Well Control Equipment
Well Control Manual Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training 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 Maersk Training. Copyright © Maersk Training A/S
2010-January
Prepared by
NLN & JOA
Modified & printed
2010 July
Modified by
MJB
Approved by
JOA
Address
Maersk Training A/S Dyrekredsen 4. Rantzausminde DK - 5700 Svendborg Denmark
E-mail:
[email protected]
Homepage
www.maersktraining.com
Internal reference
2010_01_Equipment_Training_rev1.docx
-1-
Well Control Manual Table of contents: Section 01 Well control barriers. ................................................................................. 4 01.01 01.02
Primary well control barrier. ............................................................................ 4 Secondary well control barrier......................................................................... 4
Section 02 BOP configuration ..................................................................................... 5 02.01 02.02 02.03
Bop stack arrangements ................................................................................. 5 Stack component codes .................................................................................. 5 Drilling spools.................................................................................................. 6
Section 03 Diverter systems ........................................................................................ 8 03.01 03.02 03.03 03.04 03.05 03.06
Purpose of diverter system (API RP53 4.1) .................................................... 8 Diverter equipment (API RP53 4.2.2) .............................................................. 8 Guidelines for diverting with string on bottom ............................................... 11 Guidelines for diverting with string off bottom ............................................... 11 Rotating head................................................................................................ 11 Diverter control system ................................................................................. 13
Section 04 Annular preventers .................................................................................. 14 04.00 04.01 04.02 04.03 04.04 04.05 04.06 04.07 04.08
Definition (API RP53 3.1.2) ........................................................................... 14 General ......................................................................................................... 14 Testing .......................................................................................................... 14 Pressure test frequency ................................................................................ 16 Accumulator response time........................................................................... 16 Hydril annular preventers .............................................................................. 16 Shaffer annular preventers ........................................................................... 21 Cameron annular preventer .......................................................................... 23 Packing unit .................................................................................................. 24
Section 05 Ram preventers........................................................................................ 25 05.00 05.01 05.02 05.03 05.04 05.05 05.06 05.07 05.08 05.09 05.10
General ......................................................................................................... 25 Testing .......................................................................................................... 26 Pressure test frequency ................................................................................ 27 Accumulator response time (API RP53 12.3.3)............................................. 27 Cameron ram preventer ................................................................................ 28 Ram locking systems .................................................................................... 31 Cameron ram assembly ................................................................................ 36 Operating ratio .............................................................................................. 39 BOP end and side outlet Connections .......................................................... 41 API type flanges ............................................................................................ 41 Ring joint gaskets and grooves ..................................................................... 43
Section 06 Choke manifold ........................................................................................ 47 06.01 06.02 06.03 06.04 06.05 06.06
General ......................................................................................................... 47 Choke manifold – installation ........................................................................ 47 Choke lines – installation .............................................................................. 48 Kill lines – installation .................................................................................... 48 BOP – Side outlet valves .............................................................................. 49 Chokes .......................................................................................................... 49 -2-
Well Control Manual 06.07 06.08 06.09
Hydrates........................................................................................................ 51 Mud/gas separator ........................................................................................ 52 Degasser....................................................................................................... 54
Section 07 Auxiliary equipment ................................................................................ 55 07.01 07.02 07.03 07.04 07.05 07.06 07.07 07.08 07.09 07.10
Kelly valves ................................................................................................... 55 Top drive valves ............................................................................................ 55 Drillpipe safety valve (DPSV) ........................................................................ 56 Inside blowout preventer (IBOP) ................................................................... 56 Drillstring float valve ...................................................................................... 56 Tester plug .................................................................................................... 57 Cup type tester plug ...................................................................................... 58 Triptank ......................................................................................................... 58 Pit volume measuring devices ...................................................................... 58 Flow rate sensor ........................................................................................... 58
Section 08 Subsea BOP stack components ............................................................. 59 08.01 08.02 08.03
Model 70 Collet Connector (Cameron Iron Works) ....................................... 60 Model HC Collet Connector (Cameron Iron Works) ...................................... 62 Hydraulic operated choke/kill line valves ...................................................... 63
Section 09 Drilling riser and related components ................................................... 64 09.01 09.02 09.03 09.04
Flex/Ball joint................................................................................................. 65 Telescopic joint ............................................................................................. 66 Riser fill-up valve ........................................................................................... 67 Mechanical riser coupling ............................................................................. 67
Section 10 Hydraulic BOP control system components (Subsea) ......................... 68 10.01 10.02 10.03 10.04 10.05
Subsea hose bundle storage reels................................................................ 69 Manifolds on the Subsea hose bundle storage reels .................................... 70 Subsea hose (Umbilical) ............................................................................... 70 Subsea control pods (blue and yellow) ......................................................... 71 Shuttle valves................................................................................................ 72
-3-
Well Control Manual 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.
-4-
Well Control Manual 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 Fig. 01 & 02 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 3K 5K 10K 15K 20K
2000 psi (13.8 MPa) 3000 psi (20.7 MPa) 5000 psi (34.5 MPa) 10000 psi (69.0 MPa) 15000 psi (103.5 MPa) 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 operator's choice. -5-
Well Control Manual 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 identified 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: 1. 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 2inch (5.08 cm) nominal diameter as a minimum, and be flanged, studded, or hubbed. -6-
Well Control Manual 2. 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. 3. 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.
-7-
Well Control Manual Section 03
Diverter systems
Fig 04
03.01 Purpose of diverter system (API RP53 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 RP53 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.
-8-
Well Control Manual
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 RP53 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. -9-
Well Control Manual
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: 1. Open B or C depending on wind direction 2. Close E 3. 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 09.
Fig 08
Fig 09
- 10 -
Well Control Manual 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 3.1.80 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 geothermal applications. Later generation equipment was applied by industry for the drilling applications that causes high pressures at the wellhead. The original design engineering principles for its use still applies today. Within the BOP system the recognizes the rotating head as a diverter. See Fig 10.
and flow and API
The rotating BOP is used on top of a regular BOP stack consisting of ram and annular BOPs.
- 11 -
Well Control Manual 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 10 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 11. • • •
The rotating assembly The body Kelly drive uni
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. Fig 11 Some rotating heads is build with hydraulic pressurised stripping rubbers. - 12 -
Well Control Manual 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.
- 13 -
Well Control Manual Section 04
Annular preventers
04.00 Definition (API RP53 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 API RP53 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 subsea application. 5. Milling Check for metal shavings if milling operations have been performed. - 14 -
Well Control Manual 6. Operating Pressures Ensure that a operating range pressure chart in relation to pipe size and wellbore pressure is posted. 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 RP53 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 BOP’s 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.
- 15 -
Well Control Manual Pressure tests of hydraulic chambers API RP53 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. 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 12) 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. Fig 12 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.
- 16 -
Well Control Manual 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. Hydril GL annular preventer (See Fig 13) The Hydril GL annular preventers are designed and developed for subsea and surface operations. The packing unit provides full closure at Rated Working Pressure on open hole and on most items in the wellbore - casing, drill pipe, tool joints, kelly or tubing. The special design of the Hydril GL makes it suited for subsea and deep water drilling. These drilling Fig. 13 conditions demand long-life packing elements for drill pipe stripping operations and frequent testing. The secondary chamber, which is unique for the GL BOP, provides this unit with great flexibility of hydraulic control hook-up. The chamber can be connected in two ways to optimise operations for different effects, either to minimise closing/opening fluid volumes or to reduce closing pressure. Connecting the secondary chamber (Fig 14) to the opening chamber is considered a standard hookup for all surface drilling installations. This hookup results in the fastest closing time since it requires the least amount of hydraulic fluid to close the BOP. Fig. 14
- 17 -
Well Control Manual
Looking at Fig 15, the secondary chamber is connected to the closing chamber resulting in this optional control technique. This hookup reduces the closing pressure needed to close the BOP to approximately 67% of the pressure required by the standard hookup. However, this hookup requires more fluid volume to close and thus results in a slower closing time compared to the standard hookup.
Fig. 15
When operating most annular BOPs on the seabed in a subsea operation the hydrostatic pressure of the drilling fluid column in the marine riser exerts an opening force on the BOP. Since the hydrostatic head of the drilling fluid in the marine riser vary with different drilling fluid densities and also with the depth those BOPs require a different hydraulic closing pressure, which vary with those conditions.
Fig. 16
The GL BOP’s secondary chamber should be hooked up using one of two techniques to take the full benefits of the GL’s design.
Subsea Hook-up for water depth up to 800 ft: Secondary Chamber - Opening Chamber. This control technique requires the same fluid volume for closing the BOP as the counter balance connection. It is standard hook-up in water depths up to about 800 ft. Closing pressure requires an adjustment for drilling fluid hydrostatic pressure in the marine riser to account for the opening force exerted on the BOPs piston. The operators manual should be consulted for adjusting the correct hydraulic control pressures.
- 18 -
Well Control Manual Subsea Hook-up for water depth over 800 ft: Secondary Chamber - Closing Chamber. This control technique reduces closing pressure by approximately 33% versus the secondary chamber to opening chamber hook-up. See Fig 17. This hoop-up should be considered for use in water depths over 800 ft. The operators manual should be consulted for adjusting the correct hydraulic control pressures.
Fig. 17 Secondary Chamber - Balance Chamber. With this control technique the varying hydrostatic pressures in the marine riser caused by changes of drilling fluid density or due to varying water depths of the BOP are directly compensated for. See Fig 18. Fig. 18
This is obtained by directing the effective opening pressure to act also for the closing of the BOP. The two forces are equal and they counterbalance each other. The operators manual should be consulted for adjusting the correct hydraulic control pressures. Hydril GX annular preventer (Fig 19) 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 19 - 19 -
Well Control Manual
Opening chamber head separates sealing element from the hydraulic opening chamber. Reduce closing pressure proportionally as well pressure is increased. 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 20.
3000 2800 2600
CLOSING PRESSURE
2400
CSO
2200 2000 1800 1600 1400 1200
3-1/2” Ø
1000 800
9-5/8” Ø
600
7” Ø 5” Ø
400
13-5/8” Ø
200 0
1000
2000
3000
4000
5000
WELL PRESSURE
Fig 20
- 20 -
6000
7000
8000
Well Control Manual 04.06 Shaffer annular preventers Wedge cover spherical BOP (Fig 21) 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 21
Bolted cover spherical BOP (Fig 22) 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 22
- 21 -
Well Control Manual 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 23.
Fig 23 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 Fig24.
Fig 24
- 22 -
Well Control Manual 04.07 Cameron annular preventer Cameron Cooper type “D” and “DL” (Fig 25) 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 26 • 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.
Fig 25
Fig 26 - 23 -
Well Control Manual
CLOSING PRESSURE
The graph in Fig 27 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 27 04.08 Packing unit
W ELL B ORE PR ESSU RE
Packing units for the annular BOP’s are available in NITRILE, NEOPRENE or NATURAL rubber. See Fig 28 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.
Fig 28
The steel segments are moulded into the rubber and will partially close over the rubber to prevent excessive extrusion when sealing under high pressure. 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. - 24 -
Well Control Manual Section 05 Ram preventers 05.00 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.
- 25 -
Well Control Manual 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”. 05.01 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. Note: For variable rams always check with manufacturer for correct value. Function tests (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. 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 - 26 -
Well Control Manual is installed on, whichever is lower. 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. 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. 05.02 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. 05.03 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 - 27 -
Well Control Manual 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. 05.04 Cameron ram preventer
Fig 29 Cameron (C.C.C.) manufactures three models of ram preventers specifically designed for sub-sea and surface applications. See Fig 29 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. • Plastic ram shaft packing and weep hole standard - 28 -
Well Control Manual 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 30 the single components of a Cameron type U single ram BOP is shown.
Fig 30 A: D: G: J:
Bonnet bolt Body Locking screw Intermediate flange
B: E: H: K:
Ram change cylinder Bonnet seal Operating cylinder Bonnet
C: F: I: L:
Ram assembly Ram change piston Locking screw housing 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 31 Ram closing pressure, shown in red in Fig 31 closes the rams. When the bonnet bolts are removed, closing pressure opens the bonnet. When the bonnet has moved to the fully - 29 -
Well Control Manual 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 31 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.
U II BLOWOUT PREVENTER HYDRAULIC CONTROL SYSTEM
Fig 31 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 32
Fig 32
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:
- 30 -
Well Control Manual 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 33.
Fig 33 05.05 Ram locking systems 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.
- 31 -
Well Control Manual Wedge Lock (Cameron Iron Works) The Wedge Lock System (Fig 34) is a hydraulically operated mechanical locking mechanism, thus demanding a separate hydraulic system to be activated and deactivated. The wedgelock system will lock the rams in their closed position and maintain the rams mechanically closed and locked eventhough the actuating pressure is released. The hydraulic operating system can be interlocked using sequence valves to ensure that the wedgelock is retracted before pressure is applied to open the rams. For subsea applications, a pressure balance chamber is connected to the wedgelock housing to eliminate the possibility of the wedgelock becoming unlocked due to hydrostatic seawater pressure.
Fig. 34
Poslock (Shaffer) Shaffer ram BOPs equipped with Poslock (Fig 35) pistons are locked automatically in the closed position each time they are closed. The rams will remain locked in the closed position even if closing pressure is removed. Hydraulic pressure supplied to the open side of the pistons is required to reopen the rams.
Fig. 35
The Poslock System utilises locking segments to achieve the positive mechanical lock. The Poslock System has one set of locking segments, which provides for one unique position locking. When the front packer elastomers on the rams become worn the Poslock System cannot automatically compensate for increased distance between the mating ram packers. The activation of the Poslock System to lock and to unlock the rams will happen as a result of the mechanical design making the system independent from any additional hydraulic activating systems.
- 32 -
Well Control Manual When closing the rams the hydraulic pressure is applied to the closing side of the pistons. The two complete piston assemblies move towards the well centre until they contact each other. When the pistons have reached the fully closed position the locking segments have then reached the position where the larger cylinder liner diameter begins. The closing hydraulic pressure is also exposed to the locking cone, which is a separate part placed inside the piston. The hydraulic force on the locking cone makes it travel a further distance towards the well centre inside the piston. This additional travel distance forces the locking segments to move radial outwards due to the tapered shoulder on the locking cone. The segments lock the piston in the cylinder liner. The locking cones maintain the locking segments in position. Springs ensure that the locking cone position is maintained also if the hydraulic closing pressure is removed. To open the rams again hydraulic opening pressure is supplied to the pistons opening side. Initially the locking cone will travel a short distance inside the piston. This allows the locking segments to retract allowing the piston to open the rams. UltraLock (Shaffer) Shaffer ram BOPs that are equipped with the UltraLock (Fig 36) system are locked automatically in the closed position each time the rams are closed. The rams remain locked in the closed position also if the hydraulic closing pressure is removed. Hydraulic opening pressure is required to unlock and re-open the rams. The locking system is mechanical and consists of spring loaded locking dogs that are engaged against restrained locking rods. Four rods per piston are used with four mating locking dogs. The load is carried simultaneously on a pair of two rods and locking dogs which are placed 180 degrees apart. This allows a greater number of locked positions.
Fig. 36
Due to the design no additional hydraulic lines or functions are required for activating and deactivating of the UltraLock. Hydraulic pressure is applied to the pistons when closing. The entire piston assembly moves towards the well centre together with the rams. When the rams meet each other the motion becomes restricted. At this stage the hydraulic pressure forces the secondary piston to move an additional distance within the UltraLock piston. This allows the locking segments to move radial outwards. The - 33 -
Well Control Manual radial motion supported by springs engages the locking segments into their respective locking rods. The rams will be maintained in the locked position even if the hydraulic pressure is lost or removed. The interlock between the locking rods and the locking dogs is obtained by a mating tooth profile machined into the surface of the locking rods and in the locking dogs. With wear on the front packer elastomers the further motion of the assembly towards the well centre will make the locking dogs engage at this new position. The UltraLock adjusts the locking position closer to the well centre along with wear on the front packer elastomers. When hydraulic pressure is applied to open the rams, the secondary piston responds at first and consequently the locking segments become disengaged. Consequently the UltrLock piston can move unrestricted and open the rams. UltraLock II (Shaffer)
Fig. 38
Fig. 37
The Shaffer UltraLock II locking system (Fig 37 & 38) incorporates a mechanical locking mechanism within the piston assembly. The locking system is independent of hydraulic closing pressure to remain locked. It uses flat tapered locking segments carried by the operating piston, which engages with another stationary and tapered shaft fixed in the operating cylinder. When using SL-D rams, the UltraLock II has hang-off capabilities up to 600,000 pounds at full working pressure. The system needs no adjustments, no matter the size of the pipe rams. Different size or type ram assemblies can be freely interchanged.
- 34 -
Well Control Manual Only one hydraulic function is required to operate the cylinder’s open/close function and the locking system. The system automatically locks in the closed position each time the piston assembly is closed compensating for front packer wear. Once the operating piston is closed on the pipe, the locks are engaged until opening pressure is applied. Only hydraulic pressure can unlock and reopen the rams. Multiple Position Locking MPL (Hydril)
Fig. 39 Fig. 40 Some Hydril ram BOPs are available with automatic Multiple Position ram Locking MPL (fig39 & 40). MPL allows the ram to seal off with optimum seal squeeze effect on every closure. MPL automatically locks and maintain the rams closed with optimum rubber pressure required for seal off on the front packer and upper seal. Front packer seal wear (on any ram BOP) requires a different ram locking position closer to the well centre to ensure an effective seal off. MPL is designed to automatically adjust to the new seal off position. A mechanical lock is automatically set each time the ram is closed. Ram closure is accomplished by applying hydraulic pressure to the closing chamber, which moves the ram to a seal off position. The locking system maintains the ram mechanically locked while seal off is retained even after releasing hydraulic closing pressure. The ram is opened only by application of hydraulic opening pressure. This releases the locking system initially and then opens the ram.
- 35 -
Well Control Manual Fig 39 shows the ram maintained closed and sealed off by the MPL. Hydraulic closing pressure has been released. The Hydril ram BOP automatically maintains ram closure and seal off. MPL will maintain the required rubber pressure on the front packer and upper seal to ensure a seal off up to the BOP Rated Working Pressure. MPL will maintain the seal off without closing pressure and with opening forces created by hanging the drill string on the ram. A unidirectional clutch mechanism and a lock nut control locking and unlocking of the MPL. The unidirectional clutch mechanism maintains the nut and ram in a locked position until the clutch is disengaged by application of opening hydraulic pressure. Hydraulic opening pressure disengages the clutch plates to permit the lock nut to rotate freely and the ram to open. The travel of the piston and the threaded tail rod during closing or opening the ram causes the lock to rotate. The fast lead six-path helical thread rotates the nut three turns per foot of travel. 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 Fig41. The fixed ram assembly can be obtained in different sizes ranging from 2-3/8” to 6-5/8”.
Fig 41 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.
- 36 -
Well Control Manual Variable ram assembly 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 42. Fig 42 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 43.
Fig 43 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 44. As wellbore pressure rises, the packer pressure rises as well due to the closing effect that the wellbore pressure has upon the ram blocks. See Fig 45. - 37 -
Well Control Manual With this mechanism, packer pressure is maintained above wellbore pressure.
Fig 44
Fig 45
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 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 46.
Fig 46 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.
- 38 -
Well Control Manual 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 one direction ie. from below the ram. 05.07 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 47 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. RAM SHAFT
OPENING CHAMBER
PISTON
CLOSING CHAMBER
RAM
Fig 47 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 48.
- 39 -
Well Control Manual CLOSING AREA RAM SHAFT AREA WELL PRESSURE
CLOSING PRESSURE
Closing ratios are generally in the range from 6:1 to 11:1. This means that it takes 1 psi of closing hydraulic pressure per 6 to 11 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 48 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: Closing pressure required to close ram with rated wellbore pressure in the bore
Rated Working Pressure = ------------------------------------Closing Ratio
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. RAM BLOCK RESULTANT
RAM SHAFT RESULTANT
In Fig 49 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 49 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: Opening pressure required to open rams with rated working pressure in the wellbore
Rated Working Pressure = ------------------------------------Opening Ratio
- 40 -
Well Control Manual 05.08 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 50 - 52.
Studded Connection
Fig 50
Clamp Hub Connection
Fig 51
Flanged Connection
Fig 52 05.09 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.
- 41 -
Well Control Manual The flange face might be flat or raised type. See Fig 53.
FLANGE SECTION INTERGRAL FLANGE
TOP VIEW
Fig 53 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 54.
FLANGE SECTION INTERGRAL FLANGE
TOP VIEW
Fig 54
- 42 -
Well Control Manual
RATED WORKING PRESSURE
2000 3000 5000 10000 15000 20000
FLANGE SIZE RANGE TYPE 6 B TYPE 6 BX
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 • Nominel Size (Through bore) • Thread size • End and outlet connection size • Rated working pressure • Ring gasket type and number • Ring gasket material 05.10 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 Soft Iron Low-Carbon Steel Type 304 Stainless Steel Type 316 Stainless Steel Inconel 625
HARDNESS BRINELL 90 120 160 140 to 169 481 to 560 - 43 -
IDENTIFICATION MARKING D S S 304 S 316
Well Control Manual API type “R” ring joint gasket This type “R” ring joint gasket is not energized by internal pressure. Sealing takes place along small bands of contact between grooves and the gasket on both the OD and ID of the gasket. The gasket may be either octagonal or oval in cross section. The Type “R” design does not allow face to face contact between hubs and flanges, so external loads are transmitted through the sealing surfaces of the ring. Vibration and external loads may cause small bands of contact between the ring and the groove to deform plastically, so that the joint may develop a leak unless the flange bolting is periodically tighten. Standard procedure with type “R” joints in the BOP stack is to tighten the flange bolting weekly. See Fig 55 & 57.
Type RX
Type R
Fig 55 API Type “RX” Pressure-Energised Ring Joint Gasket The “RX” pressure-energised ring joint gasket was developed by CIW and adopted by API. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The “RX” design does not allow face to face contact between hubs and flanges. The gasket has large load bearing surfaces on it’s inside diameter to transmit external loads without plastic deformation of the sealing surfaces of the gasket. See Fig 55 & 57. API Type “BX” Pressure-Energised Ring Joint Gasket In an effort to develop a more compact flange design for high pressure us the “BX” series was developed. By allowing face to face contact of the flanges, ring gasket compression and elastic deformation could be controlled. This allowed a proportionally smaller gasket to be used with the effect of reducing bolt and ultimately overall flange size. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. Although the intent of the “BX” design was face to face contact between hubs and flanges, the groove and gasket tolerances which were adopted are such that if the ring dimension is on the high side of the tolerance range and the groove dimension is on the low side of the tolerance - 44 -
Well Control Manual range, face to face contact may be very difficult to achieve. Without face to face contact vibration and external loads can cause plastic deformation of the ring, eventually resulting in leaks. The “BX” gasket frequently is manufactured with axial holes to insure pressure balance, since both the ID and OD of the gasket may contact the grooves. See Fig 56 & 57. Type BX
Fig 56 According to API the following marking should be visible on the ring gaskets OD: • Manufacturer’s name and mark • API monogram • Type and Number (Example BX 159) • Ring gasket material (Example S 304)
Fig 57 - 45 -
Well Control Manual API Type RX and BX ring-joint gaskets should be used for flanged and hub type blow-out preventer connections in that they are self-energized type gaskets. API type R ring gaskets are not a self-energized type gasket and are not recommended for use on well control equipment. RX gaskets are used with API type 6B flanges and 16B hubs and BX gaskets are used with type 6BX flanges and 16BX hubs. Detailed specifications for ringjoint gaskets are included in API Specification 6A and in API Specification 16A. Gasket materials, coatings and platings should be in accordance with API Specification 6A. Identification markings should be in accordance with API Specification 6A and API Specification 16A.
- 46 -
Well Control Manual Section 06 Choke manifold 06.01 General The choke manifold consists of high pressure pipe, fittings, flanges, valves, and manual and/or hydraulic operated adjustable chokes. This manifold may bleed off wellbore pressure at a controlled rate or may stop fluid flow from the wellbore completely, as required. See Fig 58.
Fig 58 06.02 Choke manifold – installation API RP53 8.2 Recommended practices for installation of choke manifolds for surface installations include: 1. Manifold equipment subject to well and/or pump pressure (normally upstream of and including the chokes) should have a working pressure equal to or greater than the rated working pressure of the ram BOPs in use. 2. For working pressures of 3000 psi and above, flanged, welded, clamped or other end connections in accordance with API 6A, should be employed on components subjected to well pressure. 3. The choke manifold should be placed in a readily accessible location, preferably outside the rig substructure. 4. Buffer tanks are sometimes installed downstream of the choke assemblies for the purpose of manifolding the bleed lines together. When buffer tanks are employed, provision should be made to isolate a failure or malfunction. - 47 -
Well Control Manual 5. All choke manifold valves should be full bore. Two valves are recommended between the BOP stack and the choke manifold for installations with rated working pressures of 5000 psi and above. One of these two valves should be remotely controlled. During operations, all valves should be fully opened or fully or fully closed. 6. A minimum of one remotely operated choke should be installed on 10000 psi, 15000 psi and 20000 psi rated working pressure manifolds. 7. Choke manifold configurations should allow for re-routing of flow (in the event of eroded, plugged, or malfunctioning parts) without interrupting flow control. 8. Considerations should be given to the low temperature properties of the materials used in installations to be exposed to unusually low temperatures and should be protected from freezing by heating, draining, filling with appropriate fluid, or other appropriate means 9. Pressure gauges suitable for operating pressure and drilling fluid service should be installed so that drill pipe and annulus pressures may be accurately monitored and readily observed at the station where well control operations are to be conducted.
06.03 Choke lines – installation API RP53 8.3 The choke line and manifold provide a means of applying back pressure on the formation while circulating out a formation fluid influx from the wellbore. The choke line (which connects the BOP stack to the choke manifold) and lines downstream of the choke should: 1. Be as straight as possible. 2. Be firmly anchored to prevent excessive whip or vibration. 3. Have a bore of sufficient size to prevent excessive erosion or fluid friction 4. Minimum recommended size for choke lines is 2” nominal diameter for 3K and 5K arrangements and 3” nominal diameter for IOK, 15K, and 20K arrangements. 5. Minimum recommended nominal inside diameter for lines downstream of the chokes should be equal to or greater than the nominal connection size of the chokes. 6. Lines downstream of the choke manifold are not normally required to contain pressure. 7. The bleed line (the line that bypasses the chokes) should be at least equal in diameter to the choke line. This line allows circulation of the well with the preventer closed while maintaining a minimum back pressure. It also permits high volume bleed off of well fluids to relieve casing pressure with the preventer closed. 06.04 Kill lines – installation Kill lines are an integral part of the surface equipment required for drilling well control. The kill line system provides a means of pumping into the wellbore when the normal method of circulating down through the kelly or drill pipe cannot be employed. The kill line connects the drilling fluid pumps to a side outlet on the BOP stack. The location of the kill line connection to the stack depends on the particular configuration of BOPs and spools employed. The connection should be below the ram type BOP most likely to be closed. On selective high-pressure, critical wells a remote kill line is commonly employed to permit use of an auxiliary high pressure pump if the rig pumps become inoperative or - 48 -
Well Control Manual inaccessible. This line normally is tied into the kill line near the blowout preventer stack and extended to a site suitable for location of a pump. This site should be selected to afford maximum safety and accessibility. Note: The same guidelines which govern the installation of choke manifolds and choke lines apply to kill line installations. 06.05 BOP – Side outlet valves Two valves are recommended between the BOP stack and the choke manifold for installations with rated working pressures of 5000 psi and above. One of these two valves should be remotely controlled. During operations, all valves should be either fully opened or fully closed. Of the two valves installed on the BOP side outlet the manual valves is installed as the first coming from the BOP and is always left in open position during normal drilling operation. See Fig 59.
Fig 59
Fig 60
The outside valve is a hydraulic operated valve, which can be operated from the Control Unit or from remote operation panels using 1500 psi operating pressure. The maximum operating pressure for the valves is normally 3000 psi. See Fig 60. 06.06 Chokes The purpose of the chokes in the overall BOP system is to control back pressure in the wellbore while circulating out a kick. The chokes might either be manual and/or hydraulic operated. A minimum of one remotely operated choke should be installed on 10000 psi, 15000 psi and 20000 psi rated working pressure manifolds. The choke control station, whether at the choke manifold or remote from the rig floor, should be as convenient as possible and should include all monitors necessary to furnish an overview of the well control situation. The ability to monitor and control from the same - 49 -
Well Control Manual location such items as standpipe pressure, casing pressure, pump strokes, etc., greatly increases well control efficiency. Rig air systems should be checked to assure their adequacy to provide the necessary pressure and volume requirements for controls and chokes. The remotely operated choke should be equipped with an emergency backup system such as a manual pump or nitrogen for use in the event rig air becomes unavailable. Hydraulic actuator
Position indicator
Fig 61 Cameron hydraulically actuated drilling choke are available in working pressures from 5.000 psi to 20.000 psi. See Fig 61. Cylindrical gate and large body cavity provide high flow capacity. Gate and seat are constructed of erosion resistant tungsten carbide and are reversible for double life. An air operated hydraulic pump in the control console ensures positive action gate movement. Hydraulic pressure of 300 psi applied to the actuator results in an opening or closing force of 21500 lbs at the gate.
Fig 62 Cameron manually actuated choke are available in working pressures from 5000 psi to 20000 psi See Fig 62. Thrust bearings in the actuator provide low torque handwheel operation. Upstream pressure has no thrust loading on the actuator; only downstream pressure affects the torque. Like the Auto choke, the cylindrical gate and large body cavity provide high flow capacity. Gate and seat are constructed of erosion resistant tungsten carbide and are reversible for double life. - 50 -
Well Control Manual The manually operated choke is normally used as a back up in case of problems with the hydraulically operated choke and during special well control operations such as stripping and volumetric well control. 06.07 Hydrates Hydrates are ice-like solids which are formed when gases are flowing in the presence of small quantities of water vapour. The temperatures at which hydrates can form may be well above the temperature at which pure ice would normally be formed, particularly at pressures above atmospheric. Hydrates form as small lattices of water with interstices which contain gases. The water forms an ice with molecules of gas locked into the frozen solid lattice. Those can build up into large pieces of solid hydrate at bends or restrictions, such as chokes or other valves. See Fig 63.
SOLID HYDRATE BUILD-UP
GAS + WATER (VAPOUR)
Fig 63 When hydrates form, the gas becomes "locked" into the solid at the local pressure. It is estimated that 1 cu ft of hydrate may hold the equivalent of 170 standard cubic feet compressed gas. This can be released when the hydrate is melted by the application of heat. Once hydrates have formed they may lead to complete plugging of chokes, fail-safe valves, choke lines and expansion points at entry to the mud gas separator. It is normal to try to prevent hydrates from forming by the injection of a suppressant at the upstream side of the choke or at the BOP, on the occasions when hydrate formation is likely. Prevention of hydrate formation is always regarded as the preferential action. Monoethylene glycol is the most common suppressant and it has a freezing point of 8.6°F (-13°C). It should be noted that it is the water-vapour associated with the gas which has to be inhibited, rather than the whole volume of water in the mud. It is common in HPHT wells to make provision for the injection of glycol hydrate suppressant at a point into the BOP upstream of the inner choke line valves and upstream of the choke at the choke manifold. This is done by a glycol injection pump which can deliver at a pressure up to the rated pressure of the choke manifold. The injection is started at a point when the gas influx is some depth below the BOP, such as 1500 to 2000 ft. The minimum injection rate is about 0.5 gpm but should be increased as necessary. During severe problems with hydrates methanol might be injected as it has a lower freezing point than glycol.
- 51 -
Well Control Manual 06.08 Mud/gas separator The mud/gas separator is the primary means of removing gas from the drilling fluid. There are several advantages to removing a large percentage of the gas from the drilling fluids before the drilling fluid flows to the degasser tank at the sand trap area and the pit room. See Fig 64. The primary reason is to reduce the quantity of gas which may percolate out of the drilling fluid in the mud pits and begin the process of regaining the proper density. As the atmospheric mud/gas separator is the primary type used, there are two types of atmospheric designs which are available. The vertical type and the horizontal type mud/gas separator. The horizontal type is gaining recognition within the industry because of it’s design advances and they are: a. b. c.
Larger exposed liquid surface area. Longer retention time of the fluid. The gas flow perpendicular to the direction of the fluid flow.
Fig 64 Due to space problems the vertical mud/gas separator is still the most common used in the industry. As the gas and drilling fluid is separated the gas flows up through the vent stack into the atmosphere. It can be shown that for an average 6” schedule 80, 5.85” ID pipe, extending 150 ft above the mud/gas separator, there is a back pressure reading in the range of 8 psi. The 8 psi back pressure is at the transition from the mud/gas separator to the vent line. Many variables must be taken into account in the calculations to this back pressure, such as the size and length of line in which the gas flowing, compressed isothermal flow, relative roughness, friction factors for the pipe and Reynolds numbers. However this 8 psi gauge pressure can be calculated and is fairly representative of actual situations. Due to the high friction loss in the vent line 10” to 12” lines are normally used.
- 52 -
Well Control Manual
The objective of the dip tube or Utube is to exert a hydrostatic head by column of fluid which will create a greater resistance to flow than the vent line going up the derrick. The design objective is to assure oneself that the path of least resistance is always through the derrick vent line. Considering that the dip tube or Utube is always full of fluid when flowing gas through the mud/gas separator, the worst case will be with water in the tube which is often mounted below the mud/gas separator. As shown on a typical vertical mud/gas separator drawing, where the dip tube goes into the trip tank, the trip tank frequently has a centrifugal hole fill pump installed at it’s base as well as a float and wireline extending to the rig floor and used as a trip tank indicator. See Fig 65 A U-tube does not have a level indicator installed, but a pressure gauge. Fig 65 Even that most mud gas separators have a design pressure of 150 psi the actual maximum operating pressure is below 10 psi depending of the height of the U-/Dip Tube and the fluid it contains. Eks:
Height of U-tube Fluid gradient Safety factor
15 feet 0.465 psi/ft 0.75
15 x 0.465 x 0.75 = 5.2 psi
- 53 -
Well Control Manual 06.09 Degasser Vacuum degassers are the secondary means of removing gas from gas cut drilling fluid. Two well-known types of vacuum degassers are the various WELLCO and the SWACO types. See Fig 66.
Fig 66 API RP53 16.10 A degasser may be used to remove entrained gas bubbles from the drilling fluid. These bubbles are too small to be removed by the atmospheric mud/gas separator. Most degassers make use of some degree of vacuum to assist in removing this entrained gas. The drilling fluid inlet line to the degasser should be placed close to the drilling fluid discharge line from the mud/gas separator to reduce the possibility of gas breaking out of the drilling fluid in the pit.
- 54 -
Well Control Manual Section 07
Auxiliary equipment
07.01 Kelly valves A kelly valve is a terminology which originates from the times where drilling was done using a kelly. An upper kelly valve was installed between the swivel and the Kelly and a lower kelly valve was installed immediately below the kelly. See Fig 67/68. The term “Kelly Valve” has been adoptet and is often used as synonym for a high pressure ball valve.
Fig 67
Fig 68
07.02 Top drive valves There are two ball valves (sometimes referred to as kelly valves or kelly cocks) located on top drive equipment. The upper valve is air or hydraulically operated and controlled at the driller's console. The lower valve is a standard ball kelly valve (sometimes referred to as a safety valve) and is manually operated, usually by means of a large hexagonal wrench.Generally, if it becomes necessary to prevent or stop flow up the drill pipe during tripping operations, a separate drill pipe valve should be used rather than either of the top drive valves. However, flow up the drill pipe might prevent stabbing this valve. In that case, the top drive with its valves can be used, keeping in mind the following cautions: 1. Once the top drive's manual valve is installed, closed, and the top drive disconnected, a crossover may be required to install an inside BOP on top of the manual valve. 2. Most top drive manual valves cannot be stripped into 7 5/8 inch or smaller casing. 3. Once the top drive's manual valve is disconnected from the top drive, another valve or spacer must be installed to take its place. See Fig 69. Fig 69 - 55 -
Well Control Manual 07.03 Drillpipe safety valve (DPSV) API RP53 16.2 A spare drill pipe safety valve should be readily available (i.e., stored in open position with wrench accessible) on the rig floor at all times. This valve should be accessible including cross-over’s to install into any drill string member in use. The outside diameter of the drill pipe safety valve should be suitable for running into the hole. See Fig 70.
Fig 70
07.04
Inside blowout preventer (IBOP)
API RP53 16.3 An inside blowout preventer, drill pipe float valve, or drop-in check valve should be available for use when stripping the drill string into or out of the hole. The valve(s), sub(s), or profile nipple should be equipped to screw into any drill string member in use. See Fig 71. No direct read-out of SIDPP can be obtained. Fig 71 1. 2. 3. 4.
Release Tool Body Valve Release Rod Valve Spring Valve Seat
07.05 Drillstring float valve API RP53 16.5 A float valve is placed in the drill string to prevent upward flow of fluid or gas inside the drill string. The float valve is a special type of back pressure or check valve. A float valve in good working order will prohibit backflow and a potential blowout through the drill string. The drill string float valve is usually placed in the lowermost portion of the drill string, between two drill collars or between the drill bit and drill collar. Since the float valve prevents the drill string from being filled with fluid through the bit as it is run into the hole, - 56 -
Well Control Manual the drill string must be filled from the top at the drill floor, to prevent collapse of the drill pipe. Tripping time will be increased and excess surge pressure created when running with float valves. No direct read-out of SIDPP can be obtained. There are two types of float valves: 1. The spring-loaded ball, or dart, and seat float valve offers the advantage of an instantaneous and positive shut off backflow through the drill string. See Fig 72. 2. The flapper-type float valve offers the advantage of having an opening through the valve that is approximately the same inside diameter as that of the tool joint. This valve will permit the passage of balls, or go-devils, which may be required for operation of tools inside the drill string below the float valve. See Fig 73.
Fig 72
Fig 73
07.06 Tester plug A test plug is used to test BOP’s and associated well control equipment without exerting pressure on well head and casing. When using a test plug, well head side outlet valves should be opened below the test plug, to avoid the risk of damage to casing and/or formations. See Fig 74.
Fig 74 - 57 -
Well Control Manual 07.07 Cup type tester plug A cup type tester is used to test well head and well head side outlet valves without exerting pressure on casing and formation. Cup type tester should be run on open ended drill pipe to ensure no possibility of pressure buildup below the cup type test tool. See Fig 75.
Fig 75 07.08 Triptank API RP53 15.6 A trip tank is a low-volume, [100 barrels or less] calibrated tank that can be isolated from the remainder of the surface drilling fluid system and used to accurately monitor the amount of fluid going into or coming from the well. A trip tank may be of any shape provided the capability exists for reading the volume contained in the tank at any liquid level. The readout may be direct or remote, preferably both. The size and configuration of the tank should be such that volume changes on the order of one-half barrel can be easily detected by the readout arrangement. Tanks containing two compartments with monitoring arrangements in each compartment are preferred as this facilitates removing or adding drilling fluid without interrupting rig operations. Other uses of the trip tank include measuring drilling fluid or water volume into the annulus when returns are lost, monitoring the hole while logging, or following a cement job, calibrating drilling fluid pumps, etc. The trip tank is also used to measure the volume of drilling fluid bled from or pumped into the well as pipe is stripped into or out of the well. 07.09 Pit volume measuring devices API RP53 15.7 Automatic pit volume measuring devices are available which transmit a pneumatic or electric signal from sensors on the drilling fluid pits to recorders and signalling devices on the rig floor. These are valuable in detecting fluid gain or loss. 07.10 Flow rate sensor API RP53 15.8 A flow rate sensor mounted in the flow line is recommended for early detection of formation fluid entering the wellbore or a loss of returns. - 58 -
Well Control Manual Section 08 Subsea BOP stack components The purposes of the subsea BOP stack used to control pressures in wells are essentially the same as for those with surface BOP stacks. There are, however, several additional complications, which must be taken into consideration. The purpose of this lecture is to describe some of those issues and show some typical examples of equipment, which is required to meet the additional requirements.
Fig 76
The illustration above Fig. 76 is an example of a typical subsea BOP stack.
- 59 -
Well Control Manual The BOP is designed to allow for disconnecting at the upper part of the BOP under a variety of circumstances while maintaining the well closed in. The parts of the BOP stack that remains in place on the wellhead is called the Blowout Preventer and the parts above which can be disconnected is the Lower Marine Riser Package or LMRP. Some of the additional special equipment on a subsea BOP stack includes: • Hydraulic connector between the wellhead and the BOP. • Remote operated ram locking system or integral ram locking systems. • Hydraulic operated choke line and hydraulic kill line valves for the BOP side outlets. • Riser choke line and riser kill line of fixed pipe. • Hydraulic connector between the BOP and the LMRP. • An additional annular BOP as a part of the LMRP. • Flex joint or a ball joint. • Marine drilling riser with attached lines on the outside (kill, choke, booster, hydraulic). • Riser auto fill valve (Riser fill-up valve). • Telescopic joint. • Riser tensioning system. • Hydraulic BOP Control System to function the subsea BOP. In the following some of the above equipment and systems will be described.
08.01 Model 70 Collet Connector (Cameron Iron Works)
See Fig 77. The Cameron Model 70 Collet Connector forms a tight seal while withstanding the bending stresses and separating forces caused by well pressure, riser tension and vessel motion. Manual override is possible. The metalto-metal sealing AX ring gasket is standard.
Fig 77
- 60 -
Well Control Manual The connector is functioned by a set of hydraulic cylinders, Fig 78a and 78b. These provide unlocking force that is 80% higher than locking force. The connector locks to the mating hub on the well head or on the BOP via pivoted locking segments/fingers, (called collet fingers). The position of the locking segments is controlled by the position of the surrounding cam-ring. The position of the cam-ring is again controlled by a number of connected hydraulic jacks mounted on the outside diameter of the cam-ring. When the cam-ring is placed in the uppermost position the collet fingers will force the locking segments to take the shape of a funnel, which help to guide the connector into position when landing the BOP on the wellhead.
Fig 78a Fig 78b Data: Bore Sizes: Rated Working Pressure: Bending at 10K psi/1000K lb: Preload: Shoulder Angle: Max Release Angle: Swallow: Weight: Hydraulic Operating Pressure: Hydraulic Vol. 18-3/4” 10K RWP:
13-5/8 in through 21-1/4 in 2000 psi through 15000 psi 1.85 million ftxlb 1.4 million ftxlb 25°/25° (Housing/Connector) 30° 13-3/8 in 16600 lb (7530 kg) studded top 1500 psi to 3000 psi Open 6.27 gal, Close 4.97 gal
- 61 -
Well Control Manual 08.02 Model HC Collet Connector (Cameron Iron Works) The HC Collet Connector (Fig. 79a and 79b) name, is related to High Capacity. The HC Collet Connector is similar to the popular Model 70 Connector but is designed to provide greater preload forces to withstand higher separating forces. The features include an annular hydraulic piston in the cylinder, which is an integral part of the housing. This provides substantially higher clamping preload than the Model 70. Secondary unlock is available. The Connector locks to the mating hub via pivoted locking segments/fingers, which form a funnel to guide the connector into position. The metal-to-metal sealing AX ring gasket is standard. The greater clamping force is obtained due to the segment and hub geometry and the large actuating piston area.
Fig. 79a
Fig. 79b Data: Bore Sizes: Rated Working Pressure: Bending at 15k psi/1000 k lb: Preload: Shoulder Angle: Max Release Angle: Swallow: Weight: Hydraulic Operating Pressure: Hydraulic Vol. 18-3/4” 15k RWP:
13-5/8 in through 21-1/4 in 5000 psi through 15000 psi 1.85 million ft x lb 7 million ft x lb 25°/25° (Housing/Connector) 30° 12-½ in (32 cm) 23100 lb studded top 1500 psi to 3000 psi Open 25 gal ,Close 20 gal
- 62 -
Well Control Manual 08.03 Hydraulic operated choke/kill line valves
Cameron MCS Gate Valves (Fig. 80) are compact valves suited for the requirement of subsea choke and kill lines in water depths up to 6000 ft. Balanced stem prevents fluid displacement and also prevents opening the valve when line pressure is less than sea hydrostatic pressure. Bi-directional sealing allows valves to be spaced closely without liquid lock. Metal-to-metal sealing between gate an seats is utilised. Rated Working Pressure 10000 psi and 15000 psi Hydraulic Operating Pressure 1500 psi to 3000 psi One mean (hydraulic pressure) opens the valve. The valve opens when hydraulic Fig. 80 pressure is supplied from the SPM valve in the pod to the top of the actuator. In the actuator the piston is pushing the gate into open position. Three different means close the valve: When closing the valve the hydraulic opening pressure is vented from the top of the piston in the actuator. This happens through the open-SPM valve in the pod, which is venting. Simultaneously the hydraulic closing pressure is supplied to displace the piston in the actuator into the valve’s closed position. Further additional forces support the hydraulic closing pressure. One is the spring force. The other is the hydrostatic sea water pressure which is exposed to the end of the tail rod connected to the gate. In earlier control system layouts, the only two means of closing the valve was the spring force and the hydraulic force generated by the ambient water column working on the tailrod. This way of operation was called “Failsafe”. This synonym has stuck to the choke and kill valves, although incidents has proven that valves are NOT failsafe, why the valves today are forced closed by mean of hydraulic power supplied by the BOP control system.
- 63 -
Well Control Manual Section 09
Drilling riser and related components
The riser is used as an extension of the well bore from the BOP stack situated on the seabed to the floating drilling unit (Fig 81). It is used for lowering and raising the BOP to and from the wellhead. To conduit drilling fluid returns to the surface and to guide drilling tools down to the seabed. Additional steel pipelines are attached to the circumference of the marine riser. These lines are the riser choke and kill lines, the booster line. Further a forth line can be include a Conduit line – supplying the BOP with hydraulic fluid. Above water level in the moonpool area those lines connect to the fixed pipework on the rig by means of flexible high-pressure hose loops. A booster line is used to transfer drilling fluid from the mud pumps down to the riser adapter where the line enters the marine riser. The supplied additional volume of drilling fluid generates a higher annular fluid velocity, which improves the cuttings transport up through the riser.
Fig. 81 - 64 -
Well Control Manual 09.01 Flex/Ball joint The position of the flex joint (Fig. 82) is just above the upper annular BOP on the LMRP. The flexjoint makes it possible for the marine riser above the flexjoint to deflect from vertical. This unit can accommodate a deflection angle of up to 20 degrees between the BOP and the marine riser above. The design uses two elestomeric elements. The internal seal element isolates internal fluid and pressure from the bearing element, which supports tension and bending loads
Fig. 82 The Ball joint (Vetco Gray, Fig. 83) was/is the predecessor for the flex joint. It can still be found on older rig in operation. If in operation the Ball joint will be installed just below the diverter system under the rig floor. Like the Flex joint the ball joint makes it possible for the riser below the ball joint to deflect from vertical. This unit can accommodate a deflection angle of up to 10 degrees between the diverter and the marine riser below it.
Fig. 83
A contributing factor why the ball joint is loosing terrain to the Flex joint is because of the necessity of a pressure balancing system, which helps extend the seal lifetime and minimises frictional resistance to bending.
- 65 -
Well Control Manual 09.02 Telescopic joint The telescopic joint (Fig 84) allows for rig heave and offset of the vessel. It has maximum rated riser tensile load capacity in locked position. There is a hydraulic latch available for release of inner and outer barrels. The unit has dual split/solid packer elements. Available with either a fixed or a rotating integral/non-integral tensioner ring. The choke line and kill lines are installed on the telescopic joint outer barrel. High pressure flexible lines and terminal fittings connects to the rig floor manifold piping.
Fig. 84 - 66 -
Well Control Manual 09.03 Riser fill-up valve The riser fill-up valve (Fig 85) is installed to minimise/prevent the riser system from collapsing in the event the drilling fluid level drops uncontrolled. Level drop being due to intentional drive-off, loss of circulation or accidental disconnection of the LMRP. The theory behind the valve is that the fill-up valve opens automatically when the difference in pressure between inside and outside the riser is 225 - 325 psi. When the valve opens, seawater rapidly fills the riser to equalise the pressure and prevent riser collapse. The valve can also be operated manually, when it receives the hydraulic open pressure signal from the surface. The valve closes again when it receives the disable/reset signal from the surface. Typical response time for the riser fill-up valve is five seconds. Fig. 85 09.04 Mechanical riser coupling Fig 86 is a MR-6D coupling, which is a high strength, rapid make up and release connector with a modified conical pin profile for easy stabbing. Riser joints are picked up with the mechanically operated mating riser handling tool using shackles and slings attached to holes in the support plates. Install the box over the pin and rotate the actuating screws clockwise, driving double-tooth locking dogs into the mating pin profile. This causes the nose of the pin connector to preload against the mating shoulder in the box. When the dogs are fully engaged, the lock plates automatically spring back to prevent the actuating screws from backing out due to vibrations. In the fully made-up position, the O-ring seal on the ID of the box is the primary seal, and the trash seal below the locking dog prevent foreign material from entering the coupling. Fig. 86
- 67 -
Well Control Manual Section 10
Hydraulic BOP control system components (Subsea)
Component overview
Fig. 87
- 68 -
Well Control Manual
As an opening to the subject “subsea BOP control system” Fig 87 is illustrating the main components used. The following items should be recognised. Drillers control panel Auxillary Remote Control Panel Hydraulic power unit Accumulator bank (surface) Stack mounted accumulators (subsea) Subsea hose bundle storage reels Hose bundles Control pods In Index 4 the components that compose a normal “surface BOP control system” are exhaustively described. It should be highlighted that one of the important differences between a surface and a subsea BOP control system, is that the hydraulic subsea BOP control system is divided into two separate systems. There are a “active system” and a “redundant system”. The driller is using the one system, which he selects to be the “active system”. In order to distinguish the systems from each other, an unwritten standard is used on many units. The standard is a colour coding system, whereby the pods are painted in yellow and blue colours. Some of the distinct components relating to the subsea BOP control system, will be illustrated and explained in more detail in the following. As previous mentioned attention is drawn to Index 4 for more detailed information. 10.01 Subsea hose bundle storage reels Fig. 88
The two hose reels (yellow and blue) are equipped with air-driven motors with forward and reverse controls to drive the drum. The drum shaft is supported in heavy duty bearings and it has a manual friction brake, and locking pins. (Fig. 88)
- 69 -
Well Control Manual
10.02 Manifolds on the Subsea hose bundle storage reels On the hose bundle storage reel there is a manifold located (Fig. 89). Reason for this manifold is to have full operational charge of a few vital operations when running the BOP. The operations (not limiting to) is the riser and well head connectors as well as the connectors locking the pods.
Fig. 89
10.03 Subsea hose (Umbilical) A typical subsea hose bundle (Fig. 90) consists of the following: 1. Power (or control) fluid supply hose 1 in ID. Power fluid is the fluid the moves the piston from open to close, ie. the fluid that does the work. The power fluid pressure to the Active pod is 3000 psi on surface. For the Redundant pod the control fluid pressure is vented. 2. Pilot fluid hoses 3/16 in ID. The pilot system is signal conveyer from surface to subsea and back to surface. Two pilot hoses are used for operating the subsea mounted regulators, further two pilot hoses are dedicated to confirm the regulator settings in the subsea pods. The remaining pilot hoses are used for operating the SPM valves. The pilot supply pressure is either 3000 psi on surface, or the pressure is vented. Fig. 90
3. Outer protective jacket
- 70 -
Well Control Manual
10.04 Subsea control pods (blue and yellow)
Fig. 91
Each one of the two identical control pods (Fig. 91) accommodates SPM valves for all the individual hydraulic functions on the BOP. Further two hydraulic regulators, one manifold regulator and one annular regulator are installed in each pod. All SPM and regulating functions are piped and manifolded in the control pod with a tapered male sealing surface on the bottom. The male is mechanically indexed and compressed into a “lower” spring mounted female that is bolted to the main portion of the stack. Special seals are used on all tapered surfaces to maintain high-pressure flow integrity. Functions located above the riser connector exit through radial port outlets on the mounting flange of the upper female of each pod and to individual shuttle valves that isolate and separate yellow and blue pods. Flow exits at the bottom of the lower female, for functions below riser connector on the stack, goes directly to the shuttle valve. Access for some straight through functions, supplied only from the surface manifold unit, is provided for each pod. Either pod can be retrieved without disrupting drilling operations should it be necessary. The last is one of the features of the “Redundancy principle”
- 71 -
Well Control Manual
10.05 Shuttle valves Shuttle valves (Fig. 92) are usually mounted directly on function ports or as pilot operated check valves. As previously mentioned, the shuttle valves isolate one pod from the other so both are independent from one another. A shuttle valve is a “slave” and is operated/manipulated by the fluid/pressure that runs through the valve. Description of ports: Port 1 Discharge Port 2/3 Inlet
Fig. 92
- 72 -
Well Control Manual
- 73 -
Maersk Training A/S Dyrekredsen 4 Rantzausminde DK - 5700 Svendborg Denmark
[email protected] www.maersktraining.com
Tel Fax
+45 70 263 283 +45 70 263 284
