4” 1-13/16” – 13-5/8” Marking
According to API the following marking should be visible on the flanges OD: • Manufacturer’s name and mark
• API monogram • Size
• Thread size
• End and outlet connection size • Rated working pressure
• Ring gasket type and number • Ring gasket material
10.05 Ring joint gaskets and grooves Introduction
Ring Joint gaskets and grooves are described within API RP 16A and API RP 53.
• Ring gaskets have a limited amount of positive interference which assures the gaskets will be joined into sealing relationship within the flanges grooves.
• These gaskets shall not be re-used.
Material
The purchaser can specify one of the four different materials when he produces API gaskets:
MATERIAL HARDNESS
BRINELL IDENTIFICATION MARKING
Soft Iron 90 D
Low-Carbon Steel 120 S
Type 304 Stainless Steel 160 S 304
Type 316 Stainless Steel 140 to 169 S 316