Maersk Training Centre A/S
1.
Well Control Equipment
2.
Extracts from API
3.
Well Control Principles & Procedures
4.
Spare
5.
Spare
6.
Various
MTC
WELL CONTROL MANUAL
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WELL CONTROL MANUAL
Table of content: Chapter 1 Chapter 2 Chapter 3 Chapter 4 Chapter 5 Chapter 6
Well Control Equipment............................................. Page 15 Extract from API..........................................................Page 83 Well Control Principles & Procedures...................... Page 113 Spare............................................................................ Page 249 Spare............................................................................ Page 251 Various......................................................................... Page 253
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Manual standard clause This manual is the property of Maersk Training Centre A/S (hereinafter “MTC A/S) and is only for the use of Course participants conducting courses at MTC A/S. This manual shall not affect the legal relationship or liability of MTC A/S with or to any third party and neither shall such third party be entitled to reply upon it. MTC A/S shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of MTC A/S. Copyright MTC 2004-02-04 Prepared by: JOA & NLN Modified & printed: 01/01/2004 Modified by: Maersk Training Centre Internal reference: M:\DRILLING IWCF Surface\Course material\Manual OPS\Class room Manual\040101_Update Project\040101_Updated Manual01.doc
Contact MTC Maersk Training Centre A/S Dyrekredsen 4 Rantzausminde 5700 Svendborg Denmark Phone: Telefax: Telex: E-mail: Homepage:
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Managing Director: Claus Bihl
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Index & Abbreviations:
Page 07
Chapter 1:
Page 15
Well Control Equipment
Section 01 Well control barrier 01.01 Primary well control barrier 02.01 Secondary well control barrier
Page 17
Section 02 BOP configuration 01.02 Bop stack arrangements 02.02 Stack components codes 03.02 Drilling spool
Page 18
Section 03 Diverter systems 01.03 Purpose of diverter system 02.03 Diverter equipment 03.03 Guidelines for diverting with string on bottom 04.03 Guidelines for diverting with string off bottom 05.03 Rotating head 06.03 Diverter control system
Page 21
Section 04 Annular preventer 01.04 General 02.04 Testing 03.04 Pressure test frequency 04.04 Response time 05.04 Hydril annular preventers 06.04 Shaffer annular preventers 07.04 Cameron annular preventers 08.04 Packing unit
Page 27
Section 05 Cameron ram preventers 01.05 General 02.05 Testing 03.05 Pressure test frequency 04.05 Response time 05.05 Cameron ram preventer 06.05 Cameron ram assembly 07.05 Operating ratio 08.05 BOP and side outlet connections 09.05 API type flanges 10.05 Ring joint gaskets and grooves
Page 37
Section 06 Choke manifolds 01.06 General 02.06 Choke Manifold - Installation 03.06 Choke Lines - Installation 04.06 Kill Lines - Installation 05.06 BOP side outlet valves 06.06 Chokes 07.06 Hydrates
Page 55
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MTC 08.06 09.06
WELL CONTROL MANUAL Mud/gas separator Vacuum degasser
Section 07 Control System 01.07 General 02.07 Response time 03.07 Storage equipment 04.07 Pump requirements 05.07 Accumulator cylinders and manifolds 06.07 Hydraulic control manifold 07.07 Schematic of BOP control system 08.07 Fluid flow diagramme 09.07 Remote control panel 10.07 Accumulator volumetric requirements 11.07 Accumulator volumetric capacity
Page 63
Section 08
Page 78
Chapter 2:
Auxiliary equipment 01.08 Kelly valves 02.08 Top drive valves 03.08 Drillpipe safety valve 04.08 Inside blowout preventer 05.08 Drillstring float valve 06.08 Hanger type test plug 07.08 Cup type test plug 08.08 Trip tank 09.08 Pit volume measuring devices 10.08 Flow rate sensor
Extracts from API
Page 83
Section 01
Diverter systems - purpose Installation and equipment requirements Air, aerated fluid or gas drilling operations
Page 85
Section 02
Blowout preventer equipment selection
Page 86
Section 03
Classification of blowout preventers Stack component codes Drilling spools
Page 87
Section 04
BOP operational characteristics tests General Ram-type BOP Applicable operating characteristics test Sealing characteristics test Fatigue test Stripping life test Shear ram test Hang-off test
Page 88
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Ram access test Annular-type BOP Sealing characteristics test A. Constant wellbore pressure test B. Constant closing pressure test C. Full closure pressure test Fatigue test Packer access test Stripping life test Operating manual requirements Hydrostatic proof testing Procedure Test pressures Acceptance Section 05
BOP closing ratio (ram BOP) BOP opening ratio (ram BOP) Ram locks
Page 94
Section 06
Periodic field testing Blowout preventer operating test Blowout preventer hydraulic tests Auxiliary equipment testing Recommended pressure test practices
Page 94
Section 07
Choke manifolds – purpose Design considerations Installation guidelines Choke control station Maintenance
Page 100
Section 08
Kill lines Installation guidelines
Page 103
Section 09
Control systems for surface mounted BOP stacks General Response time Hydraulic fluid and storage equipment Pump requirements Accumulator bottles and manifolds Accumulator types and interconnection of accumulator banks Precharging accumulators Accumulator volumetric requirements Volumetric capacity calculations Hydraulic control manifold Hydraulic control manifold annular BOP circuit Hydraulic manifold circuit for common pressure functions Hydraulic control manifold valves
Page 104
Section 10
Remote control panels Optional remote control methods
Page 109
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Electro-pneumatic remote control Requirements for BOP control system valves, Fittings, lines and manifold Conformity of piping systems Electrical power supplies Section 11
Chapter 3: Section 01
Closing-in kicks Soft close-in procedure Hard close-in procedure
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Well Control Training Manual
Page 113
Pressure in the earth crust 01.01 Sedimentation 02.01 Compression 03.01 Pressure 04.01 Pressure in fluids 05.01 Pressure gradient 06.01 Abnormal/subnormal pressure
Page 115
Section 02 Pressure balance in the well bore 01.02 Pressure balance 02.02 Overbalance and underbalance 03.02 Lost circulation 04.02 Rate of penetration versus overbalance 05.02 Drilling break 06.02 Necessary overbalance 07.02 Trip margin 08.02 Riser margin 09.02 Relationship 10.02 Equivalent drilling fluid density
Page 127
Section 03 Dynamic pressure regime when circulating 01.03 Circulation of drilling fluid 02.03 Dynamic pressure in the well bore
Page 135
Section 04 Consideration with a closed in well 01.04 Closed in well 02.04 U-tube
Page 140
Section 05 Properties of gasses and gas laws 01.05 Drilling with underbalance 02.05 Properties of gas and gas laws 03.05 Expansion of gas 04.05 Formation strength 05.05 Leak-off test 06.05 Maximum allowable annular surface pressure
Page 143
Section 06 Drilling fluid volume and capacities 01.06 Calculating drilling fluid volume – capacities
Page 150
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MTC 02.06 03.06 04.06 05.06
WELL CONTROL MANUAL Drilling fluid volume and capacities from tables Surface to bit strokes & bit to surface strokes Use of barite to increase drilling fluid volume Volume increase due to barite addition
Section 07 Wellbore kicks Page 158 01.07 Kick occurrences 02.07 Warning signals 03.07 Warning signals while drilling 04.07 Warning signals while tripping or making connection 05.07 Procedure for shutting in the well 06.07 Pressure after shut in Section 08 Circulating a kick out of the well bore Page 174 01.08 General points 02.08 Circulating out an influx using driller’s method 03.08 Wait and weight method or engineer’s method 04.08 The concurrent method 05.08 Advantages and disadvantages of the three methods 06.08 Pressure control schemes Section 09
Calculations of density and pressure gradient of an influx 01.09 General points 02.09 Example
Page 199
Section 10 Lost circulation 01.10 General 02.10 Causes of lost circulation 03.10 Well control with partly lost circulation 04.10 Well control with total lost circulation
Page 202
Section 11 Volumetric well control and other 01.11 General 02.11 Volumetric method – specification required 03.11 Volumetric method – handling 04.11 Lubrication technique 05.11 Volumetric method – example 06.11 Low choke method – dynamic Kill 07.11 Bullheading
Page 207
Section 12 Kick with bit off bottom Page 218 01.12 Introduction 02.12 Stripping 03.12 Closing procedures 04.12 Rig layout for combined stripping and volumetric method 05.12 Procedure 06.12 Snubbing Section 13 Gas cut drilling fluid 01.13 General 02.13 Causes of gas cut drilling fluid Index 1 Page 11
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MTC 03.13 04.13
WELL CONTROL MANUAL Gas kicks in oil based mud Influx volume
Section 14 Deviated and Horizontal well control 01.14 Introduction 02.14 Complications 03.14 Horizontal well control example 04.14 Wait and weight method 05.14 Driller’s Method 06.14 Horizontal well kill method
Page 230
Section 15 Pulling Pipe 01.15 02.15 03.15 04.15 05.15
Page 242 Introduction Pumping slug Inadequate hole filling Hole not taking correct amount of fluid Hole not giving correct amount of fluid
Chapter 4:
Spare
Page 249
Chapter 5:
Spare
Page 251
Chapter 6:
Various
Page 253
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Abbreviations: A A API Atm BHA BHP BOP C Cap CSO DC DP DPSV EDC EFD EOB ºF FCP Ft G Gal GMD GMR GPM K HCR HPHT H2S IBOP ICP ID KMW KOP lb lb/ft LOT FIT MAASP MD MGS MTC MW MWF NDE NDT OBM OD OH OMW
Annular preventer Area American Petroleum Institute Atmosphere Bottom hole assembly Bottom hole pressure Blow out preventer Hydraulic connector Capacity Complete shut off Drill collar Drill pipe Drill pipe safety valve Equivalent circulating density Equivalent formation density End of build Fahrenheit Final circulating pressure Feet Pressure gradient psi/ft Gallons Gas migration distance Gas migration rate Gallons per minute Kilo=1000 units High closing ratio High pressure/high temperature Hydrogen sulfide Gas Inside blow-out preventer Initial circulating pressure Internal diameter Kill mud weight Kick off point Pound Pounds per feet Leak off test Formation integrity test Maximum allowable annular surface pressure Measured depth Mud/Gas Separator Maersk Training Centre Mud weight Final mud weight Non destructive examination Non destructive testing Oil base mud Outside diameter Open hole Original mud weight Index 1 Page 13
MTC P PA Pc PDP Pf Ph PL PL PPG PSI PPM PWD R Rd ROP RPM Rt RP S SF SICP SIDPP SPM SX SCF T TVD V WBM WOB
WELL CONTROL MANUAL Pressure Pressure annulus Pressure circulating (dynamic) Pressure drill pipe Pressure formation (pore pressure) Pressure hydrostatic Pressure loss Reduced rate circulating pressure Loss (SCR, RRCP) Pound per gallon Pound per inch square Part per million Pressure while drilling Ram preventer (single) Ram preventer (double) Rate of penetration Rotation per minute Ram preventer (tripple) Recommended practice Drilling spool Safety factor Shut in casing pressure Shut in drill pipe pressure Strokes per minute Sacks Standard cubic feet Temperature True vertical depth Volume Water base mud Weight on bit
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Maersk Training Centre Drilling Section Chapter 1
Well Control Equipment
Copyright © Maersk Training Centre a/s. All rights reserved. No part of this publication may be reproduced, stored in or introduced into a retrieval system, or transmitted, in any form, or by any means (electronic, mechanical, photocopying, recording or otherwise) without the prior written permission of Maersk Training Centre a/s.
The basic of this well control manual is found according to recommendation in API 16E and API²RP 53. Well control equipment and control system according to API³RP 53 and API (spec) 16a.
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MTC Section 01
WELL CONTROL MANUAL Well control barriers.
01.01 Primary well control barrier. During normal drilling operation it will always be the hydrostatic pressure of the drilling fluid that creates the primary barrier to avoid any flow of formation fluid into the well bore. If for any reason the primary barrier is lost the well control equipment together with the drilling fluid in the well bore will be the secondary barrier. This will allow us to re-establish the primary barrier on a safe and efficient way. 01.02 Secondary well control barrier. The well control equipment must be able to close and secure the well under all circumstances. Further to that circulation of heavy drilling fluid into the well bore and formation fluid out of the well bore under controlled manner must be possible. The well control equipment should be able to close on open hole(without tubular), around BHA and other tubular used in the drilling operation. It should also be able to cut the drill string or lighter tubular and seal the well bore and allow the drill string to be hanged off on the pipe rams or stripped into the well bore. To avoid single components to create total failure of the system a contingency (back up) function should be build into the system. All well control equipment must be maintained, function- and pressure tested according to company policy and procedures to assured correct function and integrity when required. With the well closed in and the drill string in the well bore, formation pressure can be obtained through the drill string by adding SIDPP with pressure hydrostatic. To secure the drill string and obtain integrity following barriers can be used: DPSV (drill pipe safety valve) DIBPV (drop In back pressure valve (dart, landing sub and retrieving tool) IBOP (inside blow-out preventer) Fast shut off coupling with DPSV Check valves (Drill pipe floats) To secure the annulus and obtain integrity following barriers can be used: Annular Preventer Ram Preventer Shear/Blind Ram During normal drilling operation two barriers must always be in place where the hydrostatic head of the drilling fluid is one and the BOP stack the other.
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MTC Section 02
WELL CONTROL MANUAL BOP configuration
02.01 Bop stack arrangements Example arrangements for BOP equipment are based on rated working pressures. Example stack arrangements shown in Figures 1 and 2 should prove adequate in normal environments, for rated working pressures of 2K, 3K, 5K,IOK, 15K, and 20K. Arrangements other than those illustrated may be equally adequate in meeting well requirements and promoting safety and efficiency. Rated working pressure 2K 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.
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RT =
Triple ram type BOP with three sets of rams, positioned in accordance with operator's choice.
S=
Drilling spool with side outlet connection for choke and kill lines.
C=
Hydraulic well head connector with a minimum rated working pressure equal to the BOP stack rated working pressure.
K=
1000 psi rated working pressure.
BOP components are typically described upward from the uppermost piece of permanent wellhead equipment, or from the bottom of the BOP stack. A BOP stack may be fully 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: a. 3K and 5K arrangements should have two side outlets no smaller than a 2-inch (5.08 cm) nominal diameter and be flanged, studded, or hubbed. IOK, 15K, and 20K arrangements should have two side outlets, one 3-inch (7.62 cm) and one 2-inch (5.08 cm) nominal diameter as a minimum, and be flanged, studded, or hubbed. Index 1 Page 19
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b.
Have a vertical bore diameter the same internal diameter as the mating BOPs and at least equal to the maximum bore of the uppermost casing/tubing head.
c.
Have a rated working pressure equal to the rated working pressure of the installed ram BOP.
Note: For drilling operations, wellhead outlets should not be employed for choke- or kill lines.
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MTC Section 03
WELL CONTROL MANUAL Diverter systems
Fig 04
03.01 Purpose of diverter system (API RP 53 4.1) A diverter system is often used during top-hole drilling. A diverter is not designed to shut in or halt flow, but rather permits routing of the flow away from the rig. The diverter is used to protect the personnel and equipment by re-routing the flow of shallow gas and wellbore fluids emanating from the well to a remote vent line (see Fig 04). The system deals with the potentially hazardous flows that can be experienced prior to setting the casing string on which the BOP stack and choke manifold will be installed. The system is designed to packoff around the Kelly, drill string, or casing to divert flow in a safe direction. Diverters having annular packing units can also close on wire line and open hole. Valves in the system direct the well flow when the diverter is actuated. The function of the valves may be integral to the diverter unit. 03.02 Diverter equipment (API RP 53 4.2.2) The diverter system consists of a low pressure diverter or an annular preventer of sufficient internal bore to pass the bit required for subsequent drilling. Vent line(s) of adequate size [6 inches (15.24 cm) or larger] are attached to outlets below the diverter and extended to a location(s) sufficiently distant from the well to permit safe venting. Conventional annular BOPs (see Fig 05), insert-type diverters (see Fig 06), or rotating heads (see Fig 10) can be used as diverters. The rated working pressure of the diverter and vent line(s) are designed and sized to permit diverting of well bore fluids while minimizing wellbore back pressure. Vent lines are typically 10 inches (25.4 cm) or larger ID for offshore and 6 inches (15.24 cm) or larger ID for onshore operations.
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Fig 06
Fig 05
If the diverter system incorporates a valve(s) on the vent line(s), (refer to API Recommended practice 64), this valve(s) should be full opening and full bore (have at least the same opening as the line in which they are installed). The system should be hydraulically controlled such that at least one vent line valve is in the open position before the diverter packer closes. Diverter testing (API RP 53 4.2.5) The diverter and all valves should be function tested when installed and at appropriate times during operations to determine that the system will function properly. (See also API RP 53 17.4) CAUTION: Fluid should be pumped through the diverter and each diverter vent line at appropriate times during operations to ascertain the line(s) is not plugged. Inspection and clean-out ports should be provided at all low points in the system. Drains and/or heat tracings may he required in colder climates. The hydraulic supply pressure to the diverter control panel is routed directly from the hydraulic control unit with 3.000 psi. Older types of diverter systems have separate operating handles for each components as seen in Fig 07, but most have now been changed so the valves is integral to the diverter unit.
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Fig 07
To operate the system in Fig 07 the following sequence must be used to avoid shutting in or halt the flow from the well bore: a. b. c.
Open B or C depending on wind direction Close E Close A
In the Hydril model FS21-500 the diverter is integral to an annular preventer and is only equipped with one diverter line witch is diverted into two lines by a DS12-500 Flow Selector valve that makes it possible to divert fluid and gas to either side of the rig depending of wind direction or to both side at the same time. See Fig 08 and 08a.
Fig 08a
Fig 08
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03.03 Guidelines for diverting with string on bottom 1.
Route returns to downwind vent line and close diverter
2.
Pump at maximum rate and switch to kill fluid without stopping the pumps. If no kill fluid available, use sea water. (Do not stop the pumps)
3.
If the diverter system fails before control of the well is regained or broaching to surface occurs, evacuate all personnel and leave the mud pumps running on sea water at maximum pump rate.
03.04 Guidelines for diverting with string off bottom If it becomes necessary to divert gas, water and/or sand debris, route returns to downwind vent line and close diverter. 1.
Do not stop pumping and if mud reserves run out, keep pumping seawater at maximum rate. Do not stop the pumps.
2.
Arrange emergency evacuation of all non-essential personnel and prepare evacuation of remaining personnel.
3.
If the diverter system fails before control of the well is regained, or broaching to surface occurs, evacuate all personnel and leave the mud pumps running on seawater at maximum pump rate.
03.05 Rotating head API RP 64 section 3- 3.1.2.3 A rotating head can be used as a diverter to complement a blowout preventer system. The stripper rubber is energized by the wellbore pressure to seal against the drill pipe, kelly, or other pipe to facilitate diverting returned well fluids and can be used to permit pipe movement (reciprocating and or rotation). The original equipment was designed for air drilling and later used for mud, gas 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 09.
and flow and API
The rotating BOP is used on top of a regular BOP stack consisting of ram and annular BOPs.
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The rotating head seals off any shape of kelly and will also seal on any type of drill pipe whether flush joint, upset or coupled. No special operations are required for handling the pipe. As the various elements of the drill string are raised or lowered, the “stripper rubber” changes shape to conform to the OD of these elements. In this way the hole is closed at all times. A flanged outlet below the stripper rubber allows flow under pressure to be directed out through the flow line. Fig 09
The rotating blow-out preventer is ideal for use when: • • • • • •
Drilling in H2S areas. Circulating with air or gas. Drilling under balanced. (UBD) Drilling with reverse circulation. Drilling in areas susceptible to blow-outs. Drilling geothermal wells.
The rotating blow-out preventer consists of three major assemblies. See Fig 10. • • •
The rotating assembly The body Kelly drive unit
Fig 10
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. Some rotating heads is build with hydraulic pressurised stripping rubbers.
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Underbalanced drilling is now being more widely reborn in the oil and gas industry. The major advances of underbalanced drilling is to lower costs, reduce drilling days, reduce differential sticking problems and hole drag caused by mud cake. Because underbalanced drilling creates the condition for fluid to flow from the formation into the well bore, successful underbalanced drilling must include the selection of proper control equipment to handle the drilling fluid and formation fluids at surface. The rotating control head is one of the major elements of the system. 03.06 Diverter control system The diverter control system should be designed to preclude closing-in the well with the diverter. This requires opening one or more vent lines prior to closing the diverter as well as closing normally open mud system valves. A diverter control system should be capable of operating the vent line and flow line valves (if any) and closing the annular packing element on pipe or open hole within thirty seconds of actuation if the packing element has a nominal bore of twenty inches or less. For elements of more than twenty inches nominal bore, the diverter control system should be capable of operating the vent line and flow line valves (if any) and closing on pipe in use within fortyfive seconds. The diverter control system may be supplied with hydraulic control pressure from the BOP control system. In this case there is usually more accumulator capacity, pump capacity and reservoir capacity than is required for the diverter system. These should, however, comply with the recommendations which follow for a self-contained diverter control system. An isolation valve should be installed in the line from the main hydraulic supply to shut off the supply to the diverter control system when it is not in use. The function of this valve should be clearly labeled and its position status should be clearly visible. All of the diverter control functions should be operable from the rig floor. A second control panel should be provided in an area remote from the rig floor. The remote area panel should be capable of operating all diverter system functions including any necessary sequencing and control of the direction of the diverted flow.
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MTC Section 04
WELL CONTROL MANUAL Annular preventers
04.00 Definition (API RP 53 3.1.2): An Annular Preventer is a device that can seal around any object in the wellbore or upon itself. Compression of reinforced elastomer packing element by hydraulic pressure effects the seal. Note: This definition statement is wrong and will be adjusted in the future by API. Annular preventers will not seal around blades of very large stabilizers, bit cones and rollers on roller reamers. 04.01 General In this manual we are going to look at of some commonly used types of annular preventers in the industry. These preventers are used for subsea and/or surface applications and they are fabricated by three different manufactures: Cameron Cooper: Type “D” Type “DL” Hydril:
Model “GK” Model “GL” Model “GX” Model “MSP
Shaffer:
Shaffer Spherical.
04.02 Testing – Surface BOP stacks API RP 53 Visual Inspection of annular preventers: 1. Packer Visually inspect condition of packer. Check for gouges in seal area. Verify and record age of packer. Ensure within shelf life of manufacturer. Record drilling fluid and inquire about compatible. 2. Throughbore Ensure no key seat damage in annular cap wear band. Record if any. 3. Drift Ensure that the packer is fully open and not protruding into the wellbore. 4. Surge Bottle Check for proper nitrogen pre-charge in accumulator bottle. Consider water depth for subsea application. 5. Milling Check for metal shavings if milling operations have been performed. 6. Operating Pressures Ensure that a operating range pressure chart in relation to pipe size and wellbore pressure is posted. Index 1 Page 27
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7. Drift test Drift test the annular preventer to ensure that it returns to full open bore within 30 min. Function test: API RP53 17.3.1 All operational components of the BOP equipment systems should be functioned at least once a week to verify the component's intended operations. Function tests may or may not include pressure tests. • •
Function tests should be alternated from the driller's panel and from mini-remote panels, if on location. Actuation times should be recorded as a data base for evaluating trends.
Pressure tests: API 17.3.2.1 All blowout prevention components that may be exposed to well pressure should be tested first to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to a high pressure. • When performing the low pressure test, do not apply a higher pressure and bleed down to the low test pressure. The higher pressure could initiate a seal that may continue to seal after the pressure is lowered and therefore misrepresenting a low pressure condition. • A stable low test pressure should be maintained for at least 5 minutes. The initial high pressure test: Annular BOPs, with a joint of drill pipe installed, may be tested to the test pressure applied to the ram BOP’s or to a minimum of 70 percent of the annular preventer working pressure, whichever is the lesser. Initial pressure tests are defined as those tests that should be performed on location before the well is spudded or before the equipment is put into operational service. Subsequent high pressure tests: Annular BOP’s, with a joint of drill pipe installed, should be tested to a minimum of 70 percent of their working pressure or to the test pressure of the ram BOP’s, whichever is less. Subsequent pressure tests are tests that should be performed at identified periods during drilling and completion activity on a well. A stable high test pressure should be maintained for at least 5 minutes. With larger size annular BOPs some small movement typically continues within the large rubber mass for prolonged periods after pressure is applied. This packer creep movement should be considered when monitoring the pressure test of the annular. Pressure test operations should be alternately controlled from the various control stations. Pressure tests of hydraulic chambers API RP 53 17.3.2.4 The pressure test performed on hydraulic chambers of annular BOP’s should be to at least 1,500 psi (10.3 MPa). The tests should be run on both the opening and the closing chambers. Pressure should be stabilized for at least 5 minutes.
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Subsequent pressure tests are typically performed on hydraulic chambers only between wells or when the equipment is reassembled. 04.03 Pressure test frequency Pressure tests on the well control equipment should be conducted at least: • Prior to spud or upon installation. • After the disconnection or repair of any pressure containment seal in the BOP stack, choke line, or choke manifold, but limited to the affected component. • Not to exceed 21 days. 04.04 Accumulator response time Response time between activation and complete operation of a function is based on BOP or valve closure and seal off. Closing time should not exceed 30 seconds for annular preventers smaller than 18-3/4” nominal bore and 45 seconds for annular preventers of 18-3/4” and larger. Measurement of closing response time begins at pushing the button or turning the control valve handle to operate the function and ends when the BOP or valve is closed affecting a seal. A BOP may be considered closed when the regulated operating pressure has recovered to its nominal setting. 04.05 Hydril annular preventers Hydril GK annular preventer (See Fig 11) The “GK” annular blow-out preventer was designed especially for surface installations and is also used on offshore platforms and sub-sea. The “GK” is a universal annular blow-out preventer with a long record of proven performance. • •
Only three major components. Only two moving parts.
Closing pressure should be reduced as wellbore pressure increases in order to prevent excessive closing force. Standard operation requires both opening and closing pressure. Seal off is effected by hydraulic pressure applied to the closing chamber which raises the Fig 11 piston, forcing the packing unit into a sealing engagement. The “GK” is designed to be well pressure assisted in maintaining packing unit seal off once initial seal off has been affected. As well bore pressure further increase closure is maintained by well pressure alone.
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Hydril GL annular preventer (See Fig 12) Hydril “GL” annular preventer are designed and developed both for subsea and surface operations. The proven packing unit provides full closure at maximum working pressure on open hole and vitually anything in the bore - casing, drill pipe, tool joints, Kelly or tubing. Screwed or latched head are available. Opening chamber head separates sealing element from hydraulic opening chamber. Closing pressure depends upon the manner in which the secondary port is connected into the hydraulic operating system.
Fig 12
The secondary chamber, which is unique to the “GL” BOP, provides this unit with great flexibility of control hook-up and acts as backup closing chamber to cut operation cost and increase safety factors in critical situations. Hydril GX annular preventer (See Fig 13) The Hydril “GX” offers extra performance and serviceability while retaining the field proven features of Hydril annular BOP’s. The “GX” will close on virtually any drill stem member and seal off the open bore. This feature is called CSO (complete shut off). Operating volumes are lower, resulting in faster closing times and smaller accumulator requirements. No secondary chamber. Latched head design. Fig 13
Opening chamber head separates sealing element from the hydraulic opening chamber. Reduce closing pressure proportionally as well pressure is increased.
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Hydril GX annular preventer closing chart. Fig 14 shows the relationship of closing pressure and well bore pressure for minimum seal off for GX 18-3/4” –10.000 psi annular preventer. Closing pressures are average and will vary slightly with each packing unit. Use closing pressure shown at initial closure to establish seal off, and reduce closing pressure proportionally as well pressure is increased. Well pressure will maintain closure after exceeding the required level. See Fig 14.
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
6000
7000
WELL PRESSURE
Fig 14
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8000
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04.06 Shaffer annular preventers Wedge cover spherical BOP (See Fig 15) Spherical contour of the sealing element gives a long lasting element life. Element able to close on open hole (CSO). Small amount of seals and components. Adapter ring separates the wellbore pressure from the hydraulic area. The preventer is balanced - wellbore pressure does not assist the preventer to remain closed. Hydraulic pressure must be maintained on the closing chamber to force the preventer to seal. Fig 15
Bolted cover spherical BOP (See Fig 16) Spherical contour of the sealing element gives a long lasting element life. Element is able to close on open hole (CSO). Contains few seals and components. Adapter ring separates the wellbore pressure from the hydraulic area. The preventer is balanced - that is wellbore pressure does not assist the preventer to remain closed. Hydraulic pressure must be maintained on the closing chamber to force the preventer to seal.
Fig 16
As the preventer is balanced it require 1500 psi closing pressure for all size pipe smaller than 7” and reduced pressure for pipe larger than 7”. See Fig 17. For stripping operation the size of the pipe being stripped into the well bore and the well bore pressure have to taking into consideration. See Fig 17.
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Fig 17
04.07 Cameron annular preventer Cameron Cooper type “D” and “DL” (See Fig 18) In the unique design of the Cameron “DL” annular preventer, closing pressure forces the operating piston and pusher plate upward to displace the solid elastomer donut and force the packer to close inward. As the packer closes, steel reinforcing inserts rotate inwards to form a continuous support ring of steel at the top and bottom of the packer. The inserts remain in contact with each other whether the packer is open, closed on pipe or closed on open hole. • Replaceable liners around operating piston. • Weep hole between the wellbore pressure seals and the hydraulic system seals. • A two piece packer. See Fig 19 • Operates at higher pressures than most other annular BOP’s. • The preventer is balanced - that is wellbore pressure does not assist the preventer closed. Hydraulic pressure must be maintained on the closing chamber to force the preventer to seal.
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Fig 18
Fig 19
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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.
CLOSING PRESSURE
The graph in Fig 20 allow determination of the approximate closing pressure required to seal a given well bore pressure when stripping into the well.
Fig 20 W ELL B O RE PR ESSU RE
04.08 Packing unit Packing units for the annular BOP’s are available in NITRILE, NEOPRENE or NATURAL rubber. See Fig 21 NITRILE rubber is for use with oil base or oil additive drilling fluids, provides the best overall service life when operated at temperatures between + 20 deg F to + 190 deg F. NEOPRENE rubber is for low temperature operating service and oil base drilling fluids. It can be used at operating temperatures between - 30 deg F to + 170 deg F. NATURAL rubber is for use in non-oil base drilling fluids and can be used at operating temperatures between - 30 deg F to + 225 deg F. In extreme emergencies and when no other alternatives are available sealing elements can be replaced while drill pipe is in the hole. However, this potentially hazardous procedure involves a high degree of risk unacceptable in any circumstances other than emergency. The packing units consist of two components as steel segments and rubber compound.
Fig 21
The steel segments are moulded into the rubber and will partially close over the rubber to prevent excessive extrusion when sealing under high pressure.
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The segment will ensure the element maintains it shape. When the element is closed the steel segment will compress the rubber out against the well bore and create a seal. When the element is opened up the compressed rubber will expand and bring the element to full open position again within 30 min.
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MTC Section 05
WELL CONTROL MANUAL Ram preventers
05.01 General In the industry to-day we are normally taking about four different manufactures of Ram Preventers used both for Sub-Sea or Surface application: Cameron Cooper: Type “U” Type “U-II” Model “T” Hydril:
Hydril Ram Preventer
Shaffer:
Model “SL” Model “LWS”
Koomey:
J-line
Visual Inspection: After each well open the Ram Bonnets (doors). The ram cavity and ram block should be cleaned prior to the following visual inspection. This visual examination is generic and valid for all ram preventers. A few additional areas are required when inspecting the Cameron or Koomey “J” line ram preventer. Ram packers. Ram packers and top seals should be in good condition. Rubber should not be missing from the pipe contact area on the front packer or sheared off on the top seal Bonnet seals. Bonnet seals are generally replaced each time the bonnets are opened. Top seals. When top seals are not proud above ram block, in order of .075” to .140” for manufactures in general, the low pressure integrity of the preventer is jeopardized. Ram cavity Visually inspect cavity upper seal seat for damage. The surface finish at the top of the cavity is the most critical aspect of this inspection. Sharp scratches make it difficult for top seal rubber to flow into these grooves for pressure integrity. Ram blocks If rams are to be used for hanging off the string, record the part number of the ram blocks and verify their capabilities for hanging off. Tagging (hitting) the rams with drill string is the usual cause of damage to the top of a ram block. Connecting rods/ram shaft packing To visually examine the connecting rod, the operating piston must be stroked to the closed position when the bonnets or doors are open.
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Power ram change piston Cameron and Koomey rams use PRC pistons to open and close the bonnets. The surface finish of these chrome rods should also be checked to assure that the operating system has good pressure integrity. Packing injection Check to ensure that secondary packing has not been energized. Check weep hole to ensure it is free of sealant. Sealant could prevent a primary wellbore seal from leaking during a stump test which is performed to find such leaks. Through bore Visually inspect through bore for key seating record. Repairs should be initiated when this bore wear exceeds 3/16”. 05.02 Testing Hang-off test (API Spec. 16A 4.7.2.5) This test shal determine the ability of the ram assembly to maintain a 200-300 psi and full rated working pressure seal while supporting drill pipe loads. This test shall apply to 11 inch and larger blowout preventers. Any hang-off test performed with a variable bore ram shall use drill pipe diameter sizes of the minimum and the maximum diameter designed for that ram. Documentation shall include: • Nondestructive examination (NDE) of ram blocks in accordance with manufacturers written procedure. • Load at which leaks develop or 600.000 lb for 5 inch and larger pipe, or 425.000 lb for pipe smaller than 5 inch, whichever is less. MTC Note:
For variable rams always check with manufacturer for correct value.
Function tests (API RP 53 17.3.1) All operational components of the BOP equipment systems should be functioned at least once a week to verify the component's intended operations. Function tests may or may not include pressure tests. Function tests should be alternated from the driller's panel and from mini-remote panels, if on location. Pressure tests (API RP53 17.3.2) 17.3.2.1 All blowout prevention components that may be exposed to well pressure should be tested first to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to a high pressure. • When performing the low pressure test, do not apply a higher pressure and bleed down to the low test pressure. The higher pressure could initiate a seal that may continue to seal after the pressure is lowered and therefore misrepresenting a low pressure condition. • A stable low test pressure should be maintained for at least 5 minutes. 17.3.2.2 The initial high pressure test on components that could be exposed to well pressure (BOP stack, choke manifold, and choke/kill lines) should be to the rated working pressure of the ram BOP’s or to the rated working pressure of the wellhead that the stack is installed on, whichever is lower. Initial pressure tests are defined as those tests that Index 1 Page 38
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should be performed on location before the well is spudded or before the equipment is put into operational service. There may be instances when the available BOP stack and/or the wellhead have higher working pressures than are required for the specific wellbore conditions due to equipment availability. Special conditions such as these should be covered in the site-specific well control pressure test program. 17.3.2.3 Subsequent high pressure tests on the well control components should be to a pressure greater than the maximum anticipated surface pressure, but not to exceed the working pressure of the ram BOP's. The maximum anticipated surface pressure should be determined by the operator based on specific anticipated well conditions. Subsequent pressure tests are tests that should be performed at identified periods during drilling and completion activity on a well. A stable high test pressure should be maintained for at least 5 minutes. Pressure test operations should be alternately controlled from the various control stations. 17.3.2.4 Initial pressure tests on hydraulic chambers of ram BOP’s and hydraulically operated valves should be to the maximum operating pressure recommended by the manufacturer. The tests should be run on both the opening and the closing chambers. Pressure should be stabilized for at least 5 minutes. Subsequent pressure tests are typically performed on hydraulic chambers only between wells or when the equipment is reassembled. Test fluids 17.3.5 Well control equipment should be tested with water. Air should be removed from the system before the test pressure is applied. Control systems and hydraulic chambers should be tested using clean control fluids with lubricity and corrosion additives for the intended service and operating temperatures. 05.03 Pressure test frequency Pressure tests on the well control equipment should be conducted at least: 1.
Prior to spud or upon installation.
2.
After the disconnection or repair of any pressure containment seal in the BOP stack, choke line, or choke manifold, but limited to the affected component.
3.
Not to exceed 21 days.
05.04 Accumulator response time (API RP53 12.3.3) Response time between activation and complete operation of a function is based on BOP or valve closure and seal off. For surface installations, the BOP control system should be Index 1 Page 39
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capable of closing each ram BOP within 30 seconds. Response time for choke and kill valves (either open or close) should not exceed the minimum observed ram close response time. Measurement of closing response time begins at pushing the button or turning the control valve handle to operate the function and ends when the BOP or valve is closed affecting a seal. A BOP is considered closed when the regulated operating pressure has recovered to its nominal setting. If confirmation of seal off is required, pressure testing below the BOP or across the valve is necessary. 05.05 Cameron ram preventer
Fig 22
Cameron (C.C.C.) manufactures three models of ram preventers specifically designed for sub-sea and surface applications. See Fig 22 They are the type “U” - “U-II” – “T”. In all three products the following features are incorporated: • • • • •
Power ram change ( PRC system). Four bonnet bolts or studs used per bonnet. Wedgelock - ram locking system (Optional for type U) Ram cavities are parallel, top and bottom. Bonnet and body are forged.
Specific model features: Type “U”: Can be fitted with hydraulic bonnet bolts Plastic ram shaft packing and weep hole standard Type “U-II”: Hydraulic bonnet studs as standard. Plastic ram shaft packing and weep hole standard
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Model “T”: Hydraulic bonnet studs Replaceable wear pad fitted beneath ram block In this manual we only look at Cameron type U and U-II The Cameron “U-II” ram type blow-out preventer includes an internally ported hydraulic bonnet tensioning system, a short stroke bonnet, bore type bonnet seals and the proven advance of the “U” BOP design. The “U-II” can be provided in single and double configurations with API flange, hubbed or studded connections, and flanged or hubbed outlets. In Fig 23 the single components of a Cameron type U single ram BOP is shown.
Fig 23
A: 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 24 Ram closing pressure, shown in red in Fig 24 closes the rams. When the bonnet bolts are removed, closing pressure opens the bonnet. When the bonnet has moved to the fully Index 1 Page 41
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extended position, the ram is clear of the body. An eyebolt can be installed into the top of each ram to lift it out of the preventer. Ram opening pressure, shown in blue in Fig 24 opens the rams and closes the bonnets after ram change out. The rams are opened fully before the bonnets begin moving toward the preventer body. This assures that the rams never obstruct the bore or interfere with pipe in the hole. Hydraulic pressure draws the bonnets tightly against the preventer body and the bonnet bolts are reinstalled to hold the bonnets closed. Fig 24
U II BLOWOUT PREVENTER HYDRAULIC CONTROL SYSTEM
The four bonnet studs are simultaneously stretched to the correct pre-load by hydraulic pressure applied behind a piston which acts on a load rod in the stud. The nut is then tightened and pressure is released. Pressure is supplied by an air powered hydraulic pump via internal porting in the BOP body. See Fig 25
Fig 25
The intermediate flange is the barrier between the well bore and the hydraulic operating chamber and contains the seals around the operating shaft. In the bottom of the intermediate flange a weep or vent hole is positioned witch must always be clean. The weep hole has several functions:
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1.
During pressure test of the ram BOP leakage through the weep hole indicates worn seals against the wellbore and require immediately change out prior to commence operation.
2.
Leakage during pressure test of the hydraulic chamber indicates worn seal against the hydraulic operating side and require immediately change out prior to commence operation.
3.
The weep hole avoids well bore pressure on the opening side of the hydraulic chamber.
A secondary seal is installed in the top of the intermediate flange. In the event of leakage during a well control situation the secondary can be engaged by injecting plastic packing through a packing ring that will seal against the well bore. See Fig 26.
Fig 26
Fig 26
All ram BOP’s must be equipped with a ram lock system that can either be manual operated or hydraulic operated to assure that the ram does not open if the hydraulic closing pressure is lost. If it is a manuel system it should be equipped with extension hand wells. For hydraulic operated system Cameron is using the wedge-lock system. The wedge-lock acts directly on the operating piston tailrod. The operating system can be interlocked using sequence caps to ensure that the wedge-lock is opened before pressure is applied to open the BOP. See Fig 27.
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1. 2. 3 4. 5. 6. 7. 8. 9. 10. 11. 12.
WELL CONTROL MANUAL
Locking Head Locking Piston Wedge Piston Wedgelock Housing Unlocking Head Open Port Ram Change Assembly Bonnet Operating Piston Tail Rod Extension To Balance Chamber Close Port
05.06 Cameron ram assembly All BOP manufactures supply three different types of rams: Fixed ram assemblies. Variable ram assemblies. Shear/Blind ram assemblies. Fixed ram assembly The ram assembly consist of Ram Body, Front Packer and Top Seal. To dress the ram body the front packer must be installed first. The top seal is then installed and locks the front packer in place. See Fig 28. The fixed ram assembly can be obtained in different sizes from 2-3/8” to 6-5/8”. Fig 28
Ram packers and top seals should be in good condition. Rubber should not be missing from the pipe contact area on the front packer or sheared off on the top seal. As a general rule, ram packers should be considered acceptable when 80% of the rubber in the pipe contact area is still in place.
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Variable ram assembly Fig 29
One set of variable bore rams can be used to seal on a range of pipe. A set of variable bore rams installed in a BOP saves a round trip of a SubSea BOP stack by eliminating the need to change rams when different diameter drill strings are in use. A set of variable bore rams in a BOP stack provides backup for two or more sizes of standard pipe rams or serves as the primary ram for one size and the backup for the other. See Fig 29.
Shear/Blind ram assembly Shear/Blind rams are designed to shear drill pipe and lighter tubular like tubing and establish a seal against wellbore pressure using high hydraulic closing pressure. The Shear/Blind rams consist of a upper and lower ram body. To dress a Shear/Blind ram body (C) the blade or front packer (F) is installed first. The side packers (B) is then installed to keep the blade packer in place and finally the top packer (E) is inserted to lock the side packers. See Fig 30.
Fig 30
Importance of ram packer pressure Packer pressure is the internal elastomer compressive force generated in the ram packers when closing hydraulic pressure drives the ram assemblies into contact with each other. For a ram assembly to contain wellbore pressure the packer pressure must be higher than the wellbore pressure trying to get past the rubbers. Typically, closing hydraulic operating pressure generates several thousand psi elastomer pressure inside the ram packers. This is sufficient to initially contain wellbore pressure. See Fig 31. As wellbore pressure rises, Index 1 Page 45
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the packer pressure rises as well due to the closing effect that the wellbore pressure has upon the ram blocks. See Fig 32. With this mechanism, packer pressure is maintained above wellbore pressure.
Fig 31
Fig 32
When we have a worn out ram cavity or worn ram rubbers, the closing operating pressure is not able to generate the required packer pressure with a leak resulting. Feedable rubber All major ram type BOP manufacturers use the feedable rubber design concept in their ram packers. This includes Cameron, Hydril, Shaffer and MH Koomey. Extrusion plates moulded into the front packer into the front packer serves several purposes: To support the rubber to prevent unwanted extrusion due to wellbore forces in the vertical direction. Act as pistons to extrude feedable rubber to the point of pipe contact. See Fig 33.
Fig 33
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A new front packer contains large volume of feedable rubber. When seal off is obtained, a large clearance exists between the ram and pipe. A moderately worn packer still retains a large but reduced volume of feedable rubber. The clearance between the ram and pipe is reduced at the seal off position. The extensively worn front packer has used almost all of the feedable rubber volume, but still able to effect a full rated seal off. The clearance between the ram and pipe is now approaching zero, indicating completion of the useful life of the front packer. Note: All ram type BOP’s are only designed to contain and seal Rated Working Pressure from below the ram. 07.05 Operating ratio The first ram preventers used in drilling operations were manually operated. Threaded stems were provided to move ram blocks back and forth between the open and close position. It soon became apparent that a faster operating method was needed to close the rams when a well kicked. This led to the development of hydraulic operated pistons to close or open the rams. In Fig 34 is showed a simplified sketch of a hydraulic operated ram preventer. Fluid operating on the operating piston closes or opens the rams. Each type and size of ram preventer has a specified closing and opening ratio, which is a function of that rams particular geometry. RAM SHAFT
PISTON
OPENING CHAMBER
CLOSING CHAMBER
RAM
Fig 34
Closing Ratio. Definition:
A dimensionless factor equal to the wellbore pressure divided by the operating pressure necessary to close the ram BOP against wellbore pressure.
When closing the rams, hydraulic closing pressure acting on the ram operating piston area must overcome the wellbore pressure acting on the ram shaft area which is attempting to force the ram in to open position. This ratio exists because of difference in areas that the closing hydraulic pressure acts upon compared to the ram rod area exposed to wellbore pressure. See Fig 35. Index 1 Page 47
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CLOSING AREA RAM SHAFT AREA WELL PRESSURE
CLOSING PRESSURE
Closing ratios are generally in the range from 6:1 to 9:1. This means that it takes 1 psi of closing hydraulic pressure per 6 to 9 psi wellbore pressure to close the preventer. Stated in another way, on a preventer with closing ratio of 6:1, if the wellbore pressure is 3000 psi it should take 500 psi hydraulic pressure to close the preventer.
Fig 35
The extreme case is closing the ram preventer while it is exposed to maximum rated pressure in the wellbore. This required closing pressure is calculated by the following formula: 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 36 is an exposed view showing forces on a ram block and ram shaft while containing pressure below the ram cavity. The packer is sealed on pipe and opening force is being applied to the operating piston.
Fig 36
The extreme case is opening the ram preventer while it is exposed to maximum rated pressure in the wellbore. This required opening pressure is calculated by the following formula: Opening pressure required to open rams with rated working pressure in the wellbore
Index 1 Page 48
Rated Working Pressure = ------------------------------------Opening Ratio
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08.05 BOP end and side outlet Connections On all type of BOP’s three different types of connections is used both as end connections and side outlet connections. This includes ram preventer, annular preventer, drilling spools, casing spools and hydraulic connectors. The three types are Studded, Clamp Hub and flanged connection. See Fig 36,37,38.
Studded Connection Fig 36
Clamp Hub Connection
Fig 37
Flanged Connection Fig 38
09.05 API type flanges Two types of flanges are used in wellcontrol equipment according to API. API Type 6B Flange and API Type 6 BX Flange. API type 6B flange. API Type 6B flange is a “low” pressured flange with maximum pressure rating of 5000 psi. API Type R or RX ring gaskets are used for this type flange and does not allow face to face contact between hubs or flanges, so external loads are transmitted through the sealing surfaces of the ring. The flange face might be flat or raised type. See Fig 39.
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FLANGE SECTION INTERGRAL FLANGE
WELL CONTROL MANUAL
TOP VIEW
Fig 39
API type 6 BX flange. API Type 6 BX flange is a “high” pressure flange with maximum pressure rating of 20000 psi. API Type BX ring gaskets are used for this type of flange allowing face to face contact of the flanges. The flange face shall be raised except for studded flanges which may have flat faces. See Fig 40.
FLANGE SECTION INTERGRAL FLANGE
Fig 40 TOP VIEW
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MTC RATED WORKING PRESSURE 2000 3000 5000 10000 15000 20000
WELL CONTROL MANUAL 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 • Size • Thread size • End and outlet connection size • Rated working pressure • Ring gasket type and number • Ring gasket material 10.05 Ring joint gaskets and grooves Introduction Ring Joint gaskets and grooves are described within API RP 16A and API RP 53. • Ring gaskets have a limited amount of positive interference which assures the gaskets will be joined into sealing relationship within the flanges grooves. • These gaskets shall not be re-used. Material The purchaser can specify one of the four different materials when he produces API gaskets: MATERIAL 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
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IDENTIFICATION MARKING D S S 304 S 316
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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 41/43.
Type RX
Type R
Fig 41
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 41/43. 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 range, face to face contact may be very difficult to achieve. Without face to face contact
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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 42/43. Type B X
MARKING
Fig 42
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 43
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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.
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MTC 06
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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 44.
Fig 44
06.02 Choke manifold – installation API RP53 8.2 Recommended practices for installation of choke manifolds for surface installations include: a. 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. b. 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. c. The choke manifold should be placed in a readily accessible location, preferably outside the rig substructure. d. 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. e. 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 Index 1 Page 55
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f. g. h.
i.
WELL CONTROL MANUAL
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. A minimum of one remotely operated choke should be installed on 10000 psi, 15000 psi and 20000 psi rated working pressure manifolds. Choke manifold configurations should allow for re-routing of flow (in the event of eroded, plugged, or malfunctioning parts) without interrupting flow control. 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 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: a. Be as straight as possible. b. Be firmly anchored to prevent excessive whip or vibration. c. Have a bore of sufficient size to prevent excessive erosion or fluid friction d. 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. e. 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. f. Lines downstream of the choke manifold are not normally required to contain pressure. g. 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 Index 1 Page 56
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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 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 45.
Fig 45
Fig 46
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 of the valves is normally 3000 psi. See Fig 46. 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
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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
Fig 47
Position indicator
Cameron hydraulically actuated drilling choke are available in working pressures from 5.000 psi to 20.000 psi. See Fig 47. 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 48
Cameron manually actuated choke are available in working pressures from 5000 psi to 20000 psi See Fig 48. 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. Cylindrical gate and large body cavity provide high flow capacity.
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Gate and seat are constructed of erosion resistant tungsten carbide and are reversible for double life. 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 49.
GAS + WATER (VAPOUR)
SOLID HYDRATE BUILD-UP Fig 49
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 .05 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. Index 1 Page 59
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08.06 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 50. 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. Larger exposed liquid surface area. b. Longer retention time of the fluid. c. The gas flow perpendicular to the direction of the fluid flow. Fig 50
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.
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The objective of the dip tube or U-tube 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 U-tube 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 51
Fig 51
A U-tube does not have an indicator installed, but a pressure gauge. 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 09.06 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 52.
Fig 52
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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 athmospheric 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.
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MTC 07
WELL CONTROL MANUAL
Control system
07.01 General BOP control systems for surface installations (land rigs, offshore jack-ups and platforms) normally supply hydraulic power fluid in a closed loop circuit as the actuating medium. The elements of the BOP control system normally include (See Fig 53): 1. Storage (reservoir) equipment for supplying ample control fluid to the pumping system. 2. Pumping systems for pressurizing the control fluid. 3. Accumulator bottles for storing pressurized control fluid. 4. Hydraulic control manifold for regulating the control fluid pressure and directing the power fluid flow to operate the system functions (BOP's and choke and kill (valves). 5. Remote control panels for operating the hydraulic control manifold from remote locations. - Hydraulic control fluid.
Fig 53
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07.02 Response time 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 capable of closing each ram BOP within 30 seconds. 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. 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 may be 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. 07.03 Storage equipment A suitable control fluid should be selected for the system operating medium based on the control system operating requirements, environmental requirements and user preference. Water-based hydraulic fluids are usually a mixture of portable water and a water soluble lubricant additive. When ambient temperatures at or below freezing are expected, sufficient volume of ethylene glycol or other additive acceptable to the control system manufacturer should be mixed with the water-based hydraulic fluid to prevent freezing. The hydraulic fluid reservoir should have a capacity equal to at least twice the usable hydraulic fluid capacity of the accumulator system. 07.04 Pump requirements A pump system consists of one, or more pumps driven by a dedicated power source. Two (primary and secondary) or more pump systems should be employed having independent power sources. The combined output of all pumps should be capable of charging the entire accumulator system from precharge pressure to the maximum rated control system working pressure within 15 minutes. The same pump system(s) may be used to produce power fluid for control of both the BOP stack and the diverter system Each pump system should provide a discharge pressure at least equivalent to the system working pressure. Air driven pump systems should require no more than 75 psi air supply pressure. Devices used to prevent pump system over-pressurization should be installed directly in the control system supply line to the accumulators and should not have isolation valves or any other means that could defeat their intended purpose. Electrical and/or air (pneumatic) supply for powering pumps should be available at all times such that the pumps will automatically start when the system pressure has decreased to approximately ninety percent of the system working pressure and Index 1 Page 64
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automatically stop within plus zero or minus 100 psi of the system design working pressure. 07.05 Accumulator bottles and manifolds Accumulators are pressure vessels designed to store power fluid. Accumulator designs include bladder, piston and float types. Selection of type may be based on user preference and manufacturer's recommendations considering the intended operating environment. The accumulator system should be designed so that the loss of an individual accumulator and/or bank should not result in more than approximately twenty-five percent loss of the total accumulator system capacity. Supply pressure isolation valves and bleed down valves should be provided on each accumulator bank to facilitate checking the precharge pressure or draining the accumulators back to the control fluid reservoir. The precharge pressure in the system accumulators serves to propel the hydraulic fluid stored in the accumulators for operation of the system functions. The amount of precharge pressure is a variable depending on specific operating requirements of the equipment to be operated and the operating environment, but most common 1000 psi. Because of the presence of combustible components in hydraulic fluids, accumulators should be precharged only with nitrogen. 07.06 Hydraulic control manifold The hydraulic control manifold is the assemblage of hydraulic control valves, regulators and gages from which the system functions are directly operated. It allows manual regulation of the power fluid pressure to within the rating specified by the BOP manufacturer. The hydraulic control manifold provides direct pressure reading of the various supply and regulated pressures. A dedicated control circuit on the hydraulic control manifold should operate the annular BOP(s). The components in this circuit should include a pressure regular to reduce upstream manifold pressure to the power fluid pressure level that meets the BOP manufacturer's recommendations. The regulator should respond to pressure changes on the downstream side with sensitivity, sufficient to maintain the set pressure within plus or minus one hundred and fifty psi. The annular BOP pressure regulator should be remotely controllable. Direct manual valve and regulator operability should permit closing the annular BOP and/or maintaining the set regulated pressure in the event of loss of the remote control capability. See Fig 54
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Old Type Annular Pressure Regulator
New Type Annular Pressure Regulator
Fig 54
The hydraulic control manifold includes a common power fluid circuit with pressure regulation and control valves for operation of the ram type BOP's and choke and kill valves. This circuit may be provided with a manifold regulator bypass valve or other means to override the manifold regulator to permit switching from regulated pressure to direct accumulator pressure for operating functions. The regulator should respond to pressure changes on the downstream side with sensitivity, sufficient to maintain the set pressure within plus or minus one hundred and fifty psi. Placing the control valve handle on the right side (while facing the valve) should close the BOP or choke or kill valve, the left position should open the BOP or choke or kill valve. The center position of the control valve is called the "block" position. In the block position, power fluid supply is shut off at the control valve. The other ports on the four-way valve may be either vented or blocked depending on the valve selected for the application. Protective covers or other means which do not interfere with remote operation should be installed on the blind/shear ram and other critical function control valves. Lifting of these covers is required to enable local function operation. 07.07 Schematic of control system See Fig 55. 1. 2. 3. 4. 5. 6. 7.
Customer air supply: Normal air supply is at 125 psi. Higher air pressure may require an air regulator for the air pumps. Air lubricator: Located on the air inlet line to the air operated pumps. Use SAE 10 lubricating oil. Bypass valve: To bypass automatic hydro-pneumatic pressure switch. When pressures higher than the normal 3000 psi are required, open this valve. Keep closed at all other times. Automatic hydro-pneumatic pressure switch: Set to automatcally start the pumps when the system pressure has decreased to 90% (2700psi) of the working pressure and stop the pumps at working pressure (3000psi). Air shut-off valves: Manually operated, to open or close the air supplyto the air operated hydraulic pumps. Air operated hydraulic pumps: Air pumps shuld be capable of charging the accumulators to working pressure with 75psi. Operating pressure up to 125psi. Suction shut-off valve: Manually operated. Keep normally open. One for each air operated hydraulic pump suction line. Index 1 Page 66
MTC 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23.
24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41.
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Suction strainer: One for each air operated hydraulic pump suction line. Check valve: One for each air operated hydraulic delivery line. Electric motor driven triplex or duplex pump assembly. Automatic hydro-eletric pressure switch: Set to automatcally start the pump when the system pressure has decreased to 90% (2700psi) of the working pressure and stop the pump at working pressure (3000psi). Eletric motor starter: Automatically starts and stops the eletric motor driving the triplex or duplex pump. Works in conjunction with the automatic hydro-eletric pressure switch and has a manual overriding on-off switch. Suction shut-off valve: Manually operated. Keep normally open. Suction strainer: Located in the suction line. Check valve: Located in the delivery line. Accumulator shut-off valve: Manually operated. Normally in open position when the unit is in operation. Closed when testing or skidding rig. Accumulators: Check nitrogen precharge in accumulator system every 60 days. Nitrogen precharge pressure should be 1000psi ± 10%. Accumulator relief valve: Valve set to relieve at not more than 10% over the design working pressure (3300psi). Fluid strainer: Located on the inlet side of the Manifold Regulator. Pressure reducing and regulating valve (Manifold Regulator): Manually operated. Adjust to operating pressure of Ram type BOP (1500psi). Manifold: 5000psi working pressure, 2” pipe all welded. Selector valves, 3-position 4-way valves: With air cylinder operators for remote operation from the control panels. Bypass selector valve, 3-position 3-way valve: With air cylinder operator for remote operation from the control panels. In close position it puts regulated pressure on the manifold (1500psi). In open position it puts accumulator pressure on the manifold (3000psi). Manifold relief valve: : Valve set to relieve at not more than 10% over the design working pressure, (5500psi). Hydraulic bleeder valve: Manually operated normally closed. Panel-unit selector: Manual 3-way valve. Used to apply air pressure to the air operated pressure reducing and regulating valve (Annular Regulator), either from the air regulator on the unit or from the air regulator on the remote control panels. Pressure reducing and regulating valve air operated (Annular Regulator): Reduces the accumulator pressure to the required annular BOP operating pressure. Accumulator pressure gauge. Manifold pressure gauge. Annular preventer pressure gauge. Pneumatic pressure transmitter for accumulator pressure. Pneumatic pressure transmitter for manifold pressure. Pneumatic pressure transmitter for annular preventer pressure. Air filter: Located on the supply line to the regulators. Air regulator for annular pressure reducing and regulating valve, air operated Air regulator for pneumatic transmitter. Air regulator for pneumatic transmitter. Air regulator for pneumatic transmitter. Air junction box: To connect the air lines on the unit to the air lines coming from the remote control panels through air cables. Rig test check valve. Hydraulic fluids fill port. Index 1 Page 67
MTC 42. 43. 44. 45. 46. 47. 48. 49. 50. 51. 52. 53.
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Inspection plug port. Rig test outlet isolator valve: High pressure manually operated. Close when rig testing, open when test is completed. Rig test relief valve: Valve set to relieve at 6500psi. Rig test pressure gauge. Rig skid outlet. Rig skid relief valve. Rig skid pressure gauge. Accumulator bank isolator valves: Manually operated, normally open. Rig skid return. Rig skid outlet. Electric power. Rig test outlet.
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Fig 55
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08.07 Fluid flow diagramme for surface installation:
PT PT PT
M
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09.07 Remote control panel A minimum of one remote control panel should be furnished. This is to ensure that there are at least two locations from which all of the system functions can be operated. The remote panel should be accessible to the Driller to operate functions during drilling operations. The Driller's remote control panel display should be physically arranged as a graphic representation of the BOP stack. See Fig 56.
Fig 56
Its capability should include the following: 1. Control all the hydraulic functions which operate the BOP's and choke and kill valves. 2. Display the position of the control valves and indicate when the electric pump is running (offshore units only). 3. Provide control of the annular BOP regulator pressure setting. 4. Provide control of the manifold regulator bypass valve or provide direct control of the manifold regulator pressure setting. 5. The driller's panel should be equipped with displays for readout of: • Accumulator pressure • Manifold regulated pressure • Annular BOP regulated pressure • Rig air pressure 6. Offshore rig driller's panels should have an audible and visible alarm to indicate the following: • Low accumulator pressure • Low rig air pressure • Low hydraulic fluid reservoir level • Panel on standby power (if applicable) 7. All panel control functions should require two handed operation. Regulator control may be excluded from this requirement. The BOP stack functions should also be operable from the main hydraulic control manifold. This unit should be installed in a location remote from the drill floor and easily accessible to rig personnel in an emergency.
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Remote control from the remote panels of the hydraulic control manifold valves may be actuated by pneumatic (air), hydraulic, electro-pneumatic, or electro-hydraulic remote control systems. The remote control system should be designed such that manual operation of the control valves at the hydraulic control unit will override the position previously set by the remote controls. 10.07 Accumulator volumetric requirements API RP 16E 2.4.3 The BOP control system should have a minimum stored hydraulic fluid volume, with pumps inoperative, to satisfy the greater of the two following requirements: 1. Close from a full open position at zero wellbore pressure, all of the BOP's in the BOP stack, plus fifty percent reserve. 2. The pressure of the remaining stored accumulator volume after closing all of the BOP's should exceed the minimum calculated (using the BOP closing ratio) operating pressure required to close any ram BOP (excluding the shear rams) at the maximum rated wellbore pressure of the stack. The about mentioned requirements are from API (RP 16E) and are just guidelines. The actual volumetric requirement depends on working area, national rules and company policy and can vary a lot. API RP 53 12.3.2 BOP systems should have sufficient usable hydraulic fluid volume (with the pumps inoperative) to close one annular type preventer, all ram type preventers from a full open position, and open one HCR valve against zero wellbore pressure. After closing one annular preventer, all ram-type preventers, and opening one HCR valve, the remaining pressure shall be 200 psi (1.38 Mpa) or more above the minimum recommended precharge pressure. The about mentioned requirements are from API (RP 53) and are just guidelines. The actual volumetric requirement depends on working area, national rules and company policy and can vary a lot. 11.07 Accumulator volumetric capacity For the purpose of this section, the following definitions apply: Stored hydraulic fluid is: The fluid volume recoverable from the accumulator system between the maximum designed accumulator operating pressure and the precharge pressure. Usable hydraulic fluid is: The hydraulic fluid recoverable from the accumulator system between the maximum accumulator operating pressure and 200 psi (1.38 Mpa) above precharge pressure. Minimum calculated operating pressure is: The minimum calculated pressure to effectively close and seal a ram-type BOP against a wellbore pressure equal to the maximum rated working pressure of the BOP divided by the closing ratio specified for that BOP.
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Component minimum operating pressure recommended by the manufacturer is: The minimum operating pressure that will effectively close and seal ram-type or annulartype preventers under normal operating conditions, as prescribed by the manufacturer. The equation for volumetric capacity calculation according to Boyle’s law is: P1 x V1 = P2 x V2 or Pressure x Volume = Constant where: P1 = Initial Pressure V1 = Initial Gas Volume
P2 = Final Pressure V2 = Final Gas Volume
Fig 57
Example: Accumulator bottle size 10 gallons. Precharge pressure 1.000 psi Initial condition with only gas (See Fig 58a): Pressure x Volume = Constant 1000 x 10 = 10000 The pump system is started and hydraulic fluid is pumped into the accumulator bottle until maximum operating pressure is reached at 3.000 psi (See Fig 58b): P1 x V1 = P2 x V2
⇔
1000 x 10 = 3000 x V2
10.000 = 3.33 V2 = -----------3.000 Stored hydraulic fluid = 10 - 3.33 = 6.66 gal Index 1 Page 75
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1.000 psi
3.000 psi
1.200 psi
1.500 psi
2.110 psi
10 gal
3.33 gal
8.33 gal
6.66 gal
4.74 gal
6.66 gal
1.66 gal
3.33 gal
5.26 gal
Fig 58 b Gas
Fig 58 c
Fig 58 d Fluid
Fig 58 e
Fig 58 a Fig 58
The pump system is isolated and the BOP’s functioned until accumulator pressure reach precharge pressure + 200 psi (See Fig 58c): P1 x V1 = P2 x V2
⇔
1000 x 10 = 1200 x V2
10.000 = 8.33 V2 = -----------1.200 Usable hydraulic fluid = 8.33 - 3.33 = 5 gal If the minimum operating pressure recommended by the manufacture is 1.500 psi as for Shaffer Annular Preventer with pipe size smaller than 7” the usable hydraulic fluid would be (See Fig 58d): P1 x V1 = P2 x V2
⇔
1000 x 10 = 1500 x V2 10.000 = 6.66 V2 = -----------1.500
Usable hydraulic fluid = 6.66 - 3.33 = 3.33 gal If the minimum calculated operating pressure to effectively close and seal a ram-type BOP against maximum wellbore pressure is used the usable hydraulic fluid would be (See Fig 58e): Shaffer 15.000 psi Bop with closing ratio 7.11 Minimum operating pressure = 2110 psi
Index 1 Page 76
MTC P1 x V1 = P2 x V2
WELL CONTROL MANUAL ⇔
1000 x 10 = 2110 x V2
10.000 = 4.74 V2 = -----------2.110 Usable hydraulic fluid = 4.74 - 3.33 = 1.41 gal To determine the total number of accumulator bottles to be present, divide the required total volume according to rules and regulations to operate the functions on the BOP with the calculated usable hydraulic fluid per bottle. Round off to next larger whole bottle or accumulator bank.
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MTC 08
WELL CONTROL MANUAL
Auxiliary equipment
08.01 Kelly valves An upper kelly valve is installed between the swivel and the kelly. A lower kelly valve is installed immediately below the kelly. See Fig 59/60. Fig 59
Fig 60
08.02 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 61. Fig 61
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08.03 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 or valves should be equipped to screw 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 62.
Fig 62
08.04 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 63. No direct read-out of SIDPP can be obtained. 1. 2. 3. 4.
Release Tool Body Valve Release Rod Valve Spring Valve Seat
Fig 63
08.05 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.
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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, 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: a.
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 64.
b.
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 65. Fig 64
Fig 65
08.06 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 66. Fig 66
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08.07 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 67.
Fig 67
08.08 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. 08.09 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 signaling devices on the rig floor. These are valuable in detecting fluid gain or loss. 08.10 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.
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Maersk Training Centre Drilling Section Chapter 2
Extracts from API
Copyright © Maersk Training Centre a/s. All rights reserved. No part of this publication may be reproduced, stored in or introduced into a retrieval system, or transmitted, in any form, or by any means (electronic, mechanical, photocopying, recording or otherwise) without the prior written permission of Maersk Training Centre a/s.
API SPEC 16a, API RP16E, API RP53, API RP64,
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Section 01 Diverter system - Purpose API RP53 4.1 A diverter system is often used during top-hole drilling. A diverter is not designed to shut 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. The system is deals with potentially hazardous flow tha 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 location. Diverters having annular packing units can also close on 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. Equipment and installation guidelines General When commencing a well located in the water, a short string of large diameter casing or drive pipe is usually installed below the mud line. At land locations, a casing string is often set and cemented at a shallow depth. This drive pipe or casing should provide a seal capable of supporting the hydrostatic head of the fluid column from the base of the casing to the flow nipple outlet. The diverter system is installed on the drive pipe or casing. 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. API RP53 4.2.3 Conventional annular BOPs insert-type Diverters or rotating heads 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 fluids while minimizing wellbore back pressure. Vent lines are typically 10 inches (25.5 cm) or larger ID for offshore and 6 inches (15.24 cm) or larger ID for onshore operations. API RP53 4.2.4 If the diverter system incorporates a valve(s) on the vent line(s) 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. 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. CAUTION: Fluid should be pumped through the diverter and each diverter vent line(s) at appropriate times during operations to ascertain that line(s) are not plugged. Inspection and clean-out ports should be provided at all low points in the system. Drains and/or heat tracings may be required in colder climates.
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API RP53 4.2.6 Accumulator capacity for diverter systems should be sized in accordance with API RP 64. Control system general API RP64 3.6.1 The diverter control system is usually hydraulic or pneumatic or a combination of bothtypes which may be electrically controlled and capable of operating the diverter system from two or more control units. Control units should be available for ready access to operating personnel. The diverter control system may be self-contained or may be an integral part of the blowout preventer control system. Volumetric capacity API RP64 3.6.2 As a minimum, it is recommended that all diverter control systems should be equipped with sufficient volumetric capacity to provide usable fluid volume (with pumps inoperative) required to open and close all functions in the diverter system and still retain a 50% reserve. Usable fluid volume is defined as that fluid recoverable from an accumulator between the limits of the accumulator operating pressure and 200 psi above the precharge pressure or the shut off pressure for the hydraulic operating system. API RP53 4.2.7 Consideration should be given to the low temperature properties of materials used for facilities to be exposed to unusually low temperatures. Diverter system installation test API RP53 17.4.1 Actuate the diverter close and open function with drill pipe or test mandrel in the diverter to verify control system. A pressure integrity test (200 psi Min.) should be made on the diverter system after each installation. Pump water or drilling fluid through the diverter system at low pressure and high flow rate and check vent line(s) for returns. Examine system for leaks, vibrations and tie down while pumping at high flow rate. Air, aerated fluid or gas drilling operations API RP64 4.2.3 A diverter system is required in all air/gas drilling service and consists of at least a rotating drilling head and a blooey line (vent line). This diverter system could also be used with a blowout preventer stack installed below. In areas where gas is used as the circulating fluid or where hydrocarbon bearing formations will be drilled, the use of a full opening valve installed on the rotating drilling head should be considered. This valve will allow repairs to be made to the blooey line while diverting any flow through the choke line(s).
Section 02 Blowout preventer equipment selection API RP53 6.2 Every installed ram BOP should have, as a minimum, a working pressure equal to the maximum anticipated surface pressure to be encountered.
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H2S considerations API RP53 20.1 When there is a reasonable expectation of encountering hydrogen sulfide gas zones that could potentially result in the partial pressure of the hydrogen sulfide exceeding 0,05 psi in the gas phase at the maximum anticipated pressure, BOP equipment modifications should be made. Recommended guidelines for conducting drilling operations in such an environment can be found in API RP 49. API RP53 20.2.2 A list of specific items to be changed on annular and ram type BOPs and valves for service in a hydrogen sulfide environment should be furnished by the manufacturer. As a guide, all metallic materials which could be exposed to hydrogen sulfide under probable operating conditions should be highly resistant to sulfide stress cracking. API RP53 20.2.7 Elastomeric components are also subject to hydrogen sufide attack. Nitrile elastomeric components which meet other requirements may for hydrogen sulfide service provided drilling fluids are properly treated. Service life shortens rapidly as temperature increases from 150ºF to 200ºF (65.6ºC to 93ºC). In the event flowline temperatures in excess of 200ºF (93ºC) are anticipated, the equipment manufacturer should be consulted. Elastomeric components should be changed out as soon as possible after exposure to hydrogen sulfide under pressure.
Section 03 Classification of blowout preventers API RP53 6.1.1 Classification of arrangements for blow-out preventer equipment is based on working pressure ratings. Normal working pressure ratings are: Rated working pressure 2K 2000 psi (13.8 MPa ) 3K 3000 psi (20.7 MPa ) 5K 5000 psi (34.5 MPa ) 10K 10000 psi (69.0 MPa ) 15K 15000 psi (103.5 MPa ) 20K 20000 psi (138.0 MPa ) Stack component codes API RP53 6.2 The recommended component codes for designation of blow-out preventer stack arrangements are as follows: G A R Rd Rt S K
= = = = = = =
Rotating head Annular type BOP Single ram type BOP Double ram BOP Triple ram BOP Drilling spool with side outlets for choke and kill lines 1000 psi rated working pressure.
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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 simple designation, such as: 10K-13-5/8-SRRA This stack is rated 10000 psi (69.0 MPa) working pressure, it has a throughbore of 13-5/8 inches (34.61 cm), and is arranged from the bottom and up - Drilling spool, single ram, single ram and annular preventer. Annular BOP’s may have a lower rated working pressure than the ram BOP’s. Drilling spools API RP53 6.6.1 Drilling spools for blowout preventer stacks should meet the following minimum specifications: 1)
2) 3) BOP.
3K and 5K arrangements should have two side outlets, no smaller than 2-inch (5.08 cm) nominal diameter and be flanged, studded or hubbed. 10K, 15K and 20K arrangements should have two side outlets, one 3-inch (7.62 cm) and one 2-inch (5.08 cm) nominal diameter and be flanged, studded, or hubbed. 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. Have a rated working pressure equal to the rated working pressure of the installed
API RP53 6.6.2 For drilling operations, wellhead outlets should not be employed for choke- or kill lines.
Section 04 BOP operational characteristics tests. Requirements. API Spec. 16A 4.7.1.1 All testing shall be in accordance with Table 12. Procedure API Specification 16A 4.7.1.2 All operational characteristics tests shall be conducted using water at the same ambient temperature as the wellbore fluid and, unless otherwise noted, the level of piston closing pressure shall be the pressure recommended by the manufacturer and shall not exceed the designed hydraulic operating system working pressure. The manufacturer shall document his procedure and results. The manufacturer shall document his procedure and results. Procedures in API SPEC 16A - Appendix B may be used (See table 12). Acceptance criterion API Spec 16A 4.7.1.3 With the exception of stripping tests, the acceptance criterion for all tests that verify pressure integrity shall be no leakage (See table 12).
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Scaling API Spec. 16A 4.7.1.4 If scaling of size and working pressure is utilised, scaling shall conform to table 12. The manufacturer shall document his technical justifications (See table 12). Table 12- Required Characteristics Tests and Acceptable Scaling Practices. Annular Ram - Type BOPs Test type Fixed Bore² Variable Blind² Shear BOPs Bore Sealing Characteristics P1,S2 P3,S3 P1,S2 P1,S2 P1,S2 Fatique P1,S2 P3,S3 P1,S2 P1,S2 P1,S2 Stripping P2,S2 P2,S2 N/A N/A P2,S2 Shear N/A N/A N/A P1,S2 N/A Hang-off P!/S2 P3,S3 N/A N/A N/A Ram/Packer access b P2,S2 P2,S2c Ram Locking Device N/A P2,S2c Locking Mechanism N/A Sealing Mechanism Temperature Verification P3,S3
Hydraulic connectors N/A
P2,S2 P1,S3 N/A
Notes: a One fixed bore test qualifies other fixed bore pipe sizes and blind rams for the same test. b Only one ran access test is required for a product family. c Only closure mechanisms of functionally similar design may be scaled. d Only one ram locking device test (performed with any ram) is required for a product family Legend: P1 = Qualifies all API rated working pressures equal to and below that of the product tested. P2 = Qualifies all API rated working pressures of the product tested. P3= Qualifies only the API rated working pressure of the product tested. Exception: When packers of identical dimensions and material have multiple pressure ratings, they need only be tested at their maximum pressure rating. S1 = Qualifies all API size designations of the product tested. S2 = Qualifies only the API size designation of the product tested. Ram-type BOP API Spec. 16A 4.7.2 Sealing characteristics test API Spec. 16A 4.7.2.1 This test shall determine the actual opening or closing pressure required to either maintain or break a wellbore pressure seal. The test shall also define the ability of the ram packer to effect a seal when closing against elevated wellbore pressures. For fixed bore rams, a 5-inch test mandrel shall be used for BOPs with wellbores 11-inch and larger and a 3½-inch test mandrel shall be used for BOPs with wellbores smaller than 11-inch. Sealing characteristics test on a variable bore ram (VBR) shall include pipe sizes at the minimum and maximum of the rams range. Documentation shall include: a.
A record of closing pressure versus wellbore pressure to affect a seal against elevated wellbore pressures.
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A record of operator (Closing or opening) pressure versus wellbore pressure to break a wellbore pressure seal.
Fatigue test API Spec 16A 4.7.2.2 This test shall determine the ability of ram packers and seals to maintain a wellbore pressure seal after repeated closings and openings. This test simulates closing and opening the BOP once per day and wellbore pressure testing at 200-300 psi and full rated working pressure once per week for 1.5 years of service. For fixed bore rams, a 5-inch test mandrel shall be used for BOPs with wellbores of 11-inch and larger and a 3½-inch test mandrel shall be used for wellbores smaller than 11-inch. Tests on VBRs shall be performed at the minimum and maximum sizes for their range. Documentation shall include: a. Magnetic particle (MP) inspection of ram blocks in accordance with manufacturers written procedures. b. Total number of cycles to failure to maintain a seal or 546 close/open cycles and 78 pressure cycles, whichever is attained first. Stripping life test API Spec.16A 4.7.2.3 This test shall determine the ability of the ram packers and seals to control wellbore pressure while running dril pipe through the closed rams without exceeding 1 gpm leak rate. A 5-inch test mandrel shall be used for BOPs with wellbores 11-inch and larger and a 3½-inch test mandrel shall be used for BOPs with wellbores smaller than 11-inch. Documentation shall include: a. Wellbore pressure used during the test. b. Record of reciprocating speed. c. Equivalent length of pipe stripped or 50.000 ft, whichever is attained first. Shear ram test API Spec. 16A 4.7.2.4 This test shall determine the shearing and sealing capabilities for selected drill pipe samples. As a minimum, the pipe used shall be: 3½-inch 13.3 lb/ft Grade E for 7¹/16 –inch BOPs, 5-inch 19.5 lb/ft Grade E for 11-inch BOPs and 5-inch 19.5 lb/ft Grade G for 135/8inch and larger BOPs. These tests shall be performed without tension in the pipe and with zero wellbore pressure. Documentation shall include the manufacturer’s shear ram and BOP configuration, the actual pressure and force to shear, and actual pipe yield strength, elongation, and weight per foot of the drill pipe samples, as specified in API Specification 5D. Hang-off test API Spec. 16A 4.7.2.5 This test shall 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: a. Nondestructive Examination (NDE) of ram blocks in accordance with manufacturer’s written procedure.
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b. Load at which leaks develop or 600000 lb for 5-inch and larger pipe, or 425000 lb for pipe smaller than 5-inch, whichever is less. Note: See example of hang-off procedures API RP 59 9.10 Ram access test API Spec 16A 4.7.2.6 This test shall determine the ability of the blowout preventer to undergo repeated ram and/or ram packer changes without affecting operational characteristics. This test shall be accomplished by obtaining access to the rams and performing a wellbore pressure test every 20th ram access. Documentation shall include the number of access cycles to failure or 200 access cycles and 10 wellbore pressure cycles, whichever is less. Ram locking device test. API Spec. 16A 4.7.2.7 This test shall determine the ability of the BOP’s ram locking device to maintain a wellbore pressure seal after removing the closing and/or locking pressure(s). This test may be accomplished as part of the fatigue or hang-off tests. VBRs shal be tested at the minimum and maximum sizes of their range. A 200-300 psi and full rated working pressure test shall be performed. Annular-type BOP API Spec.16A 4.7.3 Sealing characteristics test API Spec. 16A 4.7.3.1 This test shall determine the piston closing pressure necessary to maintain a seal as a function of wellbore pressure up to a full rated working pressure of the BOP. The test is conducted on a drill pipe mandrel and on open hole conditions. For 11-inch and larger BOPs a 5-inch mandrel shall be used. For 9-inch and smaller BOPs a 3½-inch mandrel shall be used. This test shall consist of three parts: 4.7.3.1.1 Constant wellbore pressure test This test shall determine the actual closing pressure required to maintain a wellbore pressure seal on the test mandrel. Documentation shall include a record of wellbore pressure versus closing pressure. 4.7.3.1.2 Constant closing pressure test This test shall determine the maximum wellbore pressure obtainable for a given closing pressure with the preventer closed on the test mandrel. Documentation shall include a record of wellbore pressure versus closing pressure. 4.7.3.1.3 Full closure pressure test This test shall determine the closing pressure required to seal on open hole at one half rated working pressure. Documentation shall include a record of wellbore pressure versus closing pressure. Fatigue test API Spec. 16A 4.7.3.2 This test shall determine the ability of an annular packing unit to maintain a 200-300 psi and rated working pressure seal throughout repeated closings and openings. This test simulates closing and opening the BOP once per day and wellbore pressure testing at 200-300 psi and
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full rated working pressure once per week for one year of service. Documentation shall include: a. Packing element inside diameter (I.D.) after every 20th cycle versus time up to 30 minutes. b. The number of cycles to failure to maintain a seal or 364 close/open cycles and 52 pressure cycles, whichever is attained first. Packer access test API Spec. 16A 4.7.3.3 This test shall determine the ability of the blowout preventer to undergo repeated packer changes without affecting operational characteristics. This test shall be accomplished by obtaining access to the packing unit and performing a wellbore pressure test every 20th packing unit access. Documentation shall include the number of cycles to failure or 200, whichever is attained first. Stripping life test API Spec. 16A 4.7.3.4 This test shall determine the ability of the annular packing unit to maintain control of wellbore pressure while tripping drill pipe and tool joints through the closed packing unit without exceeding 1 gallon per minute (gpm) leak rate. Documentation shall include: a. Wellbore pressure used during the test. b. Record of reciprocating speed. c. Equivalent length of pipe and number of tool joints stripped or 5000 tool joints, whichever is attained first. Operating manual requirements API Spec. 16A 4.9 The manufacturer shall prepare and have available an operating manual for each model ram or annular BOP or hydraulic connector manufactured in accordance with this specification. The operating manual shall contain the following information as a minimum and as applicable: a. b. c. d. e. f. g. h. i. j.
Operation and installation instructions. Physical data. Packers and seals Information. Maintenance and testing information. Disassembly and assembly information. Parts information. Storage information. Hang-off load information. Minimum and maximum operating pressures Shearing capabilities.
Hydrostatic proof testing API Spec. 16A 7.5.8.6 General. API Spec.16A 7.5.8.6.1 All drill through equipment shall be subjected to a hydrostatic proof test prior to shipment from the manufacturer's facility. Water or water with additives shall be used as the testing fluid. Any additives shall be documented in the test records.
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In-plant hydrostatic body or shell test API Spec.16A 7.5.8.6.2 General. API Spec.16A 7.5.8.6.2.1 Drill through equipment shall be tested with its sealing mechanisms in the open position, if applicable. Test pressure. API Spec. 16A 7.5.8.6.2.2 The hydrostatic proof or shell test pressure shall be determined by the rated working pressure for the equipment. Hydrostatic proof test pressure shall be as shown in Table 18. For equipment with end or outlet connection having different working pressures, the lowest rated working pressure shall be used to determine the shell test pressure. Hydraulic operating chamber test API Spec 16A 7.5.8.6.3 General. API Spec. 16A 7.5.8.6.3.1 The hydraulic operating system shall be tested on each assembled blowout preventer and hydraulic connector. Test pressure API Spec.16A 7.5.8.6.3.2 The hydraulic operating chamber shall be tested at a minimum test pressure equal to 1.5 times the operating chamber’s rated working pressure. Table 18 – Hydrostatic test pressurea Rated Working Pressure (psi) 2K 3K 5K 10K 15K 20K
Test pressure API size designation 13-5/8 & Smaller 4K 6K 10K 15K 22.5K 30K
API Size designation 16-3/4 & Larger 3K 4.5K 10K 15K 22.5K ----
aMinimum
pressure gauge reading. Maximum test pressures are determined by the manufacturer. Procedure API Spec. 16A 7.5.8.6.4 The hydrostatic proof test shall consist of three steps: a. The initial pressure-holding period of not less than 3 minutes. b. The reduction of the pressure to zero. c. The second pressure-holding period of not less than 15 minutes. 7.5.8.6.4.1 The timing of the test shall not start until the test pressure has been stabilised within the manufacturer's specified range and the external surfaces of the body members have been thoroughly dried.
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Acceptance criterion API 16A 7.5.8.7.1 The acceptance criterion is that there shall be no leakage.
Section 05 BOP Closing ratio (ram BOP) DEFINITION: A dimensionless factor equal to the well bore pressure divided by the operating pressure necessary to close a ram BOP against well bore pressure. BOP Opening ratio (ram BOP) DEFINITION: A dimensionless factor equal to the well bore pressure divided by the operating pressure necessary to open a ram BOP containing well bore pressure. WARNING: Unless specified by the BOP manufacturer a ram BOP should never be attempted opened unless the pressures above and below the rams are equalised. If rams are opened while containing pressure a major destruction of the ram shaft can occur. Ram locks API RP53 6.3 Ram type preventers should be equipped with extension hand wheels or hydraulically operated locks.
Section 06 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 operation. 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 database for evaluation trends.
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 test of 200 to 300 psi (1.38 to 2.1 MPa), and then to a high pressure. • When performing the low pressure test, donot apply a higher pressure and bleed down to the low test pressure. The higher pressure could initiate a seal after the pressure is lowered and therefore misrepresenting a low pressure situation. • A stable low test pressure should be maintained for at least 5 minutes.
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Initial high pressure test API RP53 17.3.2.2 The initial 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 BOPs or to the rated wotrking pressure of the wellhead that the stack is on, whichever is lower. Initial pressure test 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. • Diverter systems are typically pressure tested to a low pressure only (refer to API RP 64). • Annular BOPs, with a joint of drill pipe installed, may be tested to the test pressure applied to the ram BOPs or to a minimum of 70 percent of the annular preventer working pressure, whichever is lesser. The lower kelly valves, kelly, kelly cock, drill pipe safety valves, inside BOPs and top drive safety valves, should be tested with water pressure applied from below to a low pressure of 200-300 psi (1.38 to 2.1 Mpa) then to the rated working pressure. 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 programme. Subsequent high pressure test API RP53 17.3.2.3 Subsequent high pressure test 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. Annular BOP’s, with a joint of drill pipe installed, should be tested to a minimum of 70% 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 pressure test should be maintained for at least 5 minutes. With larger size annular BOPs some small movement typically continues within the large rubber mass for prolonged periods after pressure is applied. This packer creep movement should be considered when monitoring the pressure test of the annular. Pressure test operations should be alternately controlled from the various control stations. Hydraulic chamber test API RP53 17.3.2.4 The pressure test performed on hydraulic chambers of annular BOPs should be to at least 1500 psi (10.3Mpa). Initial pressure tests on hydraulic chambers of ram BOPs and hydraulic 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 stabilised for at least 5 minutes Subsequent pressure tests are typically performed on hydraulic chambers only between wells or when the equipment is reassembled.
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BOP Closing unit API RP53 17.3.2.5 The initial pressure test on the closing unit valves, manifolds, gauges, and BOP hydraulic control lines should be to the rated working pressure of the control unit. Subsequent pressure tests of closing unit systems are typically performed following the disconnection or repair of any operating pressure containment seal in the closing unit system, but limited to the affected component. Pressure test frequency API RP53 17.3.3 Pressure tests on the well control equipment should be conducted at least: a. Prior to spud or upon installation. b. 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. c. Not to exceed 21 days Summary API RP53 17.3.4 Tables 1 and 2 include a summary of the recommended test practices for surface BOP stacks and related well control equipment. Test fluids API RP53 17.3.5 Well control equipment should be pressure 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 fluid with lubricity and corrosion additives for the intended service and operating temperatures. Test documentation API RP53 17.3.7 The results of all BOP equipment pressure and function tests shall be documented and include as a minimum, the testing sequence, the low and high pressures, the duration of each test, and the resultsof the respective component test. • Pressure tests shall be performed with a pressure chart recorder or equivalent data acquisition system and signed by the pump operator, Contractors toolpusher, and Operating Company representative. • Problems observed during testing and any actions taken to remedy the problems should be documented. • Manufacturers should be informed of well control equipment that fails to perform in the field (Refer to API Spec. 16A).
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Table 1 - Recommended pressure test practices, land and bottom supported rigs Initial test (Prior to spud or upon installation)
Component to be Tested
Recommended Pressure Test
Recommended Pressure Test
Low Pressure – psi
High Pressure – psi
Rotating Head
200 – 300
Optional
Diverter Element
Minimum of 200
Optional
Annular preventer
200 – 300
Minimum of 70% of annular BOP working pressure Minimum of 1500
Operating Chambers
N/A
Ram Preventers Fixed Pipe Variable Bore Blind/blind Shear Operating Chamber
200 – 300 200 – 300 200 – 300 N/A
Working pressure of ram BOP’s Working pressure of ram BOP’s Working pressure of ram BOP’s Maximum operating pressure recommended by ram BOP manufacturer
Diverter Flowlines
Flow Test
N/A
Choke Line & Valves
200 – 300
Working pressure of ram BOP’s
Kill Line & Valves
200 – 300
Working pressure of ram BOP’s
Choke Manifold Upstream of Last High Pressure Valve Downstream of Last High Pressure Valve
200 – 300
Working pressure of ram BOP’s
200 – 300
Optional
BOP Control System Manifold and BOP Lines Accumulator Pressure Close Time Pump Capacity Control Stations
N/A Verify Precharge Function Test Function Test Function Test
Minimum of 3000 N/A N/A N/A N/A
Safety Valves Kelly, Kelly Valves and Floor Safety Valves
200 – 300
Working pressure of components
Auxiliary Equipment Mud/Gas Separator Trip Tank, Flo-Show etc
Flow Test Flow Test
N/A N/A
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Table 2 - Recommended pressure test practices, land and bottom supported rigs Subsequent test (Not to exceed 21 days).
Component to be Tested
Recommended Pressure Test
Recommended Pressure Test
Low Pressure – psi
High Pressure – psi
Rotating Head
N/A
Optional
Diverter Element
Optional
Optional
Annular preventer
200 – 300
Minimum of 70% of annular BOP working pressure Minimum of 1500
Operating Chambers
N/A
Ram Preventers Fixed Pipe
200 – 300
Variable Bore
200 – 300
Blind/blind Shear
200 – 300
Casing(prior to running csg) Operating Chamber
Optional N/A
Greater than the maximum anticipated surface pressure Greater than the maximum anticipated surface pressure Greater than the maximum anticipated surface pressure Optional N/A
Diverter Flowlines
Flow Test
N/A
Choke Line & Valves
200 – 300
Greater than the maximum anticipated surface pressure
Kill Line & Valves
200 – 300
Greater than the maximum anticipated surface pressure
Choke Manifold Upstream of Last High Pressure Valve
200 – 300
Greater than the maximum anticipated surface pressure
Downstream of Last High Pressure Valve
Optional
Optional
BOP Control System Manifold and BOP Lines Accumulator Pressure Close Time Pump Capacity Control Stations
N/A Verify Precharge Function Test Function Test Function Test
Optional N/A N/A N/A N/A
Safety Valves Kelly, Kelly Valves and Floor Safety Valves
200 – 300
Greater than the maximum anticipated surface pressure
Auxiliary Equipment Mud/Gas Separator Trip Tank, Flo-Show etc
Optional Flow Test Flow Test
N/A N/A
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General testing considerations API RP53 17.3.8 Rig crews should be alerted when pressure test operations are to be conducted and when testing are underway. Only necessary personnel should remain in the test area. • Only personnel authorised by the well site supervisor should go into the test area to inspect for leaks when the equipment involved is under pressure. • Tightening, repair, or any other work is to be done only after pressure has been released and all parties have agreed that there is no possibility of pressure being trapped. • Pressure should be released only through pressure release lines. • All lines and connections that are used in the test procedures should be adequately secured. • All fittings, connections and piping used in pressure testing operations shall have pressure ratings greater than the maximum anticipated test pressure. Verify the type, pressure rating, size, and end connection for each piece of equipment to be tested, as documented by permanent markings on the equipment or by records that are traceable to the equipment. When a BOP is tested on the wellhead, a procedure should be available to monitor pressure on the casing should the test plug leak. If the control system regulator circuit is equipped with hydro-pneumatic regulators, a backup supply is recommended to pilot the regulators in case the rig air supply is lost. Functional test of the control system should include a simulated loss of power to the control unit and to the control panel. Vertical stack alignment should be checked and flange bolt make-up should be torqued to prescribed ratings established in API Spec. 6A If hydrogen sulfide bearing formations are anticipated manufacturer’s certification for compliance with NACE Standard MR0175 should be available and reviewed for well control equipment, as described in section 20 (RP53) Surface BOP stack equipment API RP53 17.5 17.5.1 For the purpose of this section, the surface BOP stack equipment includes the wellbore pressure containing equipment above the wellhead, including the ram BOPs, Spool(s), Annular(s), choke and kill valves, and choke line to the choke manifold. 17.5.2 Unless restricted by height, the entire stack should be pressure tested as a unit. 17.5.3 Annular BOPs should be tested with the smallest OD pipe to be used. 17.5.4 Fixed bore pipe rams should be tested only on the pipe OD size that matches the installed pipe ram blocks. 17.5.5 Variable bore rams should be initially pressure tested on the largest and smallest OD pipe sizes that may be used during the well operations. 17.5.6 Blind ram BOPs and blind shear ram BOPs should not be tested when pipe is in the stack. The capability of the shear ram and ram operator should be verified with the BOP manufacturer for the planned drill string. The shear ram and preventer design and/or
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metallurgical differences among the drill pipe manufacturers may require high closing pressures for shear operations. 17.5.7 Prior to testing each ram BOP, the secondary rod seals (emergency packoff assemblies) should be checked to ensure the seals have not been energized. Should the ram shaft seal leak during the test, the seal shall be repaired rather than energizing the secondary packing. 17.5.8 Ram BOPs equipped with ram locks should be pressure tested with ram locks in the closed position and closing pressure bled to zero. Manual locks either screw clockwise or counter-clockwise, to hold the ram closed. Hand wheels should be in place and the threads on the ram locking shaft should be in a condition that allows the locks to be easily operated. 17.5.9 The BOP elastomeric components that may be exposed to well fluids should be verified by the BOP manufacturer as appropriate for the drilling fluids to be used and for the anticipated temperatures to which exposed.Consideration should be given to the temperature and fluid conditions during well testing and completion operations. 17.5.9.1 Manufacturer’s markings for BOP elastomeric components should include the durometer hardness, generic type of compound, date of manufacture, part number, and operating temperature range of the component. 17.5.9.2 Consider replacing critical BOP elastomeric components on well control equipment that has been out of service for six (6) months or longer. 17.5.10 Flexiple choke and kill lines should be tested to the same pressure, frequency, and duration as the ram BOPs.
Section 07 Choke manifolds - Purpose If hydrostatic head of the drilling fluid is insufficient to control subsurface pressure, formation fluids will flow onto the well. To maintain well control, back pressure is applied by routing the returns through adjustable chokes until the well flow condition is corrected. The chokes are connected to the blowout preventer stack through an arrangement of valves, fittings, and lines which provide alternative flow routes or permit the flow to be halted entirely. The assemblage is designated the "choke manifold." Design considerations Choke manifold design should consider such factors as anticipated formation and surface pressures, method of well control to be employed, surrounding environment, corrosivity, volume, toxicity, and abrasiveness of fluids. Choke manifolds and choke lines – Surface BOP installations General API RP53 8.1 The choke manifold consists of high pressure piping, 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 wellbore completely, as required.
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Installation guidelines – Choke manifold Recommended practices for planning and installation of choke manifolds for surface installations include: a)
Manifold equipment subject to well and/or pump pressure (normally upstream of and including the chokes) should have a working pressure equal or greater than the rated working pressure of the ram BOPs in use. For working pressures of 3000 psi (20.7 Mpa) and above, flanged, welded, clamped, or other end connections that are in accordance with API Spec. 6A, should be employed on components subjected to well pressure. The choke manifold should be placed in a readily accessible location, preferably outside of the rig substructure. 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. All choke manifold valves should be full bore. Two valves are recommended between the BOPstack and the choke manifold for installations with rated working pressures of 5000 psi (34.5 Mpa) and above. One of these two valves should be remotely controlled. During operations, all valves should be fully opened or fully closed A minimum of one remotely operated choke should be installed on 10000 psi (69.0Mpa), 15000 (103.5 Mpa) and 20000 psi (138.0 Mpa) rated working pressure manifolds. Choke manifold configurations should allow for re-routing of flow (in the event of eroded, plugged, or malfunctioning parts) without interrupting flow control Consideration 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. 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. 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 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.
b) c) d) e)
f) g) h)
i) j)
k)
Installation guidelines – Choke lines API RP53 8.3 8.3.1 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 following an influx or kick. Refer to API spec. 16C for equipment specific requirements for choke manifolds, flexible choke lines, and articullated line assemblies. The choke line (which connects the BOP stack to the choke manifold) and lines downstream of the choke should: a)
Be as straight as possible.
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1) Because erosion at bends is possible during operations, considerations should be given to using flow targets at bends and on blocks ells and tees. The degree to which pipe bends are susceptible to erosion depends on the bend radius, flow rate, flow medium, pipe wall thickness and pipe material. However, in general, short radius pipe bends (R/d 10), targets are generally unnecessary. Bends sometime have a wall thickness greater than the straight pipe in the choke system (such as the next higher schedule) to further compensate for the effect of erosion. 90º block ells and tees should be targeted in the direction of the flow. Where: R= Radius of pipe bend measured at the centerline. d= Nominal diameter of the pipe 2) For flexiible lines, consult the manufacturer’s guidelines on wiorking minimum bend radius to ensure proper length determination and safe working configuration. 3) For articulated line assemblies, consult with the manufacturer’s written spacifications to determine the degree of relative movement allowable between end points. b. Be firmly anchored to prevent excessive whip or vibration c. Have a bore of sufficient size to prevent excessive erosion or fluid friction: 1. Minimum recommended size for choke lines is 2-inch (5.08cm) nominal diameter for 3K and 5K arrangements and 3-inch (7.62cm) nominal diameter for 10K, 15K, and 20K arrangements. 2. 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. 3. Lines downstream of the choke manifold are not normally required to contain pressure, but should be tested during the initial installation (refer tables 1 and 2 for testing considerations). 4. For air and gas drilling operations, minimum 4-inch (10.16cm) nominal diameter lines are recommended. 5. The bleed line (the line which by-passes the chokes) should be at least equal diameter to the choke line. This line allows circulation of the well with the preventers closed while maintaining a minimum of back pressure. It also permits high volume bleed-off of well fluids to relieve casing pressure with the preventers closed. Maintenance API RP53 8.4 Preventive maintenance of the choke assembly and controls should be performed regularly, checking particularly for wear and plugged or damaged lines. Frequency of maintenance will depend upon usage. Spare parts API RP53 8.5 An adequate supply of spare parts is important for components subject to wear or damage or whose failures seriously reduce the effectiveness of the manifold or choke line. Standardisation of components is recommended to minimize the inventory required. Although the inventory will vary from rig to rig, a generalised recommended minimum spare parts list includes:
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One complete valve for each size installed. Two repair kits for each valve installed. Parts for manually adjustable chokes, such as flow tip inserts, packing gaskets, Orings, disc assemblies, and wear sleeves. Parts for remotely controlled choke(s). Miscellaneous items such as hose, flexiple tubing, electrical cable, and electrical components.
Section 08 Kill lines – Surface BOP installations API RP53 10.1.1 Kill lines are integral part of the surface equipment required for drilling well control. The kill line system provides a means of pumping into the well bore 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 preventer and spools employed; the connection should be below the ram type preventer most likely to be closed. 10.1.2 On selective high-pressure, critical wells a remote kill line is commonly employed to permit use of a auxiliary high pressure pump if the rig pumps become inoperative or 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. Installation guidelines API RP53 10.2 10.2.1 The same guidelines, which govern the installation of choke manifolds and choke lines, apply to kill line installations. The more important recommendations include: a) b) c) d) e) f) g)
All lines, valves, check valves, and flow fittings should have a working pressure rating and be tested following installation to pressures equal to the rated working pressure of the blowout preventer in use. For working pressures of 3000 psi (20.7Mpa) or above, flanged, welded, or clamped connections that are in accordance with API Spec. 6A, should be employed. Components should be sufficient diameter to permit reasonable pumping rates without excessive friction. The minimum recommended size is 2-inch (5.08cm) nominal diameter. Two full bore manual valves plus acheck valve or two full bore valves (one of,which is remotely operated) between the stack outlet and the kill line are recommended for installations with rated working pressure of 5000 psi (34.5Mpa) or greater. Periodic operation, inspection, testing, and maintenance should be performed on the same schedule as employed for the BOP stack in use. All components of the kill line system should be protected from freezing by heating, draining, filling with proper fluid, or other appropriate means. 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 proper fluid, or other appropriate means.
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h)
Lines should be as straight as possible. When bends are required to accommodate either dimensional variation(s) on sequential rigups or to facilitate hookup to the BOP, the largest bend radius allowable under the hookup restraints should be provided. Following is guidance for bends in different types of lines. 1. For rigid pipe, the bend radius should be maximized. Because erosion at bends is possible during operation, consideration should be given to using flow targets at bends and on blocks ells and tees. The degree to which pipe bends are susceptible to erosion depends on the bend radius, flow rate, flow medium, pipe wall thickness, and pipe material. However, in general, short radius pipe bends (R/d10) targets are generally unnecessary. Bends sometime have a wall thickness greater than the straight pipe in the kill system (such as the next higher schedule) to further compensate for the effect of erosion. 90º block ells and tees should be targeted in the direction of flow. Where: R= Radius of pipe bend measured at the centerline. D= Nominal diameter of the pipe. 2. For flexible lines, consult the manufacturer’s guidelines on working minimum bend radius to ensure proper length determination and safe working configuration. 3. For articulated line assemblies, consult the manufacturer’s written specifications to determine the degree of relative movement allowable between the end points. i)
All lines should be firmly anchored to prevent excessive whip or vibration.
10.2.2 The kill line should not be used as a fill up-line during normal drilling operations. Spare parts API RP53 10.4 An adequate supply of spare parts is important for components subject to wear or damage or whose failure seriously reduces the effectiveness of the kill line. Standardisation of components is recommended to minimize the inventory required. Although the inventory will vary from rig to rig, a generalised recommended spare parts list includes: a. One complete valve for each size installed. b. Two repair kits for each valve installed. c. Miscellaneous items such as hose, flexiple tubing, electrical cable, pressure gauges, small control line valves, fittings and electrical components.
Section 09 Control systems for surface mounted BOP stacks API RP16E These systems are typically simple closed hydraulic control systems consisting of a reservoir for storing hydraulic fluid, pump equipment for pressurizing the hydraulic fluid, accumulator banks for storing power fluid, hydraulic regulators, manifolding, piping and control valves for transmission of control fluid to the BOP stack functions.
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General API RP16E 2 BOP control systems for surface installations (land-rigs, offshore jackups and platforms) normally supply hydraulic power fluid in a closed loop circuit as the actuating medium. The elements of the BOP control system normally include: -
Storage (reservoir) equipment for supplying ample control fluid to the pumping system. Pumping systems for pressurising the control fluid. Accumulator bottles for storing pressurised control fluid. Hydraulic control manifold for regulating the control fluid pressure and directing the power fluid flow to operate the system functions (BOP's and choke and kill valves). Remote control panels for operating the hydraulic control manifold from remote locations. Hydraulic control fluid.
Response time API RP16E 2.1 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 capable of closing each ram BOP within 30 seconds. Closing time should not exceed 30 seconds for annular preventers smaller than 18¾ -inch and 45 seconds for annular preventers 18¾ -inch and larger. 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 handle to operate the function and ends when the BOP or valve is closed effecting a seal. A BOP may be 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. Storage equipment API RP16E 2.2 A suitable control fluid should be selected for the system operating medium based on the control system operating requirements, environmental and user preference. Water-based hydraulic fluids are usually mixture of portable water and a water-soluble lubricant additive. When ambient temperatures at or below freezing are expected, sufficient volume of ethylene glycol or other acceptable additive acceptable to the control system manufacturer should be mixed with the water-based hydraulic fluid to prevent freezing. The hydraulic fluid reservoir should have a capacity equal to at least twice the usable hydraulic fluid capacity of the accumulator system. Air breather outlets should be installed of sufficient size to avoid pressurisation of the tank during hydraulic fluid transfer or nitrogen transfers if a nitrogen backup system is installed. Pump requirements API RP16E 2.3 A pump system consists of one or more pumps driven by a dedicated power source. Two (primary and secondary) or more pump systems should be employed having independent power sources. Each pump system should have sufficient quantity and sizes of pumps to satisfactorily perform the following:
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With the accumulators isolated from service, the pump system should be capable of closing each annular BOP (excluding the diverter) on the minimum size drill pipe being used, open the hydraulically operated choke valve(s) and provide the operating pressure level recommended by the annular BOP manufacturer to effect a seal on the annular space within 2 minutes. The combined output of all pumps should be capable of charging the entire accumulator system from precharge pressure to the maximum rated control system working pressure within 15 minutes. The same pump system(s) may be used to produce power fluid for control of both the BOP stack and the diverter system. Each pump system should provide a discharge pressure at least equivalent to the system working pressure. Air driven pump systems should require no more than 75 psi air supply pressure. Each pump system should be protected from over-pressurisation by a minimum of 2 devices designed to limit the pump discharge pressure. One device should limit the pump discharge pressure so that it will not exceed the design working pressure of the BOP control system. The second device, normally a relief valve, should be sized to relieve at a flow rate of at least equal to the design flow rate of the pump systems and should be set to relieve at not more than 10 percent over the design working pressure. Devices used to prevent pump system over-pressurisation should be installed directly in the control system line to the accumulators and should not have isolation valves or any other means that could defeat their intended purpose. Electrical and/ or air (pneumatic) supply for powering pumps should be available at all times such that the pumps automatically start when the system pressure has decreased to approximately ninety percent of the system working pressure and automatically stop within plus zero or minus 100 psi of the system design working pressure. Accumulator bottles and manifolds API RP16E 2.4 Accumulators are pressure vessels designed to store power fluid. Accumulators should be compatible with control fluids, should meet ASME Section VIII Division 1 design requirements and should be documented with ASME U-A-1 certificates. Accumulator types and inter connect of accumulator banks API RP16E 2.4.1 Accumulator designs include bladder, piston and float types. Selection of type may be based on user preference and manufacturer's recommendations considering the intended operating environment. The accumulator system should be designed so that the loss of an individual accumulator and/or bank should not result in more than approximately twenty-five percent loss of the total accumulator system capacity.
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Supply pressure isolation valves and bleed down valves should be provided on each accumulator bank to facilitate checking the precharge pressure or draining the accumulators back to the control fluid reservoir. Precharging accumulators API RP16E 2.4.2 The precharge pressure in the system accumulators serves to propel the hydraulic fluid stored in the accumulators for operation of the system functions. The amount of precharge pressure is a variable depending on specific operating requirements of the equipment to be operated and the operating environment. The accumulator precharge pressure can be checked after bleeding off the control fluid. In the field, the precharge should be checked and adjusted within 100 psi of the recommended pressure at installation of the control system and at the start of drilling each well (intervals not to exceed sixty days). Because of presence of combustible components in hydraulic fluids, accumulators should be precharged only with nitrogen. Compressed air or oxygen should never be used to precharge accumulators since combining them with oil could result in combustion. 2.4.2.1 The recommended precharge pressures for BOP components and conditions specified should be stated on a tag permanently attached to the accumulator banks. Precharge pressure should not exceed working pressure of the accumulator. Accumulator volumetric requirements API RP16 2.4.3 The BOP control system should have a minimum stored hydraulic fluid volume (VR), with pumps inoperative, to satisfy the greater of the two following requirements: 1. Close from a full open position at zero well bore pressure, all of the BOP's in the BOP stack, plus fifty percent reserve. 2. The pressure of the remaining stored accumulator volume after closing all of the BOPs should exceed the minimum calculated (using the BOP closing ratio) operating pressure required to close any ram BOP (excluding the shear rams) at the maximum rated well bore pressure of the stack. Accumulator volumetric requirements API RP53 12.3.2 BOP systems should have sufficient usable hydraulic fluid volume (with pumps inoperative) to close one annular type preventer, all ram type preventers from a full open position, and open one HCR valve against zero wellbore pressure. After closing one annular preventer, all ram preventers, and opening ine HCR valve, the remaining pressure shall be 200 psi (1.38Mpa) or more above the minimum recommended precharge pressure. Note: The capability of the shear ram preventer and the ram operator should be verified with the manufacturer(s) for the planned drill string. The design of the shear ram BOP and/or metallurgical differences among the drill pipe manufacturers may necessitate high closing pressure for shear operations.
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Volumetric capacity calculation The equations for volumetric capacity calculation are different according to local regulations, operating company policy and contractor company policy etc. Examples of methods for volumetric capacity calculations can be found in the following documents • API (RP 53) • API (RP 16E) • NPD Veiledning til forskrift om bore- og brønnaktiviteter og om geologisk datainnsamling i petroleums virksomheten § 31. • DEA Vol.III Sec. • Other national regulations can apply. Hydraulic control manifold API RP16E 2.5 The hydraulic control manifold is the assemblage of hydraulic control valves, regulators and gauges from which the system functions are directly operated. It allows manual regulation of the power fluid pressure to within the rating specified by the BOP manufacturer. The hydraulic control manifold provides direct pressure reading of the various supply and regulated pressures. A suitable valve with porting sized at least equal to the control manifold supply piping size should be provided for supply of control hydraulic fluid from an alternate source. This valve should be plugged when not in use. Hydraulic control manifold annular BOP circuit API RP16E 2.5.1 A dedicated control circuit on the hydraulic control manifold should operate the annular BOP(s). The components in this circuit should include a pressure regulator to reduce upstream manifold pressure to the power fluid pressure level that meets the BOP manufacturer's recommendations. The regulator should respond to pressure changes on the downstream side with sensitivity sufficient to maintain the pressure within plus or minus 150 psi. This pressure range is normally called the regulator's dead band. 2.5.1.1 The annular BOP pressure regulator should be remotely controllable. Direct manual valve and regulator operability should permit closing the annular BOP and/or maintaining the set regulated pressure in the event of loss of the remote control capability. It is essential that the regulator will not fail open if pilot pressure is lost causing complete loss of hydraulic operating pressure. Hydraulic manifold circuit for common pressure functions API RP16E 2.5.1.2 The hydraulic control manifold includes a common power fluid circuit with pressure regulation and control valves for operation of the ram type BOPs and choke and kill valves. This circuit may be provided with a manifold regulator bypass valve or other means to override the manifold regulator to permit switching from regulated pressure to direct accumulator pressure for operating functions.
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Hydraulic control manifold valves API RP16E 2.5.2 Placing the control valve handle on the right side (while facing the valve) should close the BOP or choke or kill valve, the left position should open the BOP or choke or kill valve. The centre position is called "Block" position. In the block position, power fluid supply is shut off at the control valve. The other ports on the four-way valve may be either vented or blocked depending on the valve selected for the application. The hydraulic circuit schematics should clearly indicate the block position control valve port assignments for the particular control system. Valves and gages should be clearly functionally labelled. Protective covers or other means which do not interfere with remote operation should be installed on the blind/shear ram and other critical function control valves. Lifting of these covers is required to enable local function operation.
Section 10 Remote control panels API RP16E 2.6 A minimum of one remote control panel should be furnished. This is to ensure that there are at least two locations from which all of the system functions can be operated. The remote panel should be accessible to the Driller to operate function during drilling operations. The driller's remote control panel display should be physically arranged as a graphic representation of the BOP stack. Its capability should include the following: 1
Control all the hydraulic function, which operate the BOPs and choke and kill valves.
2
Display the position of the control valves and indicate when the electric pump is running (offshore units only).
3
Provide control of the annular BOP regulator pressure setting.
4
Provide control of the manifold regulator bypass valve or provide direct control of the manifold regulator pressure setting.
5
The driller's panel should be equipped with displays for readout of: • Accumulator pressure • Manifold regulated pressure • Annular BOP regulated pressure • Rig air pressure
6
Offshore rig driller's panels should have an audible and visible alarm to indicate the following: • Low accumulator pressure • Low rig air pressure • Low hydraulic fluid reservoir level • Panel on standby power (if applicable).
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7
All panel control functions should require two-handed operation. Regulator control may be excluded from this requirement. The BOP stack functions should also be operable from the main hydraulic control manifold. This unit should be installed in a location remote from the drill floor and easily accessible to rig personnel in an emergency.
Optional remote control methods API RP16E 2.6.1 2.6.1 Remote control from the remote panels of the hydraulic control manifold valves may be actuated by pneumatic (air), hydraulic, Electro-pneumatic, or Electro-hydraulic remote control systems. The remote control system should be designed such that manual operation of the control valves at the hydraulic control unit will override the position previously set by the remote controls. Electro- pneumatic remote control API RP16E 2.6.1.3 Electro-pneumatic controls employ electric circuit to operate pneumatic solenoid valves that control the pneumatic actuators, which operate the hydraulic control valves. Electro-pneumatic controls have the advantage of fast response and ease of running electrical cables compared to hose bundles of pneumatic remote controls. Electro-pneumatic controls should not be used in sub-freezing temperatures. Requirements for BOP control system valves, fittings, lines and manifold API RP16E 2.7 All valves, fittings and other components such as pressure switches, transducers, transmitters, etc., should have a working pressure at least equal to the working pressure of the control system. BOP control system working pressure rating is usually 3000 psi. Other working pressure ratings may be preferred based on function operating requirements. Conformity of Piping Systems API RP16E 2.7.1 All piping components and all threaded pipe connections should conform to the design and tolerance specifications for American National Standard Taper Pipe Threads as specified in ANSI B2.1. Pipe and pipe fittings should conform to specifications of ANSI B31.3. If weld fittings are used, the welder should be certified for the applicable procedure required.All rigid or flexible lines between the control system and the BOP stack should be fire-resistant including end connections, and should have a working pressure equal to the design working pressure of the BOP control system. All control system interconnect piping, tubing, hose, linkages, etc., should be protected from damage from drilling operations, drilling equipment movement and day-to-day personnel, operations. Electrical power supplies API RP16E 2.8 The electrical power supply to electro-pneumatic and electro-hydraulic panels should automatically switch to an alternate source of electric supply when primary power is interrupted. The alternate source of electric power supply should be capable of maintaining operation of the remote functions for a minimum of two hours if primary source should fail.
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Section 11 Closing in a kick Soft close-in procedure For a soft close-in, a choke is left open at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system, with the exception of one choke line valve located near the blow out preventer. When the soft close-in procedure is selected for closing in a well the: 1
Choke line valve is opened.
2
Blow out preventer is closed.
3
Choke is closed.
This procedure allows the choke to be closed in such a manner to permit sensitive control and monitoring of casing pressure buildup during closure. Hard close-in procedure For a hard close-in, the chokes remain closed at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system with the exemption of the choke(s) itself and one choke line valve located near the blow out preventer stack. When the hard close-in procedure is selected for closing in a well, the blow out preventer is closed. If the casing pressure cannot be measured at the well head, the choke line valve is opened with the choke or adjacent high pressure valve remaining closed so that pressure can be measured at the choke manifold. This procedure allows the well to be closed in the shortest possible time, thereby minimising the amount of additional influx of kicking fluid to enter the well bore.
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MAERSK TRAINING CENTRE Drilling Section Chapter 3
Well Control Principles & Procedures
Copyright © Maersk Training Centre a/s. All rights reserved. No part of this publication may be reproduced, stored in or introduced into a retrieval system, or transmitted, in any form, or by any means (electronic, mechanical, photocopying, recording or otherwise) without the prior written permission of Maersk Training Centre a/s.
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MTC Section 01
WELL CONTROL MANUAL PRESSURE IN THE EARTHS CRUST
01.01 Sedimentation: The theory behind the pressure being present in the different depths in the earth rock formations are based on the historic development during millions of years where settling of particles has taken place in the ocean. Large and small rock particles are transported by rivers and streams, ice and wind and deposited on the seabed offshore. In the sea several different chemical substances are present which also separates from the water and sink to the seabed. Amongst others carbonates, sulphates and chlorides are known to be dissolved in the seawater. Small organisms which live in the sea has a life cyclus and when they die their solid remains also sink to the seabed. When this process continues during millions of years the layers of settling will obtain a considerable thickness on the sea floor. 02.01 Compression: The rock particles and solid matter will eventually become more and more compacted as they bear more and more weight from the overlaying deposits. As this process continues the water that is found between the rock particles will usually escape. However there will usually be small cavities left between the particles, which contain the remaining water. These cavities or void spaces make the rock formations more or less porous. A porous formation can contain fluids, gas or hydrocarbons. As compression and compaction continue during time, combined with thermal and chemical processes the unconsolidated particles will eventually become rock formations within the earth crust. These sedimentary rock formations are generally porous, and the pores are filled with a fluid or gas.
SHALE Porous/
impermeable Porous/
SANDSTONE permeable Tight and
SALT without pores Fig 01 If communication between the cavities or pores in the formation is present this allows the fluid to flow away and escape. Under certain conditions the formation fluid can become
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trapped. If a porous fluid-bearing formation becomes covered with an impermeable layer of rock such as a clay stone, the fluid becomes trapped. 03.01 Pressure Before describing the conditions in which the formation fluids are found at different depths in the rock formations the terms mass, density, force, energy and pressure will be considered. Mass Mass is defined as the term for a quantity of matter. The unit of measurement that is used is the pound. Density Density is an expression giving the mass of gas, fluid or solid matter in relationship to its volume, E.I. mass per unit volume. Other means to express density is the term relative density. By relative density is understood, the mass of a particular volume of substance divided by the mass of an equal volume of fresh water. Due to the definition of the relative density it remains dimensionless. In this lecture mass in pounds, and volume in gallons is used, therefore the density is given in pounds per gallon (ppg). Force When a mass hangs by a string, a force will keep the string in tension. The product of gravitational acceleration and the mass causes the force itself.
Mass Power
Fig 02
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This force can be measured by a dynamometer, Fig. 03. This instrument consists of a spring. One end is fixed and the other end shows on a scale how much gravity force is exerted.
Scale Pointer
Fig 03 Force is expressed in the unit pounds-force, which is defined as follows. One pound-force is the force, which will influence a body with a one pound mass when subjected to a gravitational acceleration of 9.80665 m/s2. The gravitational acceleration of 9.80665 m/s2 is present at latitude 45° North on the earth's globe. Gravitational acceleration differs in various parts of the globe. This means that one pound-force is not an equal value everywhere on the globe. As an example the gravitational acceleration at the North Pole is equal to 9.831 m/s2, which gives a force influence on a mass of one pound according to the following G=1 x
9,831 = 1.0025 [ pounds ] 9,80665
At the equator the gravitational acceleration = 9,781 m/s2 The force influence on one pound mass becomes G=1 x
9,781 = 0,9974 [ pounds ] 9,80665
In practice this variation in gravitational acceleration is ignored and a one pound mass is considered to exert a one pound-force influence.
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Pressure Pressure is defined in physics as force per area unit.
Pressure =
Force Area unit
The total force, which acts on a plane, is divided by the area of the plane. The result is called pressure. The unit for force is pounds-force and the unit for area is square inch. Therefore the unit for pressure will be:
Pressure =
Pounds [pounds per square inch ] Square inch M = 1 pound G = 1 pound ( 45° latitude North ) g = 9,80665 m/s2 A = 1 inch2
M G A
Pressure (P) = P x
G 1 = =1 A 1
Fig 04 04.01 Pressure in fluids Considering a vertical cylindrical volume of static fresh water with a cross-sectional area of one inch2 and height of 10 ft, the pressure at the bottom of this cylinder can be calculated. The fluid total volume is 1 in2 x 10 x 12 = 120 in3 10 ft
1 inch2
The density of fresh water is 8.34 ppg
8.34 pounds per gallon =
8.34 x 7,48 pounds/ inch3 1728
Fig 05
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The mass of the fluid column will be M = 8.34
3 pounds gallon 1 ft x 7,48 x x 120 inch3 = 4,33 pounds 3 3 gallons 1728 inch ft
The pressure at the base of the fluid column is caused by gravitational acceleration that acts on the fluid column divided by the fluid columns' cross sectional area. Ph =
4.33 pound = 4.33 psi 1 inch 2
It is important to realise that the pressure at the bottom of a static fluid column is only depending on the vertical height of the column and the density of the fluid. 05.01 Pressure gradient Considering a porous and permeable rock formation in which the pores are filled with fresh water (density 8.34 ppg). It is now possible to calculate the pressure at 5000 feet depth Ph =
4,33 x 5000 = 2165 psi 10
It is also possible to calculate the pressure increase that every foot of depth will represent. Pressure increase per ft =
2165 = 0.433 psi pr ft 5000
This quantity which represents pressure increase in psi/ft is named Pressure Gradient (G). When the pressure gradient for a fluid or gas is known it is easy to calculate the pressure at any given depth. From the shown example of freshwater (8.34 ppg) and pressure gradient (0.433 psi/ft) it is possible to calculate the pressure gradient for a fluid or for a gas with a density of 1 ppg. Pressure gradient for 1 ppg =
0,433 = 0,052 psi / ft 8,34
With this new figure it is now possible to calculate the pressure gradient for any fluid or gas. Pressure gradient = 0.052 x density in ppg Example: Calculate the pressure gradient for a fluid with the density 10.4 ppg. Answer:
0.052 x 10.4 = 0.541 psi/ft Index 03 Page 119
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Calculate the pressure exerted from this fluid at a depth of 4000 ft Answer:
0.541 x 4000 = 2164 psi
Fig 06 shows different pressure gradients and illustrates how pressure increases with depth-
DEPTH 0
1
Gas grad. 0.07 psi/ft 2
Oil grad. 0.30 psi/ft 3
Fresh W. grad 0.433 psi/ft 4
Salt W. grad 0.465 psi/ft 5
10 ppg grad. 0.52 psi/ft
2500 6
15 ppg grad. 0.7785 psi/ft 7
5000
1000
2000
3000
4000
21 ppg grad. 1.091 psi/ft
5000
PRESSURE
Fig 06 06.01 Abnormal / Subnormal pressure So far it has been assumed that there is a direct proportional relation between formation pressure and fluid density and true vertical depth from the surface. That means that the formation fluid pressure is only affected by the fluid density and from the true vertical depth. The influence of the overlying rock formations has so far not been considered. The reason is that in case of a permeable and porous formation system every single rock particle rests upon or leans up against other particles just below and to the side of it. Therefore the rock structure supports its own weight, and regardless of depth does not affect the formation fluid pressure. Index 03 Page 120
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Artesian Well N O RM A L FO RM A TIO N PRESSUR E AT THE W ELL U NTILL BELO W TH E CA P R O CK LA KE
PO R O US SAN DSTO NE BELO W C AP R O CK
When talking about artesian wells, we are normally talking about water wells where we have a porous sandstone witch has communication to higher laying areas creating abnormal pressure below a cap rock.
HYDR O STA TIC PRESSUR E FR O M FO RM ATIO N W ATER CO LU M N
Fig 07 Under compaction Let us consider that at a particular period in a rock formations' development it was not possible for the formation fluids to escape since an impermeable formation type placed on top prevents this from happening. Therefore the rock particles can not be compacted and consolidated sufficiently to carry the weight of the overlying rock. Since the fluid trapped in between the particles could not escape the fluid will be exposed to compressing forces. These forces result in an increased formation fluid pressure, which is abnormal at the given depth. It can be realised that the trapped formation fluid has to carry the weight of the overlaying formation, along with the formation rock in which it is trapped. In a situation such as this the formation pressure will be greatly different from a calculated normal pressure/depth forecast. Example: A formation at 5000 ft depth contains formation fluid. The formation fluid has communication to the surface through porous and permeable formation rock. See fig. 08 Formation pressure at 5000 ft will be the fluid column pressure Density for formation fluid = 8.95 ppg Pressure gradient for formation fluid = 8.95 x O.052 = 0.465 psi/ft Pf (Pressure of Formation) = 5000 x O.465 = 2325 psi
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5000 ft
5000 ft
2325 psi
Impermeable zone 5147 psi
Fig 08 If it is considered that this formation fluid was trapped in an earlier period in the sedimentary process and therefore could not escape the later compaction process, it is possible that the fluid may be exposed to the weight of the overlying rock mass. Assuming formation fluid is 10% and an equivalent formation density of 21 ppg this results in the following formation pressure (Pf): P f = ( 0.1 x 5000 x 8.95 x 0.052) + (0.9 x 5000 x 21 x 0.052)
Pf = 5146.7 psi This formation fluid is over-pressured or abnormal. Over-pressured formations are often encountered with thick salt sediments and salt domes. Salt does not have the same structure as normal rock formations. Salt is termed a "plastic" formation, which means that it is not self-supporting, it can move and deform under pressure, and (this is not necessarily a rapid process). When pressure is applied to a salt formation it behaves more as fluids rather than as solid matter. The relative strength of salt is very low compared to other rock types. Because of the salt's qualities the weight from the overlying formation including the weight of the salt layers themselves will be transferred to the formation below the salt. The pressure in the salt and in the formation below it will often have a pressure gradient of 1 psi/ft instead of the normal pressure gradient for formation fluid, which is 0.465 psi/ft. Abnormal pressures can also occur when an encapsulated and normal pressured formation for the particular depth at a later stage in history with movements or surface erosion is brought closer to the surface. The particular formation in question can be found deeper or shallower in relation to its original position. If it is the case that the formation pressure cannot adjust to its new depth it will hold its original pressure. Example: A sandstone formation at 4000 ft depth is considered to have a normal pressure of 1860 psi. On account of geological processes the area of the sandstone becomes isolated by impermeable rock. Over time and through earth movements the formation moves to a shallower depth of 2500 ft. In this situation the sandstone will retain it's original 1860 psi pore pressure but he surrounding formation has a pore pressure of 1160 psi. Index 03 Page 122
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Such an isolated zone is called a high-pressure zone or abnormal pressured zone. It may as well be the case that the isolated sandstone by earth movements was brought down to 5000 ft depth. The normal pressure for 5000 ft would be 2325 psi and the isolated sandstone area with its 1860 psi would become a low-pressure or subnormal-pressured zone.
2500 ft 4000 ft
1160 psi
1860 psi
1860 psi
5000 ft
1860 psi 2325 psi
1860 psi
Fig 09 Abnormal pressured formations can also develop because of differences in the contained formation fluid and gas densities. Figure 10 shows an anticline. An anticline is the geological term for an area of formations which, due to earth movements has been pushed upwards to take a shape like a dome. In the figure the anticline consists of porous sandstone which contains gas. A layer of impermeable shale that prevents the gas from escaping caps the sandstone. The formation surrounding the anticline has a pore content of salt water and a base depth of 5000 ft. The formation pressure is considered to be normal. Formation pressure of the salt Water bearing rock at 5000 ft will therefore be: P f = 5000 x 0.465 = 2325 psi
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3000 ft Anticline
1395 psi 2125 psi
Porous with water
Sandstone with gas
5000 ft
Tight Shale
2325 psi Fig 10
If the sandstone in the anticline contained salt water instead of gas, the formation pressure at the very top of the anticline would be exactly the same as the formation just above. Example: Pf = 3000 x 0.465 = 1395 psi The sandstone however is containing gas, which has a pressure gradient of 0.1 psi/ft. This results in the pressure at top of the anticline to be substantially higher than the calculated 1395 psi for a salt-water formation. The reason is that the hydrostatic pressure of gas within the anticline is much lower than the corresponding hydrostatic pressure of salt water on the outside. Pressure from the 2000 ft high gas column will be: Ph = 2000 x 0.1 = 200 psi Therefore the formation pressure at the very top of the anticline below the cap rock will be: Pf = 2325 - 200 = 2125 psi Formation structures of this type give a real problem if the formations above and/or below will not withstand the 12.45 ppg hydrostatic pressure from the drilling fluid that is required to balance the zone at 2000 ft. It may be necessary to set several casing strings in order to isolate the pressure. High-permeability limestone formations have small formation strength gradients, and lost circulation may be the result when the bottom well pressure exceeds formation pressure by as little as 200 psi. This value may be less than the dynamic pressure drop in the annulus or less than a safe trip margin. Such conditions can be risky if insufficient information is available.
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Transition zones and under compacted shale Wherever massive shale formations are found the risk for transition zones and high pressure is present. This is caused by thick impermeable shale restricting the disposal of formation fluid. Due to new sediments are settled on the seabed increasing weight load is exerted on the shale from the formation above. The water, gas or oil trapped within the shale cannot escape. The result is the development of abnormal pore pressures. The terminology under compacted shales is used to indicate these circumstances. A seal of harder rock often caps the top of the abnormal pressured shale. After the cap rock is penetrated the Rate of Penetration (ROP) increases. The reason is that the shale is easier to drill since the differential pressure between drilling fluid hydrostatic pressure and the formation pressure decreases. A reduction in overbalance results in a faster drilling rate.
When the Driller maintains his drilling parameters constant (constant rotary speed, constant weight on bit and constant pump rate), the Rate of Penetration (ROP) should be constant as well, unless changes in the drilled formation takes place. The indication of changes in the formation can therefore be observed by the Driller by means of changes in Rate of Penetration. To confirm whether the well is still in balance, the Driller must stop and observe/check if the well is static. The terminology for this operation is "flow checking the well".
UNCONSOLIDATED SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES
SAND WITH COMMUNICATION TO SURFACE
SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED
ENCLOSED SAND LENS WITH FORMATION FLUID
Fig 11 Whenever thick shales are encountered it is important to be careful and expect abnormal pressure in the formation. Shale related abnormal pressures can occur at any depth from surface to very deep and is the most common reason for abnormal formation pressure. Because the formation fluid in under compacted shale is unable to escape, a typical trend will indicate that the cuttings density decrease with depth. The density decrease with depth can indicate that abnormal pressure is encountered. Surcharged formations by underground blowouts A different reason for abnormal formation pressures are the result of previous blowouts underground. Shallower sands can become charged as the result of an uncontrolled underground blow out from an adjacent well or from a bad cement job. Even the well has successfully been closed in on surface the pressure from the deeper zone can communicate to the shallower sand reservoir. When the next well is drilled the abnormal pressure is encountered at the much shallower depth. See Fig 12
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UNDERGROUND BLOWOUT
FAULT ZONE
Pf Pf
Fig 12
Fig 13
Surcharged formations by natural causes Shallow formations may also be surcharged by natural causes. This can be the result of a fault in the formations. A fault gives a means of communication between deeper formations with high pressure and shallower formations. The higher pressure escapes into the shallower formation where an abnormal pressure will be the result. See Fig 13.
Index 03 Page 126
MTC Section 02
WELL CONTROL MANUAL PRESSURE BALANCE IN THE WELL BORE
01.02 Pressure balance During drilling of a well the formation pressure must always be counter balanced by an equal amount of pressure exerted from within the well. This is achieved by using a drilling fluid having a sufficient density. Drilling fluid which is a combination of different fluids and chemicals has several important functions in the drilling process but a main function is the ability to give pressure balance in the well. The density of the fluid can be adjusted by adding high density material or by diluting by water. It is in this way that balance and control of the formation pressure can be achieved. 02.02 Overbalance and underbalance Underbalance is the term used when at a particular depth the formation pressure exceeds the hydrostatic pressure exerted by the drilling fluid column. In this situation there is a risk that fluid from the formation will intrude into the wellbore and begin to displace the drilling fluid. On surface the drilling fluid returns rate will increase and later the active drilling fluid pits will show a gain of fluid. If this sequence of events takes place in a well a kick is said to have occurred. The rate of influx is dependent on the degree of underbalance and on the formation's permeability. To drill a well underbalanced is dangerous in most parts of the world and is therefore usually not practised in oil well drilling. However in certain areas where sufficient data are available it is practised anyway mainly because drilling can take place with a high penetration rate. 03.02 Lost circulation Overbalance in the well is present when the drilling fluid hydrostatic pressure exerts a higher pressure than the formation pressure. In this situation formation fluids cannot intrude into the wellbore. The reverse can occur whereby drilling fluid will seep into the formation, and lost circulation may be the result. This is not a desirable situation. If drilling fluid seeps into the formation the formations' permeability becomes reduced. When the overbalance becomes too large the formation will break allowing a large amount of the drilling fluid to flow into the formation. This situation is called lost circulation. When lost circulation has been the result a dangerous situation is created. The drilling fluid level drops and hydrostatic pressure is lost. When hydrostatic pressure is lost the formation pressure higher up becomes underbalanced which can result in a blow out. 04.02 Rate of penetration versus overbalance The difference between the hydrostatic pressure exerted by the drilling fluid at the bottom of the wellbore and the formation pressure is called the differential pressure. When the hydrostatic pressure exerted by the drilling fluid is higher than the formation pressure the bottom hole pressure is in overbalance.
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The relationship between differential pressure and Rate of Penetration shows that Rate of Penetration increases when the differential pressure decreases. Penetration is given in feet per minute and differential pressure in psi.
Ft/min
15
Rate of Penetration
12
9
6 4 3 psi 1000
2000 Differential Pressure P=
3000
Fig 14 The graph is interesting in several ways. Assume drilling with a differential pressure of 2430 psi in a particular formation with constant drilling parameters. •
Constant Weight on Bit
•
Constant drilling fluid density
•
Constant rotary RPM and
•
Constant pump rate
it can be seen that the penetration rate is 4 ft per minute.
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Without changing any other parameters imagine that the formation pressure increases by 980 psi. This results in a new differential pressure of 1450 psi and a corresponding increased penetration rate to 6 ft per minute. It is realised that when the differential pressure decreases the penetration rate will increase. 05.02 Drilling break An increase in Rate of Penetration (ROP) with constant drilling parameters is called a drilling break. It should be known that a drilling break is an early warning of a kick. If the Driller reacts on the observation by making a flow check the well may still be overbalanced with the pumps stopped. Even that an increase in Rate of Penetration may be caused by other factors than a change in differential pressure, the Driller should always play safe and perform a flow check in order to confirm that the well is in balance. A natural reaction must also be to inform the supervisors of any drilling breaks. 06.02 Necessary overbalance By means of the graph it is seen that to obtain the highest possible penetration rate the degree of overbalance has to be as small as possible. In practice a sufficient overbalance must be used to avoid kicks from taking place. 07.02 Trip margin A situation that can bring the well in underbalance is when the drill string is pulled upwards during a connection and when tripping the string out of the well. The lower part of the drill string acts as a piston that results in reducing the pressure below the string when pulling upwards. When the pressure in the wellbore is reduced the formation fluids can enter the well underneath the bit. To what extent this occurs is dependent on: •
How quickly the drill string is pulled upwards
•
The dimension of the wellbor
•
Dimensions of the drill string
•
The rheological characteristics of the drilling fluid
•
Other factors like degree of balling of the Bottom Hole Assembly etc.
To prevent formation fluids from being swabbed into the wellbore caused by any of these reasons in combination a necessary overbalance is used. This small degree of overbalance is called a trip margin.
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Formation Strength
Fluid Density
Formation Pressure
Surge Pressure
Swab Pressure
Fig 15 Fig. 15 shows the conditions when drilling in normal pressure conditions. The tolerance area (given by the area between the formation strength pressure and the formation pressure) is relatively large. When the drilling fluid density is adjusted to be in the centre of the area, there is only a small risk for swabbing in connection with a trip. There is also allowance for a relatively large surge pressure in excess of the hydrostatic pressure without risk for exceeding the formation strength. Surge pressure in the well is the result of lowering the drill string too quickly. The piston effect results in increasing the pressure below the drill string. Fig 16 and 17 shows different measurements taken with a Pressure While Drilling (PWD) tool under “normal” tripping conditions.
SURGE PRESSURE
SWAB PRESSURE Pulling Speed (mins/stand
Running Speed (mins/stand
Pump Rate 0 gpm
Pump Rate 180 gpm
Pump Rate 250 gpm
1
295 psi
651 psi
837 psi
124
2
124 psi
434 psi
636 psi
0.958
62
3
93 psi
356 psi
527 psi
0.960
31
4
Start EMW (G)
End EMW (G)
Pressure Drop psi
4
0.965
0.956
140
5
0.964
0.956
7
0.962
8
0.962
Fig 16
Fig 17
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08.02 Riser margin When drilling takes place from floating rigs (semi-submersible and drill ship), there can be several hundred feet of distance between the rig and the sea floor. The marine riser connects the rig to the sea floor amongst other to allow returns to be taken to the rig. The drilling fluid that is contained in the marine riser is contributing to balancing the formation pressure in the well. If a marine riser by accident or on purpose is disconnected from the wellhead at the seabed the bottom hole pressure will be reduced. The reason is that the drilling fluid in the marine riser from the well head to the bell nipple is removed and replaced by a shorter column of seawater. An important factor is that the seawater has a lower density than the drilling fluid. To prevent that the reduction in hydrostatic pressure leads to a kick and a blowout a preparation must be made that will ensure that a sufficient overbalance in the well, even with the marine riser disconnected. This overbalance is called a riser margin. It is realised that there are many precautions to take into consideration, when deciding the drilling fluid density to be used in a particular situation. 09.02 Relationship between hydrostatic pressure, drilling fluid density and true vertical depth Example: Well depth TVD Drilling fluid density
6000 10.5
ft ppg
What is the hydrostatic bottom hole pressure? Answer:
Ph = 10.5 x 0.052 x 6000 = 3276 psi
It is required to increase the hydrostatic bottom hole pressure by 500 psi. Which new drilling fluid density shall be used? Answer:
Ph = 3276 + 500 = 3776 psi
The new drilling fluid density will therefore be: 3776 MW = --------------------- = 12.1 ppg 6000 x 0.052 The increase in drilling fluid density will be: ∆MW = 12.1 - 10.5 = 1.6 ppg With the new drilling fluid density drill to 9000 ft TVD and calculate the bottom hole pressure at this depth?
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WELL CONTROL MANUAL
Ph = 12.1 x 0.052 x 9000 = 5663 psi
What is the pressure gradient of this drilling fluid column? Answer:
G drilling fluid = 12.1 x 0.052 = 0.629 psi per foot
This can also be calculated a different way: 5665 Gmud = ------------------- = 9000
0.629 psi per foot
All results comes from utilising the formula: Ph = TVDft x Drilling Fluid Densityppg x 0.052 0.052 is a constant, which represents the pressure gradient in psi per foot for a fluid density equal to 1 ppg. Pressure Gradient G Drilling Fluid = Drilling Fluid Density ppg x 0.052 psi/ft
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10.02 Equivalent drilling fluid Density. Considering a well with a true vertical depth of 6000 ft, filled with drilling fluid having a density of 11 ppg. The well is closed-in at the surface with the Blow Out Preventer (BOP) and drilling fluid is pumped slowly into the wellbore. Pressure at the top of the well will now increase to 900 psi. See Fig 18 900 psi
What will be the bottom hole pressure in the well ? It is seen that the pressure now consists of two components. 1. The hydrostatic pressure from the drilling fluid (which changes with depth).
MW 11 ppg 6000 ft
2. The static pressure at the surface (which gives a constant extra pressure at all depths in the well).
900 psi
900 psi
Fig 18 Hydrostatic pressure Closed-in pressure Bottom hole pressure
11 x 0.052 x 6000
= = =
3430 psi 900 psi 4330 psi
Which drilling fluid density must be used if the above bottom hole pressure shall be maintained by using only hydrostatic pressure? MW =
4330 = 13.9 [ppg] 6000 x 0.052
The calculated drilling fluid density is called the equivalent drilling fluid density.
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This means that the original 11.0 ppg drilling fluid must be replaced by a drilling fluid which has a density of 13.9 ppg if the same bottom hole pressure shall be present without extra pressure being applied at the top of the well. Pressure in all depths in the well will be different in the two examples. This can be confirmed by simple calculation. What is the pressure at 3000 ft in the two examples? Example with closed-in pressure on surface:
1. P h = 11 x 0.052x 3000 = 1716 psi Applied Static Pressure = 900 psi Total Pressure = 2616 psi Example without closed-in pressure on surface: 2. P h = 13.9 x 0.052 x 3000 = 2168 psi
It must be realised that pressures throughout the well will be lower, if a particular bottom hole pressure is achieved only by drilling fluid density, rather than using a lower drilling fluid density combined with a static pressure applied at the surface.
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DYNAMIC PRESSURE REGIME WHEN CIRCULATING
01.03 Circulation of Drilling Fluid Whilst drilling the drilling fluid is continuously circulated to clean out the rock fragments (cuttings) from underneath the bit whilst removing them up to the surface where they are separated from the drilling fluid by the mud cleaning equipment. To establish the circulation in the system it is required to have a dynamic fluid differential pressure between certain areas in the system. This pressure difference represents a certain energy that is used to overcome the resistance against fluid movement, resistance that is existing in the system. This resistance against fluid flow or friction as it is generally called in a hydraulic system is largely dependent upon: • • •
The fluids' rheology (viscosity, density etc.) The fluids' velocity Type of flow regime ( laminar or turbulent)
If a fluid is pumped through an enclosed pipe system with a constant velocity the resistance in the system depends on the flow area. Where the fluid flow meets diameter reductions, a local increase in velocity is the result and therefore a greater friction. Conversely where the flow meets a larger diameter the velocity will decrease and the friction will consequently also decrease. Recorded Pressure (psi) 1400 1320
80
40
1280
1220
60
1170
50
370
800
0
800
Pressure loss (psi)
Fig 19 Fig.19 shows a circulating fluid system where the initial pressure at the pump is 1400 psi and the final pressure is 0 psi at the flow line. It is seen that the 1400 psi represents the energy required to overcome the friction that is present against the flow of the fluid in the system. Large obstructions to flow give large pressure losses. By means of pressure gauges placed in the system the pressure losses in the different parts of the system can be monitored. Applying these considerations to the circulation of drilling fluid the Fig. 20 shows a pipe system in which the drilling fluid pump (mud pump) shall pump drilling fluid through. This simplified pipe system consists of drill pipe, drill collars, bit nozzles and annulus. The drilling
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fluid enters the top of the drill string with a pressure of 2200 psi. On the way down through the string some of this pressure is lost depending on: • •
The dimensions of the drill pipe (Internal diameter) The characteristics of the drilling fluid.
DRILL COLLARS ANNULUS
DRILL PIPE
NATIONAL
PSI
BIT P1 P3 P2
P4
P5
Fig 20 P1 P2 P3 P4 P5
= = = = =
Pressure as drilling fluids enters the drill pipe Pressure as drilling fluid enters the drill collars Pressure as drilling fluid enters the bit nozzles Pressure as drilling fluids enters annulus Pressure as drilling fluid enters the flow line
(2200 psi) (1900 psi) (1700 psi) (130 psi) ( 0 psi)
The largest pressure loss in the well system takes place when fluid flows through the bit nozzles that have a relatively small flow-through area. On the way towards the surface through the annulus, the pressure loss will be the lowest in the system, because the friction is not at all large on account of the large cross-sectional area of the annulus. The pressure figures used in Fig. 20 are based on average calculations for a simple rotary assembly, and they show that 94% of the total pressure loss occurs in the drill string and bit nozzles. The figures show that to circulate the drilling fluid from the bottom of the well up to the surface it is only necessary to use approximately 6% of the total pump pressure. This dynamic pressure will be transmitted to the bottom hole pressure. When the pump is running and circulation takes place there will be a higher bottom hole pressure than when the pump is stopped. With the pumps stopped only hydrostatic pressure is present in the well to balance the formation pressure.
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02.03 Dynamic pressure in the wellbore (Circulating Pressure) Dynamic Pressure (PC) is dependent on three factors: •
Components in the flow system (Flow area, length of drill string, nozzles size etc)
•
The fluid characteristics (Rheology)
•
The flow rate (SPM, liner size, pump efficiency etc)
Change in drilling fluid characteristics (such as viscosity and gel-strength) can change the friction against flow in a system. A fluid's flow resistance is largely depending on the drilling fluid density. In well control calculations it is accepted that dynamic pressure loss is proportionally depending on drilling fluid density.
PC 2 = PC 1 x
PC1 PC2
= =
MW 2 [psi] MW 1
Circulation pressure when drilling fluid density is MW1 Circulation pressure when drilling fluid density is MW2
The expression for the relationship between circulation pressure and drilling fluid density has proved to be realistic in most practical cases. See fig. 21. PSI High fluid dens ity Low fluid dens ity
PC2 PC1
Fig 21
Example: At 100 SPM the pump pressure is 1000 psi with a drilling fluid density of 10 ppg. What would the pump pressure be at 100 SPM if the drilling fluid density was increased to 12 ppg? New pump pressure:
P C 2 = 1000 x
12 = 1200 [psi] 10
To calculate the new
pump pressure Index 03 Page 137
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it is required to know the original pump pressure, which is read just after the pump ( standpipe pressure ). The third factor that affects the circulation pressure is the speed of the flow of drilling fluid. This velocity of flow is directly related on the pump speed ( SPM = strokes per minute). The relationship between pump speed and dynamic pressure can be expressed as: SPM 2 PC 2 = P C 1 x SPM 1
1.86
Where SPM is the number of strokes per minute in the two cases. Example: Circulation pressure is 1200 psi with 40 SPM. What will the circulation pressure be if the pump speed was increased to 80 SPM?
80 P C 2 = 1200 x 40
Answer:
1.86
= 4356 psi
It is realised that if the pump speed is increased to twice its original value the dynamic pressure will be increased almost fourfold. The graph in Fig. 22 illustrates this fact. The power 1.86 is an experience figure, which is obtained from experiments. However in well control calculations it is generally accepted to use the power 2 in stead of 1.86. For well control calculations use the formula below:
SPM 2 P C 2 = PC 1 x SPM 1
2
Pc
4000 3000 2000 1000
SPM 10
20
30
40
50
60
Fig 22 Index 03 Page 138
70
80
90
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Fig. 23 shows circulation pressures and pressure losses between the drill string and annulus with three different pump rates.
Pc
4000
80 spm
3000 60 spm 2000 1000
40 spm
Fig 23
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MTC 04
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CONSIDERATIONS WITH A CLOSED-IN WELL
01.04 Closed in well Fig. 24 illustrates a wellbore with pressure gauges. The drill string consists of pipe connected to each other, right down to the bottom of the well. Through the bit nozzles, the string is in communication with the annulus. In principle this can represent two pipes, one inside the other but there is only communication at the bottom of the well. On top of the well the BOP equipment is installed. This equipment makes it possible to contain and close off the annulus and its contents. Under the BOP a pressure gauge is installed which measures the surface annulus/casing pressure. On the top of the drill pipe after the pumps another gauge which measures drill pipe pressure is installed. The two gauges are necessary to get an indication of down hole conditions. PDP NATIONAL
PDP
PA
PA BOP
ANNULUS
DRILLSTRING
DRILL STRING
ANNULAR
A DRILLCOLLAR
Fig 24
Fig 25
02.04 U-tube A simplified and equal system can be represented by two tubes standing upright side-by-side and connected at the bottom. The example is called a U-tube. See. Fig. 25. The pressure in the same horizontal levels in the connected system is always the same if fluid density is the same, when no circulation is taken place and no pressures are closed in on the top on any of the two legs. It is seen that the hydrostatic pressure at the bottom of such a U-tube system, irrespective of which leg of the U-tube column is considered will be equal. This is easily confirmed by a simple calculation:
Index 03 Page 140
MTC
WELL CONTROL MANUAL
Example: True vertical depth = Drilling fluid Density =
10000 10
ft ppg
Both drill pipe and annulus are open at the surface and the U-tube is in balance. Bottom hole pressure Ph at the point A can be found either by the drill pipe or by the annulus when drilling fluid density is uniform :
P h = Drilling Fluid Density ppg x 0.052 x True Vertical Depth ft [psi] P h = 10 x 0.052 x 10000 = 5200 [psi] If the BOP is closed on the annulus and the drilling fluid in the annulus is replaced with saltwater (8.34 ppg ) the following can be calculated: The internal contents of the string (drill pipes and drill collars) have not changed so PH at A is still 5200, but the hydrostatic pressure in the annulus is only (Fig 26):
P ha = 8.34 x 0.052 x 10000 = 4337 psi P a = 5200 - 4340 = 860 psi
8.34 ppg
PA
9 ppg
10000 ft
DRILL STRING
ANNULUS
DRILL STRING
10 ppg
10000 ft
PDP
PA
ANNULUS
PDP
8.34 ppg
A
A
Fig 26
Fig 27
Index 03 Page 141
MTC
WELL CONTROL MANUAL
Example: Considering the same well with the same bottom hole pressure, but now with 9 ppg drilling fluid in the drill string and upper 7000 ft of annulus, while there remains saltwater in the lower part of the annulus (Fig 27). When PSIDP = Pressure (Shut in drill pipe) When PSIA = Pressure (Shut in annulus)
P SIDP = 5200 - ( 9 x 0.052 x 10000 ) = 520 [psi]
P SIA = 5200 - ( 7000 x 9 x 0.052 + 3000 x 8.34 x 0.052 ) = 623 [psi] The example represents a typical kick situation, where insufficient drilling fluid density has resulted in a saltwater influx into the annulus. The influx has replaced a quantity of drilling fluid. Notice that the drill pipe bottom hole pressure consists of two parts, first the PSIDP value and secondly the hydrostatic pressure of the drilling fluid. The annulus bottom hole pressure consists of three parts. (1) The PSIA value (2) the hydrostatic pressure of drilling fluid and (3) the hydrostatic pressure of the saltwater.
Index 03 Page 142
MTC 05
WELL CONTROL MANUAL
PROPERTIES OF GASSES AND GAS LAWS
01.05 Drilling with underbalance. If drilling takes placed being underbalanced the risk of taking a kick is always present. The influx resulting from a kick can be water, oil or gas. When dealing with gas the drill crew must be aware that gas behaves differently than fluid. 02.05 Properties of gas and gas laws A given mass of gas can be compressed or expanded, and as the volume changes the pressure will do the same. Boyles Law states that: P1 x V1 = P2 x V2 or Pressure x Volume = Constant → See Fig 28 Fig 28 PRESSURE 15000 14000 13000 12000 11000 10000 9000 8000 7000 6000 5000 4000 3000 2000 1000
5
10
15
20
25
30
35
40
45
50
Index 03 Page 143
55
60
65
70
75
80
VOLUME
MTC
WELL CONTROL MANUAL
This means that when a given volume V1 with an absolute pressure P1 is changed in pressure or volume we get a new pressure P2 with a new volume V2. Example: V1 = 5 gal V2 = 3 gal Calculate
P1 = 170 psi P2
P1 x V 1 = P 2 x V 2 _ P 2 =
P1 x V 1 170 x 5 = = 283 [psi] 3 V2
It is important to know that gas expands if pressure is reduced. Boyle’s Law is only true when the temperature is constant. If the temperature changes the formula given below is used where → T = temperature
P1 x V 1 = P 2 x V 2 T2 T1 It must be noted that the temperature to use is an absolute temperature which is given in Kelvin degrees, (ºK ) for the Centigrade system. If the Fahrenheit system is used the absolute temperature must be given in Rankin (ºR ) degrees. ºK is obtained by addition of 273º to the temperature given in Centigrade ºC.
T ° K = t °C + 273 ºR is obtained by addition of 460º to the temperature given in Fahrenheit ºF.
T ° R = t ° F + 460 Example: V1 = 12 gal V2 = 12 gal
P1 = 90 psi T2 = 80ºC
P2 =
T1 = 20ºC
P1 x V 1 x T 2 90 x 12 x (273 + 80) = = 108 [psi] (273 + 20) x 12 T1 xV 2
Since V1 = V2 pressure increases only through temperature increase. Example: The formula, which relates to the properties of gasses, is here used in a practical example.
Index 03 Page 144
MTC
WELL CONTROL MANUAL
The well has a depth of 10000 ft and there is a swabbed gas bubble on bottom. The drilling fluid density is 12.5. The well is open and in balance. Consequently no closed-in pressure at the surface. The pressure in the gas is therefore equal to the hydrostatic pressure at 10000 ft → Ph. Hydrostatic pressure Ph is 6500 psi. If the BOP is closed and the gas is allowed to rise upwards ( migrate ), the gas volume will not change and in accordance with the gas law the pressure will also remain unchanged. Assuming the temperature is constant the gas would retain its original volume and pressure all the way to the surface. 0 psi
3250 psi
PA
6500 psi
PA
PA
6500 psi 12.5 ppg 12.5 ppg 5000 ft 12.5 ppg 10000 ft
6500 psi
5000 ft
10000 ft
12.5 ppg
6500 psi 6500 psi
9750 psi
13000 psi
Fig 29 Considering that the gas has migrated halfway up the wellbore it still has a pressure of 6500 psi. The pressure at surface (annulus) at this stage will be: (See Fig 29.)
P SIA = 6500 - 12.5 x 0.052 x 5000 = 3250 [psi] Bottom hole pressure:
P bottom = 6500 + 12.5 x 0.052 x 5000 = 9750 [psi] When the gas is allowed to rise all the way to the surface without expanding, the pressure at the surface will be 6500 psi. Bottom hole pressure would be:
P bottom = 6500 + 12.5 x 0.052 x 10000 = 13000 [psi]
Index 03 Page 145
MTC
WELL CONTROL MANUAL
This extreme pressure throughout the wellbore cannot be controlled, and it is not reasonable to assume that the situation would develop all the way as described. The weakest point in the wellbore is normally believed to be at the casing shoe level. When the pressure increases above the strength at the weakest point the formation at that point will fracture. The risk for an underground blow out is high. A gas kick can never be allowed to migrate up through the annulus without expanding. A skilled drill crew must take proper and timely action to avoid the dangerous situation that is likely to occur. In the given example the temperature influence neither the changed height due to annulus geometry was taken into account since these factors only have a small influence in practice. 03.05 Expansion of gas Although some kicks are predominantly salt water or oil, at least some gas is usually present. Because salt water and oil do not expand as pressure decreases, they are not as troublesome as gas. It is important for the persons who control blowouts to understand the behaviour of gas in a well. The gas volume change as a result of pressure change is predictable, and this allows calculation under illustrative conditions of changes in bottom well pressure as gas rises through the drilling fluid. When the pressure of a given mass of gas is doubled, the volume is halved. When the pressure is halved the volume is doubled. This relationship between pressure and volume results in the greatest expansion of the gas in the upper part of the well. See Fig 28. Although gas-cut drilling fluid is one of the early indicators of abnormal pressure, minor gas-cutting results in only a small reduction in the hydrostatic head. In a gas-cut column of drilling fluid, the pressure increases rapidly with depth, so that the volume of gas scattered through the well bore is very small, and reduces the overall drilling fluid density in the well very little. A slug of gas in the bottom of a well is potentially dangerous, because it will expand greatly when it rises or is pumped up. Under low pressure near the surface, it will displace a large amount of drilling fluid from the well and consequently greatly reduce bottom hole pressure giving risk for a blowout. The safe handling of a gas kick requires knowledge about the principle of gas expansion and consequently lowering the pressure in the gas bubble as it is circulated up through the annulus in order to maintain the correct and constant bottom hole pressure. The theoretical knowledge requires practice as well as knowledge about well control equipment. When the gas in a well control situation is circulated to the surface and expanding, more drilling fluid must be allowed to flow out of the annulus than is pumped into the drill pipe. Thus, the pit level will increase. The expected drilling fluid volume increase should be known prior to circulating out the kick. This detail is discussed in the kick control section. To control a correct and constant bottom hole pressure, the surface pressures are used as a parameter for control. This is done by means of the choke in connection with a stroke counter for the mud pumps, and simple recognised procedures.
Index 03 Page 146
MTC
WELL CONTROL MANUAL
04.05 Formation strength From the previous examples it is realised that pressure throughout the wellbore increases when gas rises up the annulus in a closed-in well. Gas must be circulated out of a well under control. One of the most important limitations that should be known is the maximum pressure the formation (or weak point) can withstand before it fractures and allows the drilling fluid to flow into the formation. If the formation strength is exceeded in a kick situation there is a high risk for an underground blow-out and perhaps complete loss of control of the well. The formation strength is recorded by means of a leak-off test. 05.05 Leak-off test A leak-off test can be carried out in various ways. The aim is to find the surface annulus pressure value for when the drilling fluid begins to seep into the formation, without at the same time to cause an actual fracture of the formation. The less drilling fluid volume that is pumped into the formation, the less damage there is caused to the formation. After the test the formation should easily heal again as a result of the drilling fluid's wall building effect. A leak-off test is carried out just after casing has been set and cemented. A leak-off test may be conducted as follows:
• • •
Between 10 and 30 feet is drilled below the casing shoe to expose virgin hole. The well is then circulated clean to obtain an accurately known drilling fluid density all through the well. The well is closed-in and drilling fluid is pumped into the well at a very slow rate.The cement pump is generally used since they have a smaller displacement and thus are easier to control and are fitted with very accurate low pressure gauges.Accurately measured volumes are pumped into the well, one barrel in this example, until an increase in casing pressure is registered. At this point pumping is stopped for about one minute, until the surface annulus pressure has stabilised. When no pressure decrease is observed the pressure is plotted on a graph paper. The pumping is resumed and the same volume is again pumped. The pumps are stopped and the new pressure is plotted after it has stabilised. This procedure is repeated until it is observed that the pressure increase per volume portion is no longer proportional.
This is easy seen on the plotted graph at the point where the straight line begins to bend.
Index 03 Page 147
MTC
WELL CONTROL MANUAL
The pressure on the graph where this happens is the annulus surface leak-off pressure. See Fig. 30. PRESSURE ANNULUS
DEPTH
PRESSURE
1100 1000 900 800 700
* *
600
S H O E
*
*
500
* *
400
*
300
*
200 100
* * *
* * * 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
V O L U M E
Ph
Max P shoe
P R E S S U R E
Fig 30 The leak-off test should be interrupted at this point. If the pumping is continued the pressure will decrease as a result of an increasing amount of drilling fluid which is injected into the formation. Furthermore the formation strength will be reduced. It has been proven that a leak-off test performed too far has damaged the formation. In that case a second leak-off test will indicate a lower formation strength. Fig. 30 shows the results from a leak-off test carried out after casing has been cemented at 3000 ft. Drilling fluid density was 9.6 ppg. The leak-off pressure is seen to be 720 psi. The combined pressure the casing shoe is exposed to is the hydrostatic pressure of the drilling fluid and the surface leak off pressure and this combined pressure becomes the maximum allowable shoe pressure at any given time. Calculate the maximum allowable pressure at the casing shoe: Answer:
P shoe = 9.6 x 0.052 x 3000 + 720 = 2218 [psi] When we know the maximum allowable shoe pressure, we are able to calculate the equivalent drilling fluid density or maximum allowable drilling fluid density
Equivalent drilling fluid density =
2218 = 14.22 [ppg] 3000 x 0.052
Index 03 Page 148
MTC
WELL CONTROL MANUAL
06.05 Maximum allowable annular surface pressure ( MAASP ) MAASP means the highest surface pressure that can be allowed at the top of the casing in excess of hydrostatic pressure that is likely to causes losses at the shoe formation if exceeded. There are three factors that decide the Initial MAASP.
•
The maximum pressure that the surface equipment can handle
•
The maximum pressure the casing can handle
•
The maximum pressure that the formation at the casing shoe (or weak point) can support.
In most cases it is the formation strength at the casing shoe that is the deciding factor, and Initial MAASP is then given from the leak-off test which has previously been described. As the maximum allowable shoe pressure remains constant the hydrostatic pressure inside the casing is the determine factor for the MAASP at any given time-See Fig 31 MAASP = Maximum allowable shoe pressure – pressure hydrostatic inside casing
Ph
MAASP DOWN
DOWN
= MAASP UP
Ph
=
UP
Fig 31 As illustrated in Fig 31 the MAASP will increase if pressure hydrostatic inside the casing decrease for whatever reason and visa versa. One important issue when circulating out a kick is to monitor the Initial MAASP value. If the Initial MAASP is approached before the kick is circulated into the casing the responsible rig management must take safe action. It may be impossible to avoid exceeding the Initial MAASP, but the competent and responsible management may decide to evacuate the rig for non-essential personnel until the situation has proven to be safe. Once the influx is inside the casing the initial value can be exceeded. In chapter 08 we will look on how MAASP behaves while circulating out a kick.
Index 03 Page 149
MTC 06
WELL CONTROL MANUAL
DRILLING FLUID VOLUME AND CAPACITIES
In routine operations as well as during well control operations it is necessary to know the total drilling fluid volume and the volume for the individual sections in the circulating system. How much volume does the drill string contain and what is the volume in the different parts of the annulus? These questions can easily be answered if the dimensions of the different components in the drill string and annulus are known. There are two ways to find the different capacities and volumes:
•
By calculating the volumes
•
By reading tables
01.06 Calculating drilling fluid Volume - Capacities The internal capacity of drill pipe and drill collars is calculated based on formulas for cylinders. For a cylinder with a diameter d (inches) and a height of 1 foot the volume will be:
D V=Axh π x d2x h V= [ ft 3 /ft] 4 x 144
1 ft
1 ft2 = 144 in2 1 ft3 = 0.1781 bbl Then: V=
π x d 2 x 0.1781 4 x 144
2
=
d bbl/ft 1029.4
Fig 32 Calculations of annular capacities are basically calculations of a hollow cylinder, or the difference between two cylinders, - one inside the other.
Index 03 Page 150
MTC
WELL CONTROL MANUAL
For a hollow cylinder with an outside diameter OD in and inside diameter ID in and a height of 1 ft the following formula can be derived ID
V ann =
2 2 2 2 OD OD - ID ID = [ bbl/ft ] 1029.4 1029.4 1029.4
The total inside or outside capacity for a certain length of pipe can be worked out by multiplying the capacity in bbl/ft by the length in ft. The result is the capacity in bbl. 1 ft
Example:
OD
Wellbore inside diameter = casing id Vertical depth
= 9-7/8 in = 5000 ft
Drill pipe Drill collars
= 4600 ft = 400 ft
5"OD & 4-1/4"ID 7"OD & 2-13/16”ID
Fig 33 Internal capacities drill pipe: 2
V drill pipe =
(4 1/4) = 0,01754 bbl/ft 1029,4
Total Volume of drill pipe = 0.01754 x 4600 = 80.68 bbl Internal capacities drill collars: 2
V drill collar =
(2 13/16) = 0,00768 bbl/ft 1029,4
Total Volume drill collars = 0.00768 x 400 = 3.07 bbl Annulus Capacities: (9 7/8 )2 - 5 2 V drill pipe = = 0,0704 bbl/ft 1029,4
Total Volume between casing and drill pipe = 0.0704 x 4600 = 323.84 bbl (9 7/8 )2 - 7 2 V drill collar = = 0,04713 bbl/ft 1029,4
Total Volume between casing and drill collars = 0.04713 x 400 = 18.85 bbl Index 03 Page 151
MTC
WELL CONTROL MANUAL
02.06 Drilling fluid Volume and Capacities from Tables It is common practice to use tables that give capacities in bbl/ft or litre/meter for different sizes of pipe and casing. These tables are made taking into consideration the physical outline of the pipes (tool-joint etc). Tables of this kind can be found in different Data Handbooks or in the Drilling Data Handbook (DDH) sixth edition 1991. Section D “Capacities and Annular Volumes” and section G “Pumping and Pressure Losses”. All the tables in DDH are in SI-units, but at the bottom of each table a conversion factor is found in order to convert to oil-field units. Fig 34 Fig. 34 shows an example of a well and drill string. Internal capacity of drill pipe: (table D7) 10000 ft of 5" Drill-pipe , 19.5 lbs/ft, Grade G-105. Reading in table: 9.05 l/m,(9.05 x 0.00192 = bbl/ft)
Drill Pipe 5” - 19.5 lbs/ft 10000 ft
9.05 x 0.00192 bbl/ft x 10000ft = 173.76 bbl
Internal capacity of drill collars: (table D8 ) 500 ft of 7"OD x 2 13/16"ID Drill collar Reading in table: 4.01 l/m,(4.01 x 0.00192 = bbl/ft)
( 4.01 x 0.00192 )bbl/ft x 500 ft = 3.85 bbl Total internal capacity of drill string: 173.76 + 3.85 = 177.61 bbl Volume between drill pipe and casing: ( table D14 ) 7500 ft of Casing 9-5/8”, 47 lbs/ft Reading in table: 24.9 l/m, (24.9 x 0.00192 = bbl/ft)
(24.9 x 0.00192)bbl/ft x 7500 ft = 358.56 bbl Volume between drill pipe and Open-Hole: (table D12) 2500 ft of 8-5/8” Open-Hole Reading in table: 24.4 l/m, (24.4 x 0.00192 = bbl/ft)
(24.4 x 0.00192)bbb/ft x 2500 ft = 117.12 bbl Volume between drill collars and Open-Hole: (table D11) 500 ft of 8-5/8” Open-Hole Reading in table: 12.9 l/m, (12.9 x 0.00192 = bbl/ft)
(12.9 x 0.00192)bbl/ft x 500 ft = 12.38 bbl
Index 03 Page 152
Casing 9-7/8” - 47 lbs/ft 7500 ft
Open Hole - 8-5/8” 3000 ft Drill Collar 7” x 2-13/16” 500 ft
MTC
WELL CONTROL MANUAL
Total capacity of annulus:
558.56 + 117.12 + 12.38
= 688.06 bbl
By making the above calculations the exact quantities of drilling fluid contained in the different parts of the well is known. 03.06 Surface-to-Bit Strokes & Bit-to-Surface Strokes The exact number of strokes required to pump from the surface through the drill string to the bit, is known as surface-to-bit strokes. The number of pump strokes required to pump from the bottom of the well to the surface, is known as bit-to-surface strokes. These values can be calculated when the pump displacement per stroke is known. Pump displacement can be found in the DDH Section G table G6. Given: National pump 12-P-160. w/ 6" liners. The number 12 represents the stroke length in inches. Volumetric efficiency 97 %. From the table is read 16.68 l/stroke with volumetric efficiency of 100 %. At the bottom of the table a conversion factor is found to convert into bbl.
16.68 x 0.264 = 0.1048 bbl/stroke 42 With 97 % efficiency the pump output would be:
0.1048 x 97 = 0.1017 bbl/stroke 100 By using the capacity figures in fig. 34 we can now calculate surface-to-bit strokes as follows:
Total inside volume of drillstring = Strokes Mud pump output per stroke Surface-to-bit strokes
Surface → bit strokes =
177.61 = 1746 strokes 0.1017
Respectively bit-to-surface strokes is now calculated. Bit-to-surface strokes
Total annulus capacity = Strokes Mud pump output per stroke Bit → surface strokes :
688.06 = 6765 strokes 0.1017
Index 03 Page 153
MTC
WELL CONTROL MANUAL
Bit → surface time =
6765 = 225.5 minutes 30
The circulating time required is controlled by the speed of the drilling fluid pump. In case of a pump speed of 30 strokes per minute ( SPM ) the result would be:
Surface → bit time =
1746 = 58.2 minutes 30
Another volume that is often necessary to know is the bit-to-shoe time and the corresponding pump strokes. Considering fig. 34 it can be seen that:
Bit → shoe strokes =
117.12 + 12.38 = 1273 strokes 0.1017
Therefore:
Bit → shoe time (at 30 SPM) =
1273 = 42.4 minutes 30
Index 03 Page 154
MTC
WELL CONTROL MANUAL
04.06 Use of barite to increase the drilling fluid density The theoretic and actual quantity of barite used to effect a drilling fluid density increase can be calculated beforehand by using the initial drilling fluid density MW ( ppg ) and the drilling fluid density required MWf ( PPG ) (final drilling fluid density). The units will be number of 100 lb sacks per 100 bbl of drilling fluid. Example: An active drilling fluid system contains 900 bbl of drilling fluid with a weight of 10.5 ppg. We want to increase this density to 13.5 ppg by adding barite. How many sacks will be used?
MWf - MWi 0 1
100 lb Sacks Theoretical
MWf 9 10
100
2 3 4 5 6 7 8 9
100 lb Sacks Actual 0
11 200 300 400
12
200
13
300
14
400
15
500
16
600 700 800 900
10
100
17 18 19
500 600 700 800 900 1000 1200 1400
Fig 35 l.
2.
In the homograph fig 35 a straight line is drawn on the scale from 13.5 ppg MWf (final drilling fluid density) to 3.0 ppg on the scale to get MWf - MWi(final drilling fluid density minus initial drilling fluid density). The scale reads 204 sacks per 100 bbl on the scale for theoretical use of 100 lb sacks. By taking the point on the scale for theoretical use where the first line crosses (i.e. 204 sacks) and by drawing a horizontal line across to the scale for actual use from this point, the actual true value is seen to be 224 sacks (100 lb sacks) per 100 bbl of drilling fluid to effect the desired increase. Index 03 Page 155
MTC 3.
WELL CONTROL MANUAL
Therefore: 224 x
900 = 2 0 1 6 sa cks 100
2016 sacks in the 900 bbl system is required to increase the drilling fluid weight to the desired level. The theoretical quantity of sacks per 100 bbl of drilling fluid can be calculated by the following expression:
S = 1490 x
where S MWf MWi
MW f - MW i 35,5 - MW f
= theoretical number of 100 lb sacks of barite = final drilling fluid weight (ppg) = initial drilling fluid weight ((ppg)
35.5 = the calculated density of barite is considered to be 35.5 ppg. It is always necessary to use more barite than the theoretical quantity because of hydration, variations in barite density and volume increases because of addition of other material. 05.06 Volume increase due to barite addition The volume increase (in barrels per 100 bbl of drilling fluid in the system) can also be calculated by initial drilling fluid weight MWi (ppg.) and final drilling fluid weight MWf (ppg.). Example: An active drilling fluid system contains 900 bbl of drilling fluid with a weight of 10.5 ppg. We want to raise this weight up to 13.5 ppg. by adding barite. How much volume increase will we have in the system? 1.
In the homograph fig. 36 we draw a straight line between 13.5 ppg. on the scale for MWf and 3.0 ppg. on the scale for MWf - MWi, and we notice where this line crosses the Pivot Line.
2.
Where our first line crosses the Pivot Line we draw a horizontal line across to the scale for volume increase and we can read-off that there will occour a 22.5 bbl per 100 bbl increase in drilling fluid volume.
Index 03 Page 156
MTC
WELL CONTROL MANUAL
MW f - M W i 0
MW f 9
1
10
2
11
Volum e Increase 0
10
12
20
13
30
5
14
40
6
15
3
2 1
4
OT
16
L IN E
8
PIV
7
17
9
18
10
19
50 60 70 80 90 100 120 140
Fig 36 3.
22.5 x
900 = 202,5 bbls increase ∈ volume 100
Therefore total volume = 900 + 202.5 = 1103 bbl after completion of weight increase. The volume increase can be calculated with the help of the following expression:
V = 155 x C x
MW f - MW i 35.5 - MW f
where V
= the volume increase (bbl/100 bbl)
C
= factor for extra barite, based on MW
MWf
= final drilling fluid weight (ppg.)
MWi
= initial drilling fluid weight (ppg.)
This expression assumes that 1.5 gallons of water are used per sack of barite to replace water lost on account of hydration, and a dry barite volume factor of 14.9 sacks per bbl.
Index 03 Page 157
MTC 07
WELL CONTROL MANUAL
WELLBORE KICKS
01.07 Kick occurrences A kick can occur when the formation pressure becomes higher than the hydrostatic pressure that the drilling fluid column is exerting in the wellbore. The influx of fluid or gas into the wellbore further reduces the hydrostatic pressure, which results in increased flow at the surface and therefore further influx from the formation. The influx into the well bore shall therefore be stopped as rapidly as possible by closing-in the well. There are two normal reasons why the formation pressure can exceed the hydrostatic pressure in the wellbore: 1.
Pore pressure or formation pressure increase more rapidly than drilling fluid weight
2.
The drilling fluid weight is sufficient to balance the formation when the well is full of drilling fluid, but when the height of the drilling fluid column is reduced for some reason hydrostatic pressure is reduced.
A kick (influx) can be caused by any of the following: 1.
Insufficient drilling fluid weight
2.
Failure to keep well full of drilling fluid
3.
Swabbing
4.
Lost circulation
5.
Drilling fluid cut by gas or water
6.
Abnormal pressure zones
1.
Insufficient drilling fluid weight
This should seldom be the cause of a kick in development wells where formation pressures are known. At a wildcat well where the pressures of the formation are partly unknown the danger for insufficient drilling fluid weight is much greater. In Normal Pressured Formations the pressure gradient is taken as 0.465 psi/ft. of depth. This is the figure for salt water having a salinity of about 100,000 parts per million (ppm). The drilling fluid density required to balance this pressure would be approx. 9 ppg. It must be remembered that the overbalance increases with depth if the formation pressure gradient remains constant. See Fig 37.
Index 03 Page 158
MTC
WELL CONTROL MANUAL Mud Column Pressure 10 ppg
Formation Pressure 0.465psi/ft
Over Balance Pressure
5.000 ft
2600 psi
2325 psi
275 psi
10.000 ft
5200 psi
4650 psi
550 psi
15.000 ft
7800 psi
6975 psi
825 psi
DEPTH
Hole Depth
Overbalance pressure increases with depth
Pf
Ph
PRESSURE
O/B
Fig 37 2.
Failure to keep the well full of drilling fluid
This particular cause of well kicks is one, which should never happen today, but it still does. When a stand of drill pipe is pulled from the well, the volume of the metal pulled must be replaced with drilling fluid. If this is not done, the level of the drilling fluid in the well will drop. Since the bottom hole hydrostatic pressure is the product of the drilling fluid density multiplied by the height of the column, the bottom hole hydrostatic pressure will reduce if the height of the column is reduced. If this reduction in height is appreciable, the bottom well hydrostatic pressure may be reduced to such an extent that the safety margin may be taken away and the well may kick.
DEPTH
Different measurements can indicate if the proper amount of drilling fluid is pumped into the well. One possibility is a pit volume monitoring, but large pits will not show small changes; these can best be seen in trip tanks. This is one or more high tanks with a little cross-section, where a little change in volume is easy to see. It should be near the rig floor and calibrated so the Driller can easily see and compare the volumes pumped into the well versus steel pulled out. Another possibility is that the Driller by help of a stroke counter can check the amount of drilling fluid pumped into the well from the pits. Fig 38 384 ft 500 ft Example: If, while pulling out of a well at 8000' carrying 200 psi hydrostatic overbalance with 10 ppg. drilling fluid, the drilling fluid level was allowed to drop to 384 ft. below the surface, the well would be just on balance. Pf Ph If the level was allowed to drop to 500 ft. a kick would develop. See Fig 38 384 x 10 X ,052 = 200 psi = balance 500 x 10 x ,052 = 260 psi = 60 psi underbalance 3.
Swabbing Index 03 Page 159
PRESSURE
U/B
O/B
MTC
WELL CONTROL MANUAL
Several things can cause swabbing: a.
Balled bit
b.
Pulling pipe too fast
c.
Poor drilling fluid properties
d.
Heaving or swelling formations
a.
Balled bit (or Stabilisers, Reamers, or Drill Collars) - When pipe is pulled it acts somewhat like a piston or swab, more so if a bit or other bottom assembly member is balled up. This pulls all or most of the fluid up the well, directly reducing the hydrostatic head on the formation. If the well is almost at balance, only a few feet swabbed can result in a kick, or potential blowout.
b.
Pulling pipe too fast - This piston action is enhanced when pipe is pulled too fast. The rig supervisor should be sure that the pipe is pulled slowly of bottom for a reasonable distance. However, the well should be watched closely at all times to be sure it is taken the correct amount of fluid. Fig 39 show recommended pulling speed w/16.9 ppg mud in the wellbore.
c.
Drilling fluid properties - Swabbing problems are compounded by poor drilling fluid proper-ties, such as high viscosity and gels. Drilling fluid in this condition tends to cling to the drill pipe as it moves up or down the well, causing swabbing coming out and lost circulation going in. 300 280 260 240 220
Sec. Pr Stand
200 180 160 140 120 100 80 60 40 20 0
1000
2000
3000
4000 BIT DEPTH
Fig 39
Index 03 Page 160
5000
6000
7000
800
MTC d.
WELL CONTROL MANUAL
Heaving or swelling formations - Swabbing can result if the formations exposed either heave or swell, effectively reducing the diameter of the well and clearance around the bit or stabilisers. In these regions even a clean bit acts like a balled bit or stabiliser.
Normal good practices to prevent or minimise swabbing are aimed at keeping the drilling fluid in good condition, pulling the pipe at a reasonable speed, and using some type of effective lubricant drilling fluid additive to reduce balling. Additives such as blown asphalt, gelsonite, detergent, and EP additives are effective in many cases. Good hydraulics will often help clean a balled-up bit or bottom well assembly. If the well does swab, in spite of best practices, the pipe should be run back to bottom immediately, the drilling fluid circulated out, and its weight increased before making the trip. Sometimes a short trip is made to see if the well actually swabs when several stands of pipe are pulled. 4.
Loss of circulation
Following can cause loss of circulation: a. b. c. d.
High drilling fluid weight Going into well too fast Underground blowouts Pressure due to annular circulating friction
a.
High drilling fluid weight - If the hydrostatic head of the drilling fluid exceeds the fracture gradient of the weakest exposed formation, circulation is lost and the fluid level in the well drops. This reduces the effective hydrostatic head acting against the formations that did not break down. If the drilling fluid level falls far enough to reduce the bottom hole pressure below the formation pressure, the well will begin flowing. Thus, it is important to avoid losing circulation. Should returns cease, loss of hydrostatic head can be minimised by immediately pumping measured volumes of water into the well. Measuring the volumes will enable the drilling supervisor to calculate what density of drilling fluid the formation will support without fracturing.
b.
Going into well too fast - Loss of circulation can also result from too rapid lowering of the drill string. This is similar to swabbing, only in reverse; the piston action forces the drilling fluid into the weakest formation. This problem is compounded if the string has a float in it and the pipe is large compared to the well. Particular discretion is required when running pipe into a well having exposed weaker formations and heavy drilling fluid to counter high formation pressure. Fig 40 show recommended running speed w/16.9 ppg mud in the wellbore.
c.
Underground blowouts - Loss of circulation due to any cause can create a condition known as an underground blow out. This happens when the hydrostatic pressure around a permeable formation is reduced below the pressure value in that formation. Fluids can then produce into the well and flow uncontrolled into the zone that has broken down. The situation can be very difficult to control, and the well is usually lost below the formation that is broken down. It is therefore very important that loss of circulation is avoided. Index 03 Page 161
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300 280 260 240 220
Sec. Pr Stand
200 180 160 140 120 100 80 60 40 20 0
1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 BIT DEPTH
Fig 40 d.
Pressure due to annular circulating friction - Another item to be considered when drilling with a heavy drilling fluid near the fracture gradient of the formation is the pressure added by circulating friction. This can be quite large, particularly in small wells with large drill pipe, stabilisers, or large drill pipe rubbers inside the protective casing. It is sometimes necessary to reduce the pumping rate to lower the circulating pressure.
5.
Cut by gas or water.
a.
Drilling fluid cut by gas: Gas cutting of the drilling fluid need not always indicate that kick has occurred. When a porous gas zone is drilled the gas in the pores of the cuttings will be released as the cuttings approach the surface. This will happen despite the fact that a good 200 psi overbalance is carried in drilling fluid column density. Provided the drilling fluid viscosity and gel strength is low, this is no problem and the drilling fluid can easily be degassed at the surface and go back into circulation at full density. If this gas is not released at the surface and is allowed to continually recycle, problems will crop up. When in doubt stop the pump and observe the well for flow.
b.
Drilling fluid cut by water: If drilling fluid density is reduced by the addition of water there must be a corresponding rise, equal to the amount influx, in the drilling fluid pits. Therefore, this should seldom happen. If it does, the pit level and flow rate indicators are not functioning.
Index 03 Page 162
MTC 6.
WELL CONTROL MANUAL
Abnormal pressure
Usually a formation with such pressures gives enough warning that proper steps can be taken. Once these zones are detected, it is normally possible to drill into them a reasonable distance while raising the drilling fluid weight as necessary to control gas entry. However, when pressure due to drilling fluid weight approaches the fracture gradient of the highest exposed formation, it is good practice to set casing. Failure to do this has been the cause of many underground blowouts and lost or junked wells. 02.07 Warning signals It is impossible for a blowout to occur under normal conditions without warning of its development. The wellbore and the drilling fluid system is a closed circulation system, and any influx from the formation into the system will show up in the form of increasing returns from the annulus and an increase of total drilling fluid volume in the surface system (drilling fluid tanks). Often while drilling we can get indications at the surface that we are entering a transition zone, that is to say a zone where pressure increases slowly because of the formations relatively slow change of compaction, but sometimes such formations are difficult to interpret. Normally we will have many clear indications of increasing formation pressure before a kick occurs. The following points show the indications that we can often receive at the surface before or when a kick has occurred: 1.
While drilling: a. Drilling rate increase - drilling breaks b. Gas in return drilling fluid - gas-cut drilling fluid c. Chlorides in return drilling fluid - salt water cut drilling fluid d. Change in the density of cuttings e. Change in the size of cuttings f. Fall in circulation pressure g. Temperature increase in return drilling fluid h. Increase in R.P.M. (rotary speed) i. Increase in flow from the wellbore j. Increase in volume in drilling fluid pits (pit gain)
2.
While tripping or while making connections: a. b. c. d. e. f.
Increase in flow from the wellbore Trip gas Connection gas Well-fill after a trip "Tight" well on connections Wellbore not taking the correct amount of drilling fluid to compensate for pipe taken out.
Index 03 Page 163
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WELL CONTROL MANUAL
03.07 Warning signals while drilling a.
An increase in penetration rate can often be a sign of drilling into a softer formation. Pump pressure can also change because the drilling fluid is simply cleaning out the cuttings under the bit better than previously. These two examples are not of course signals that a kick is about to occur. We discussed earlier also that penetration rate is also dependent upon differential pressure. An increase in penetration rate can also indicate, therefore, that differential pressure is known to be reduced and there is danger of taking a kick. An increase in penetration rate must always be noted and acted upon. The bit must be picked up off bottom, the drilling fluid pumps must be stopped, and 6 8 10 12 the well must be checked for flow. 2 4 A drilling break is a sudden change in penetration rate from a low to a higher value. This sudden change in penetration can vary considerably depending upon the actual formation type. In some cases a "break" can be from between 10 ft. to 50 ft./hour, in others maybe only 5 ft. to 10 ft./hour. In all cases where drilling is conducted in areas that are unknown or where high pressures are expected, after a relatively long period of slow drilling is followed by faster drilling, no more than between 2 to 4 feet should be drilled before the pumps are shut down and the well checked for flow. See Fig 41
12:00 12:15 12:30 12:45 13:00 13:15 13:30 13:45 14:00 14:15
A negative drilling break could also be a warning sign that a cap rock is being penetrated and possible higher pressure is contained in the formation below the cap rock. b.
Fig 41
Background gas increases quite suddenly if the bit penetrates a zone of higher pore pressure. This background gas is not gas that intrudes into the wellbore from the formation but gas which is contained between the wellbore cuttings. If this gas has a high pore pressure it will expand considerably on the way up to the surface and may make up 50% of the drilling fluid volume. Such a situation is not so critical if it is properly treated. This gas is removed from the drilling fluid at the surface with the help of a “Degasser”. If the drilling fluid is not properly degassed before it is pumped back down the well the hydrostatic pressure in the well will be lowered and the chance for a kick to occur is possibly. On the other hand, gas in the return drilling fluid could mean that there actually exists an underbalance in the well and gas is intruding. In such a case this is a real kick situation and the necessary steps to contain it must be made immediately.
Index 03 Page 164
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WELL CONTROL MANUAL
c.
The chloride content in drilling fluid, (fresh-water based drilling fluid) will normally increase when high-pressure zones are penetrated. However, this increase is impossible to notice when salt-water based drilling fluid, or drilling fluid with high chloride content, is in use. This indication therefore is not reliable enough on its own to be of any use to us in indicating high pressure zones.
d.
The density of rock formation will nearly always be reduced if it is associated with a high pressure zone. This is because it will have a greater porosity. This is a good indicator if it is possible to examine different cuttings at the shale shaker, and with the help of S.P.M. (Pump speed) and annulus capacity decide from which depth they originate.
e.
The size of the cuttings often suddenly change when a high-pressure zone is penetrated, they can become long and splintery in shape.
f.
Changes in pump pressure are a direct result of changing resistance (friction) in the drilling fluid, if formation fluids or gas penetrate the wellbore and intermingle with the drilling fluid. However, it will only be a small part of the drilling fluid in the annulus that becomes affected in this way. Pump pressure will normally fall if a kick occurs, as part of the drilling fluid in the wellbore becomes lighter through reduction in weight and viscosity. If the kick is a gas kick it is possible that the gas forces its way up the annulus of its own accord and pushes the drilling fluid ahead of it. This will cause large pressure fluctuations. STROKES
STROKES
110 PRESSURE
112 PRESSURE
165.5
162.5 Fig 42
A reduction in pump pressure can in some cases give an increase in pump speed. This occurs because of the decreased load on the pump. However, some rigs have drilling fluid pumps that are self-regulating, which is to say that regardless of what loads are imposed on the pumps they will automatically use less or more energy and maintain a constant pre-determined speed. See Fig 42 We should also be aware that pressure reductions can occur through reasons other than kick situations, such as washouts in the drill string etc. g.
Flow line (return drilling fluid) temperature often increases when a high pressure zone is penetrated, but although this has been observed in many places throughout the world it is not a particularly trustworthy indication on its own. Drilling fluid temperature Index 03 Page 165
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WELL CONTROL MANUAL
can often increase when caustic soda and barite are added, well geometry can also cause temperature increases (higher drilling fluid velocities). A clear and uniform temperature increase that could possibly indicate a formation with a high pressure is best seen when shown graphically in detail. h.
Rotary table speed (R.P.M.) often increases when a high pressure zone is penetrated. This is because the formation is breaking up easier and, therefore, offering less resistance to the bit.
i.
Increasing flow at the flow-line is immediately the first signal that a kick is occurring. This indication is called a “positive kick indicator” and require no flow check, but an immediately shut in of the well to minimise the size of the influx. See Fig 43
Fig 43 j.
An increase in pit volume will always occur when fluid or gas enters the wellbore, because a proportional amount of drilling fluid is displaced out of the well and into the drilling fluid pits. Any unexplained pit gain is a sure sign of a kick and is also called a “positive kick indicator” where the necessary precaution and steps must be carried out immediately.
Index 03 Page 166
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WELL CONTROL MANUAL
04.07 Warning signals while tripping or making connections a.
If drilling fluid returns are observed at the flow-line when the pumps are not running this is a certain sign that formation fluids are flowing into the wellbore. Therefore, the annulus becomes underbalanced and drilling fluid is displaced into the drilling fluid pits. See Fig 43
Pf
PRESSURE
DEPTH
DEPTH
Ph
Pf
Ph+Pl
Pl annulus
Ph
PRESSURE
Fig 43 b.
Trip gas, which is gas that permeates into the wellbore during a trip, will normally increase when a high-pressure zone is penetrated, and drilling fluid weight is not increased to counter balance this. This trip gas is measured by a gas detector at the flow-line that continuously monitors the drilling fluid and will be seen as a peek on the chart during first circulation bottoms up after a trip. Trip gas alone is not a reliable kick indicator.
c.
Connection gas is the name given to the gas which penetrates into the wellbore when circulation is stopped and a new length of pipe added to the drill-string. This connection gas will always increase as a rule when a high pressure zone is penetrated. Connection gas is also monitored by the gas censor at the flow line and is normally not a problem as long the gas is removed from the drilling fluid and not recirculated. To avoid reducing pressure hydrostatic in the annulus more that one slug of connection gas should not be circulated out at any given time.
d.
Well-fill after a trip accompanied by an increase in trip gas can indicate high pressure, but can also be caused by other factors such as poor drilling fluid qualities, swelling formations and incorrect well-filling procedures so therefore it is unreliable in itself as an indicator.
e.
"Tight" well, which is when the formation closes back in on the drill string, can occur when connections are made and can indicate high pressure. This condition can also warn us that there is a danger of the drill string becoming stuck (sometimes permanently).
f.
When the drill string is pulled out of the well the volume of steel which it comprises must be replaced by equivalent volume of drilling fluid, this is achieved by pumping Index 03 Page 167
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measured amounts of drilling fluid into the well as the drill string is removed. The well shall at all times be kept full of drilling fluid. The amount of drilling fluid needed to fill the well on a trip must be calculated before-hand and the amount used on the trip must be identical, if the amount becomes dissimilar the reasons must immediately be found. This quantity is usually checked every 5 stands. If the well is taking too small an amount of drilling fluid, formation fluids are intruding into the wellbore, and if the well is taking too much drilling fluid, drilling fluid is flowing into the formation, both situations are highly dangerous and must be controlled. 05.07 Procedure for shutting in the well If we are drilling ahead and for any reason we have cause to think that a kick may be developing, the well must immediately be checked for flow. If there is no flow and everything is in order we go back to drilling. If the well is flowing, we shut the well in either using a soft shut-in or a hard shut-in procedure. Soft shut-in procedure: 1.
Pick-up from bottom and position drill string, shut down mud pumps and rotation. Flow check. Well flowing.
2.
Open hydraulic side outlet choke valve.
3.
Close BOP (Ram or Annular preventer).
4.
Close adjustable hydraulic choke.
5.
Record SIDPP – SICP – Pit Gain.
Hard shut-in procedure: 1.
Pick-up from bottom and position drill string, shut down mud pumps and rotation. Flow check. Well flowing.
2.
Close BOP (Ram or Annular preventer).
3.
Open hydraulic side outlet choke valve.
4.
Record SIDPP – SICP – Pit Gain.
If it is a positive kick indication that is observed keep in mind that no flow check is carried out, but the well is shut in instantly. Remembering what has been said about MAASP, we must observe the casing pressure as it begins to rise and ensure that it does not exceed the pre-determined MAASP value. Now that the well is shut-in, the pressure in bottom of the well will soon come into balance with the formation pressure. The different between the two existing methods to close the well in is that the Hard Shut-in Procedure reduces the amount of influx into the wellbore with resulting lesser annulus pressure and surface pressure when circulating out the kick. Index 03 Page 168
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The purposes of the shut-in procedure are: 1.
Stop the influx into the wellbore.
2.
Provide a safe rig environment.
3.
Start kill procedures.
The purpose of raising the bit from bottom of the well is: a.
Less chance of getting stuck.
b.
More easy to get free if stuck ( you can go up or down ).
c.
Kelly cock is above rotary table. (if Kelly is used)
d.
Ram type preventer can be used if correctly spaced out .
e.
The Kelly can be removed.
f.
Ability to run wire line tools into the well.
Index 03 Page 169
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WELL CONTROL MANUAL
06.07 Pressure after shut In Fig. 44 and 45 shows the situation just after the well is shut in. On account of the influx in the bottom of the well there can now be read pressure on the standpipe (PSIDPP) and pressure on the casing (PSICP). The cause for the kick is an increase in the formation pressure PF. PSIDPP NATIONAL
PSICP
PSICP PSIDPP
BOP
Gradient of mud
PSIDPP
PSICP
+
+
PHDP
PHA
D E P T H
PH
PH
Gradient of influx Annulus
Drill Pipe
PF
Pf
PRESSURE
PF
Fig
45 Fig 44 This new pressure will be the sum of the hydrostatic pressure from the column of drilling fluid in the drill pipe (PHDP) and the pressure on standpipe (PSIDPP). The new pressure of the formation will also be the sum of the hydrostatic pressure from the column of drilling fluid-gas in annulus (PHA) and the pressure on the casing (PSICP). PHDP + PSIDPP = PF = PHA + PSICP The pressure reading on the standpipe PSIDPP alone will be determined by the pressure of the formation (PF). The pressure reading on the casing (PSICP) will be determined by both the pressure of the formation and the amount of gas, which is flowed into the wellbore. Gas has a pressure gradient of @ 0.17 psi/ft. Drilling fluid with a weight of 10 ppg has a pressure gradient of 0.52 psi/ft. This means that if more gas is allowed to flow into the wellbore, the hydrostatic pressure (PHA) from the column of drilling fluid+gas be get even lower, as PF = PHA + PSICP. Fig 45 shows this connection from 3 different quantities of influx. PSIDPP and PSICP are gauges connected to the bottom of the well via the drilling fluid. They can be used to calculate the kill drilling fluid density for a kick or to see how much pressure a formation can stand before losing circulation, such as with a leak off test.
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WELL CONTROL MANUAL
For well control the PSIDPP is used to calculate the kill drilling fluid density required for killing a well with a certain influx. The drill pipe is full of clean and homogeneous drilling fluid newly treated from the pits. To know how much to increase the drilling fluid density to kill a well, it is necessary to know how much the original drilling fluid density is to begin with and the PSIDPP shown on the drill pipe gauge on the choke panel. The annulus or casing has cuttings and gas or salt water in it, so it is much harder to determine an accurate drilling fluid weight increase from it. The calculation of kill drilling fluid weight is made as follows:
Kill MW =
P sidpp + MW 1 TVD x 0,052
Where: Kill MW =
the drilling fluid density required balancing the pressure in the formation.
PSIDPP =
the read back pressure on the standpipe after the well is shut in and the pressure stabilised.
TVD
the true vertical depth of the well.
=
0,052 =
a constant which tells how much the hydrostatic pressure will be changed for every feet fluid column at a fluid with a density equal to 1 PPG.
MW1
Original drilling fluid density while drilling.
=
Fig. 46 shows how to figure the drilling fluid density increase from PSIDPP out from a Chart: PSICP can together with PSIDPP be used to calculate the pressure gradient (density) for the influx by using the following formulae: Height Influx(TVD) ft Gradient of influx (psi/ft) = MW x 0.052 — ------------------------------------------SICP —SIDPP (psi)
Kick Size (bbl) Height of Influx along hole = ----------------------------------------Annular Volume (bbl/ft)
Index 03 Page 171
MTC
WELL CONTROL MANUAL Increase required to balance a kick (lb/gal) SIDPP SIDPP x 19.2 Lb/galincrease = -------------------- = -----------------Depth x 0.052 Depth SIDPP 300 400 500 600 700 800
100
200
1000
1.9
3.8
5.8
7.7
9.6
11.5
13.5
15.7
17.3
19.2
2000 3000
1.0
1.9
2.9
3.8
4.8
5.8
6.7
7.7
8.6
9.6
0.6
1.3
1.9
2.6
3.2
3.8
4.5
5.1
5.8
6.4
4000
0.5
1.0
1.4
1.9
2.4
2.9
3.4
3.8
4.3
4.8
5000 6000
0.4
0.8
1.2
1.5
1.9
2.3
2.7
3.1
3.5
3.8
0.3
0.6
1.0
1.3
1.6
1.9
2.3
2.6
2.9
3.2
7000
0.3
0.6
0.8
1.1
1.4
1.7
1.9
2.2
2.5
2.8
8000 9000
0.2
0.5
0.7
1.0
1.2
1.4
1.7
1.9
2.2
2.4
0.2
0.4
0.6
0.9
1.1
1.3
1.5
1.7
1.9
2.1
0.2
0.4
0.6
0.8
1.0
1.2
1.3
1.5
1.7
1.9
0.2
0.4
0.5
0.7
0.9
1.1
1.2
1.4
1.6
1.8
0.2
0.3
0.5
0.6
0.8
1.0
1.1
1.3
1.4
1.6
13000 14000
0.1
0.3
0.4
0.6
0.7
0.9
1.0
1.2
1.3
1.5
0.1
0.3
0.4
0.6
0.7
0.8
1.0
1.1
1.2
1.4
15000
0.1
0.3
0.4
0.5
0.6
0.8
0.9
1.1
1.2
1.3
16000
0.1
0.2
0.4
0.5
0.6
0.7
0.8
1.0
1.1
1.2
D E P 10000 T 11000 H 12000
900
1000
Fig 46 Rising pressures after shut-in: Often the drill pipe and casing pressures do not stop, but continue to rise. This could be due to: 1. 2.
Low permeability Percolation of gas up through the drilling fluid
Low permeability: If the permeability of the formation in the kick zone is low, then the influx will come slowly. There will go some time before the influx can create a pressure in the top of the drill string and the annulus respectively, which added to the hydrostatic pressure can balance the pressure in the formation. You must therefore wait until the pressures have stabilised before the accurate PSIDPP and PSICP can be read. Percolation: If the slowly rising pressure is due to gas percolating up the well the pressure does not represent reservoir pressure, but is due to the low density of the gas. On account of this, the gas will raise up through the drilling fluid without expansion. If this situation is handled properly it will cause no major problems. How the situation must be handled is mentioned in section 11 the volumetric method. Index 03 Page 172
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Low or no pressures on standpipe (PSIDPP) Low pressure: If there is no PSIDPP after the well is Shut-in following could be the reason: 1. 2. 3. 4.
The gauges are broken, malfunctioning or shut off. There is a float in the drill pipe. The well is in balance. The drill string is plugged.
If there is no float install in the drill string, check the gauges on the standpipe manifold to see that this is not the problem. Change gauges as required after isolation to obtain SIDPP. Float in the drill pipe: If there is a float in the drill string the SIDPP may be zero. Some floats have a 3/16" hole drilled through the float witch will allow the pressure to build up slowly on the drill pipe site. If the float valve provides a complete shut off there are several ways to check for the true shut in pressure. 1.
Pump as slowly as possible (3 to 5 SPM) until the casing pressure starts to rise. Then stop pumping. The pressure after the pump stops should be PSIDPP.
2.
Slowly bring the pump up to kill rate holding casing pressure constant. The circulating drill pipe pressure is identical to the ICP (initial circulating pressure). The PSIDPP can now be calculated using the formula below: PSIDPP =
Circulating drill pipe pressure – Pre-recorded kill rate pressure.
Index 03 Page 173
MTC 8
WELL CONTROL MANUAL
CIRCULATING A KICK OUT OF THE WELLBORE
01.08 General points It can be seen by the calculations in chapter 02 of this book, that the bottom hole pressure in a well shut in will be balanced by the hydrostatic pressure (both annulus and drill string) and pressure at the surface (casing and standpipe pressure). As long as this bottom hole pressure is held constant no more formation fluid/gas can intrude into the wellbore. If the bottom hole pressure is allowed to fall below the formation pressure, a fresh influx will enter the wellbore and we will have to deal with a second kick. If the bottom hole pressure is increased too much there is a possibility to break down the formation resulting in losses and further complications to the well control problem. To get the influx out of the well, drilling fluid is pumped down the drill string. This displaces the influx higher and higher up the annulus until it reaches the surface where it is vented out of the wellbore via the choke. This can be achieved by holding the bottom hole pressure constant during circulation (i.e. the bottom hole pressure that was registered when the well was shut in). How can it be known at the surface that bottom well pressure is being held constant, under circulation? We can deduce that if there is no change in the height of the drilling fluid column or drilling fluid properties and, furthermore, no change in the pressure at the surface acting on the drilling fluid column there will not be any change in bottom hole pressure. Therefore we have the possibility of observing changes in the bottom hole pressure by way of the gauges installed respectively on the standpipe and casing. If the bit is at the bottom of the well it is normal practice to use the standpipe (drill string) pressure as a bottom hole pressure indicator. If the drilling fluid weight in the drill string remains constant, a constant standpipe pressure will indicate a constant bottom hole pressure. Well killing methods: There are several methods recognised within the industry to control formation pressure while circulate out a kick and the primary object regardless of method is to keep constant bottom hole pressure. In this manual we will focus on the first three mentioned methods as shown below.
•
Driller’s Method.
•
Wait and Weight Method.
•
Volumetric Method
•
Concurrent Method
Index 03 Page 174
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WELL CONTROL MANUAL
02.08 Circulating out an influx using the driller's method This method is also called the "Constant Drill-Pipe Pressure Method" and consists of two steps. First step is to circulate the kick out of the wellbore without changing the drilling fluid density. Second step is to displace the original drilling fluid out of the well bore with heavier drilling fluid (Kill Mud) which will exert enough hydrostatic pressure to balance the formation pressure. After taken an influx and shutting in the well, pressure will build up on the standpipe and casing gauges because of the hydrostatic underbalance (drilling fluid weight too low to balance formation pressure). This pressure is known as "Shut In Drill pipe Pressure" PSIDPP. As long as the drill string contains drilling fluid of the original weight, PSIDPP will always exist as an extra pressure registered at the surface which in addition to hydrostatic pressure will balance formation pressure. When the influx is circulated out, the pump will have to overcome the PSIDPP + the friction losses in the circulating system at the desired pump rate. The friction losses in the circulating system has been determined previously when checking the dynamic pressure loss (PL) or SCR (Slow circulating Rate), and the slight increase due to friction losses in the annulus is very small and therefore not taking into consideration when circulating out the influx. Where and when is the value for dynamic pressure loss (PL) found? PL is the friction loss in the system at a decided pump speed (reduced pump rate). These pressures are recorded at several different reduced pump rates, for example at 20 -, 30 -, and 40 SPM. The pressure is recorded from the remote choke panel and noted on the prerecorded kill sheet. The PL is normally recorded at the beginning of each shift. Other factors could require the PL to be recorded more frequently such as:
• • •
Change in drilling fluid properties. Change in drill string configuration. Very fast drilling.
The pump pressure at initial start of kill operation is called Initial Circulation Pressure ICP and is registered on the standpipe gauge on the remote choke panel. To reach the ICP while keeping constant bottom hole pressure the pumps are slowly brought up to desired reduced rate (PL) while keeping casing pressure constant by manipulating the choke. At the desired pump rate the drill pipe pressure is identical to the ICP. ICP = PL + SIDPP
Index 03 Page 175
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WELL CONTROL MANUAL
What happens to the casing pressure as an influx is circulated out of the wellbore? If the influx is fluid (water or oil), the casing pressure will remain constant until the influx begins to vent at the choke. If the influx is gas, the gas must be allowed to expand as it rises up through the annulus, to ensure that bottom hole pressure does not increase. In this situation more drilling fluid is displaced out of the wellbore through the choke than pumped into the well. Therefore the drilling fluid pit level will increase. This also means that when the height of the drilling fluid column in the annulus is reduced and the column of gas increased, a loss of hydrostatic pressure takes place. Increasing surface casing pressures will be seen on the casing gauge. The expansion of gas depends of the drilling fluid properties and type. See Fig 47. FLUID INFLUX GAS IN WATER BASE DRILLING FLUID
1500 1400
GAS IN OIL BASE DRILLING FLUID
1300 1200 CASING PRESSURE
1100 1000 900 800 700 600 500 400 300 200
SICP
SIDPP
100 0
1000
2000
3000 4000 5000 STROKES - BIT TO SURFACE
6000
7000
8000
Fig 47 To ensure that bottom well pressure does not change as a kick is being circulated out standpipe pressure must remain constant all the time. When the influx is circulated out the pump can be stopped and the well closed. Standpipe pressure and casing pressure will now have the same value (PSIDPP) as both the drill pipe and the annulus is filled with a homogeneous column of original drilling fluid and no further influx has taken place. The next step consists of replacing the original drilling fluid with a heavier drilling fluid (KMW) which will create sufficient hydrostatic pressure to balance the formation pressure. The drill string is filled gradually with heavy drilling fluid and therefore the hydrostatic pressure inside the drill string will change. The drill pipe pressure must be allowed to decrease and can for that reason not be held constant, but as long as the heavy drilling fluid is confined inside Index 03 Page 176
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WELL CONTROL MANUAL
the drill string there will be no change of drilling fluid in the annulus and therefore no change in pressure. We can hold casing pressure constant until the heavy drilling fluid has reached the bit. The new standpipe pressure observed at this stage is the final circulating pressure (FCP) and held constant until the annulus is full of heavy drilling fluid. If the new drilling fluid is the correct weight the well should now be "killed" (dead) and standpipe and casing pressure should be zero when pumps are stopped. KMW FCP = PL x -----------------OMW Drillers method 1st circulation: Well Kick Data: Hole size Hole depth TVD/MD Casing (9 5/8 in) TVD/MD Drill pipe 5 in capacity Heavy Wall pipe 5 in Capacity Drill collars 6¼ in Capacity Drilling fluid density Capacity open hole x collars Capacity open hole x drill pipe/HWDP Capacity casing x drill pipe Fracture fluid density at the casing shoe SIDPP SICP Mud pumps displacement Slow Circulating Rate Pressure (PL) at 30 SPM Pit gain
8½ 11536 9875 0.01741 600 0.00874 880 0.00492 14.0 0.03221 0.04470 0.04891 16.9 530 700 0.1019 650 10.0
in ft ft bbl/ft ft bbl/ft ft bbl/ft ppg bbl/ft bbl/ft bbl/ft ppg psi psi bbl/strk. psi bbl
With the following date given the kill sheet can be filled out and the necessary information be required to kill the well: Internal strokes from surface to bit: Total annulus from bit to surface: Open hole from bit to shoe: Kill fluid density: Initial circulation pressure Final circulation pressure: Initial MAASP with drilling fluid density: New MAASP with kill fluid density: Influx gradient Height of influx around DC Height of influx around DP
Index 03 Page 177
1812 5360 620 14.9 1180 692 1489 1027 0.178 310 204
strokes strokes strokes ppg psi psi psi psi psi/ft ft ft
MTC
WELL CONTROL MANUAL
Shoe
PA
ANNULUS
OMW OMW
ANNULUS
PDP
DRILL STRING
PA
DRILL STRING
OMW
PDP
OMW
Shoe GAS
BHP
BHP
GAS
Fig 48
Fig 49
Situation Fig 48 shows the start of circulation. The standpipe pressure is equal to PSIDPP plus PL (Reduced Rate Circulating Pressure Loss). The pressure at the casing head Pa is equal to PSICP . While keeping constant casing pressure the pumps are slowly brought up to slow circulating rate, in this case 30 SPM. When the pumps are running at 30 SPM and pressures have stabilized the ICP pressure on the drill pipe gauge is keep constant. ICP = 530 psi + 650 psi = 1180 psi Shoe pressure = 7189 psi + 700 psi = 7889 psi MAASP = 8678 psi - 7189 psi = 1489 psi
SIDPP + PL Phshoe + SICP Max Shoe Pressure - Phshoe
Situation Fig 49 shows the gas circulated a way up the annulus. Drill Pipe Pressure is kept constant while gas is being pumped up through the open hole section and the top of the gas bubble reach the shoe. The gas is expanding allowing the pressure inside bubble to decrease. Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 775 psi Shoe pressure is increasing with same value as the casing pressure. Shoe P = Phshoe + Csg P 7964 psi MAASP remains constant due to no change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1489 psi Index 03 Page 178
MTC
WELL CONTROL MANUAL
PDP
PA
PDP
PA
Shoe
BHP
ANNULUS
GAS
DRILL STRING
OMW OMW
ANNULUS
DRILL STRING
OMW
GAS
OMW
Shoe
BHP
Fig 50
Fig 51
Situation Fig 50 shows the gas circulated inside the casing. Drill Pipe Pressure is kept constant while gas is being pumped from the open hole section until all the gas is inside the casing so the open hole section is displaced to original drilling fluid. The gas is expanding allowing the pressure inside bubble to decrease. Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 785 psi Shoe pressure is constantly decreasing from gas reach the shoe until all gas is inside casing. Shoe P = BHP - Phopen hole 7718 psi MAASP start increasing from the first gas enters the casing due to change in Ph inside the casing. 1685 psi MAASP = Max Shoe Pressure - Phshoe Situation Fig 51 shows the gas at the choke. Drill Pipe Pressure is kept constant while gas is being pumped up inside the casing and the top of the gas bubble reach the choke. The gas is expanding allowing the pressure inside bubble to decrease. Casing pressure increasing due to the expanding gas is displacing drilling fluid and when top of the gas bubble reach the choke casing pressure is increased to max. CSG P = BHP - (Phmud + Phgas) 1580 psi
Index 03 Page 179
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WELL CONTROL MANUAL
Shoe pressure remains constant from the moment all gas is inside the casing. Shoe P = BHP - Phopen hole 7718 psi MAASP increasing with the same value as the Csg P due to change in Ph inside the casing and will reach max value when gas at choke. MAASP = Max Shoe Pressure - Phshoe 2480 psi PA
ANNULUS
DRILL STRING
OMW
PDP
OMW
Shoe
BHP
Fig 52 Situation Fig 52 shows that all the gas is now circulated out. Drill Pipe Pressure is kept constant while gas is being pumped out of the well through the choke. Casing pressure is decreasing while drilling fluid is displacing gas in the well bore and will reach SIDPP when all the gas is out of the well. CSG P = BHP - Phmud 530 psi Shoe pressure remains constant while the gas is displaced from the well bore due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7718 psi MAASP decreasing with same value as the Casing Pressure and will reach initial MAASP when the annulus is displaced to original drilling fluid. MAASP = Max Shoe Pressure - Phshoe 1489 psi
Index 03 Page 180
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WELL CONTROL MANUAL
Drillers method 2nd circulation:
Shoe
PA
BHP
ANNULUS
OMW KMW
ANNULUS
PDP
DRILL STRING
PA
DRILL STRING
OMW
PDP
OMW
Shoe
BHP
Fig 53
Fig 54
Situation Fig 53 shows the kill fluid is being pumped to the rig floor. Kill mud is being mixed to 14.9 ppg and 2nd circulation is started. Casing pressure is kept constant while kill fluid fills the drill string. CSG P = BHP - Phmud
530 psi
Drillpipe pressure is decreasing while kill fluid fills the drill string. DP P = PL + (BHP - Phmud) Shoe pressure remains constant while kill mud fills the drill string due to no change in Phopen hole. 7718 psi Shoe P = BHP - Phopen hole MAASP remains constant while kill mud fills the drill string. MAASP = Max Shoe Pressure - Phshoe
1489 psi
Situation Fig 54 shows that kill fluid has reached the bit. Kill fluid reach the bit. Casing pressure is kept constant while kill fluid fills the drill string. CSG P = BHP - Phmud
530 psi
Drillpipe pressure decreasing while kill fluid fills the drill string and when kill fluid reach the bit pressure is FCP or PL with 14.9 ppg mud. DP P = PL with 14.9 ppg 692 psi Index 03 Page 181
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WELL CONTROL MANUAL
Shoe pressure remains constant while kill mud fills the drill string due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7718 psi MAASP remains constant while kill mud fills the drill string. MAASP = Max Shoe Pressure - Phshoe
Shoe
ANNULUS
KMW
ANNULUS
OMW
KMW
Shoe
BHP
BHP
Fig 55
PA
DRILL STRING
PDP
PA
DRILL STRING
KMW
PDP
1489 psi
Fig 56
Situation Fig 55 shows that kill fluid is on its way up the annulus. Kill fluid at shoe. Drillpipe pressure is kept constant while kill fluid displaces original mud in annulus. DP P = PL with 14.9 ppg 692 psi Casing pressure decreasing as kill fluid moves up the annulus to the shoe. CSG P = BHP - Phmud 469 psi Shoe pressure is decreasing as kill fluid moves up the annulus to the shoe with same value as the decrease in Csg P. Shoe P = BHP - Phopen hole 7657 psi MAASP remains constant while kill fluid moves up the annulus to the shoe. 1489 psi MAASP = Max Shoe Pressure - Phshoe Situation Fig 56 shows that the kill fluid has reach the choke. Kill fluid at the choke. Drillpipe pressure is kept constant while kill fluid displaces original mud in annulus. Index 03 Page 182
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WELL CONTROL MANUAL
DP P
=
RRCP w/14.9 ppg
692 psi
Casing pressure decreasing as kill fluid moves up the annulus and will reach 0 psi when kill fluid reach the choke. CSG P = BHP - Phmud 0 psi Shoe pressure remains constant while kill fluid is displacing original mud inside the casing due to no change in Ph open hole. Shoe P = BHP - Phopen hole 7657 psi MAASP decreasing as kill fluid is displacing original mud inside the casing with same value as the drop in casing pressure. 1020 psi MAASP = Max Shoe Pressure - Phshoe CASING PRESSURE
DRILL PIPE PRESSURE 1500 1400 1300 1200 1100 1000 PRESSURE
900 800 700 600 500 400 300 200 100 0
2000
4000
6000
8000
10000
12000
14000
16000
STROKES
Fig 57 Fig 57 shows the pressure relationship between drill pipe and casing. Drill Pipe pressure 1st circulation: Drill Pipe Pressure constant while displacing annulus to original drilling fluid and removing gas from well bore. Drill Pipe pressure 2nd circulation: Drill Pipe Pressure decreasing to FCP will kill fluid fills the drill string and then constant while kill fluid displaces original mud in annulus. Casing pressure 1st circulation: Casing Pressure is constantly increasing until gas reach choke. Casing pressure is decreasing to SIDPP while gas is displaced from the well bore. Index 03 Page 183
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WELL CONTROL MANUAL
Casing pressure 2nd circulation: Casing Pressure constant while kill fluid fills the drill string and then decreasing while kill fluid displace original mud in annulus. Shoe pressure 1st circulation: Increase with SICP when taking influx. Increase while gas is moving up in the open hole section. Decrease while gas enters the casing. Constant after open hole has been displaced to drilling fluid. Shoe pressure 2nd circulation: Shoe pressure constant while kill fluid fills the drill string. Shoe pressure decreasing while kill fluid displaces original mud in open hole. Shoe pressure constant while kill fluid displaces original mud inside casing. MAASP pressure 1st circulation: Constant while gas is moving up open hole section. Increase quickly while gas is entering casing. Increase slowly with same value as Csg P while gas moves up inside casing. Decreasing to initial value while gas is displaced from the well bore. MAASP pressure 2nd circulation: MAASP constant while kill fluid fills the drill string. MAASP constant while kill fluid displaces original mud in open hole. MAASP decreasing while kill fluid displace original mud inside casing with same value as the decrease in casing pressure.
Index 03 Page 184
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WELL CONTROL MANUAL
03.08 Wait and weight method. This method is also called the "balance method" and is described below. The well is shut in and pressure values are observed. The drilling fluid is increased to the weight necessary to kill the well. While keeping constant casing pressure the pumps are slowly brought up to slow circulating rate and when running at the desire rate the drill pipe pressure is the ICP. The primary objective, while killing the well is to keep constant BHP, but as the heavy drilling fluid fills the drill string the ICP cannot be held constant due to the change in hydrostatic head. In the annulus the gas expands as it rises, so therefore casing pressure cannot be held constant either. However, the choke can be manipulated in such a way that standpipe pressure can be gradually decreased as the heavy drilling fluid is pumped down the drill string. How much and how often it is decreased can be decided in the following way. Like the Driller's Method we begin to circulate with a standpipe pressure equal to PSIDPP + PL and when the drill string is full of heavy drilling fluid the pressure will be equal to the new PL with heavy drilling fluid inside the string or FCP. This change in standpipe pressure occurs over a certain period of time that depends on the total number of strokes it takes to pump the drill string full of heavy drilling fluid. (Surface-to-bit). The easiest way is to represent this graphically. The following graph will show standpipe pressure changes in relation to pump strokes combined with a table that shows the new standpipe pressure for every 100 strokes. See Fig 58 The figures used for the graph and table apply to example in Driller’s Method and W&W Method. Pressure change per 100 strokes is calculated in the following way: (ICP – FCP) x 100 ----------------------------Surface to bit strokes
∆P/100 strk = Using the previous example we will get:
∆P/100 strk =
(1180 – 692) x 100 ----------------------------1812
=
27psi/100 strk
Circulation of the heavy drilling fluid from surface-to-bit can now proceed by regulating the choke after the table, so the bottom-hole pressure will remain constant. As soon as the drill string is full of heavy drilling fluid (after 1812 strokes) no change will occur of drilling fluid density and drilling fluid column in the drill string, which means that standpipe pressure (692 psi) can be held constant for the rest of circulation.
Index 03 Page 185
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WELL CONTROL MANUAL
PRESSURE 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1812
1180 1153 1126 1099 1072 1045 1018 991 964 937 910 883 856 829 802 775 748 721 694 692
1100 900 700 500 300
100 500
1000
1500
2000
STROKES
Fig 58
When killing a kick by the Weight and Wait Method, there are four phases that are described below. Phase 1.
Mix the required kill fluid immediately. When the kill fluid is ready, start pumping and open choke slowly while the pump is brought up to speed holding casing pressure constant at this initial start-up. As the drill string is gradually filled with kill fluid, circulation pressure is regulated with the choke to follow the values of the curve, until the calculated FCP with kill fluid at the bit is reached. (At this stage the drill pipe should be dead).
Phase 2.
Continue pumping until the gas is at the choke keeping constant drill pipe pressure.
Phase 3.
Continue pumping until all the gas is out. At this stage the annulus will be full of kill fluid, minus the capacity of the drill string which is light drilling fluid.
Phase 4.
Continue pumping until the annulus is full of heavy drilling fluid. At this stage the well should be dead.
Index 03 Page 186
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WELL CONTROL MANUAL
Wait and weight method: Well Kick Data: Hole size Hole depth TVD/MD Casing (9 5/8 in) TVD/MD Drill pipe 5 in capacity Heavy Wall pipe 5 in Capacity Drill collars 6¼ in Capacity Drilling fluid density Capacity open hole x collars Capacity open hole x drill pipe/HWDP Capacity casing x drill pipe Fracture fluid density at the casing shoe SIDPP SICP Mud pumps displacement Slow Circulating Rate Pressure (PL) at 30 SPM Pit gain
8½ 11536 9875 0.01741 600 0.00874 880 0.00492 14.0 0.03221 0.04470 0.04891 16.9 530 700 0.1019 650 10.0
in ft ft bbl/ft ft bbl/ft ft bbl/ft ppg bbl/ft bbl/ft bbl/ft ppg psi psi bbl/strk. psi bbl
With the following date given the kill sheet can be filled out and the necessary information be required to kill the well: Internal strokes from surface to bit: Total annulus from bit to surface: Open hole from bit to shoe: Kill fluid density: Initial circulation pressure Final circulation pressure: Initial MAASP with drilling fluid density: New MAASP with kill fluid density: Pressure drop/100 strk Influx gradient Height of influx around DC Height of influx around DP
1812 5360 620 14.9 1180 692 1489 1027 27 0.178 310 204
strokes strokes strokes ppg psi psi psi psi psi/100 strk psi/ft ft ft
Situation Fig 59 shows the start of circulation. The standpipe pressure is equal to PSIDPP plus PL (Reduced Rate Circulation Pressure Loss). The pressure at the casing head Pa is equal to PSICp. While keeping constant casing pressure the pumps are slowly brought up to slow circulating rate, in this case 30 SPM. When the pumps are running at 30 SPM and pressures have stabilized change to ICP and then keep DP pressure on schedule. ICP = 530 psi + 650 psi = 1180 psi
SIDPP + PL
Shoe pressure
Phshoe + SICP
=
Index 03 Page 187
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WELL CONTROL MANUAL
7189 psi + 700 psi = 7889 psi MAASP = 8678 psi - 7189 psi = 1489 psi
PA
PDP
PA
ANNULUS
Shoe
DRILL STRING
OMW OMW
ANNULUS
DRILL STRING
OMW
KMW
PDP
Max Shoe Pressure - Phshoe
OMW
Shoe GAS
BHP
Fig 59
BHP
GAS
Fig 60
Situation Fig 60 shows kill fluid fills the drill string while gas is circulated a way up the annulus. Drill Pipe Pressure is kept on schedule while gas is being pumped up through the open hole section and the top of the gas bubble reach the shoe. The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped. 1053 psi DP P = ICP - (470 x 27) 100 Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 775 psi Shoe pressure is increasing with same value as the casing pressure and reach max. value when gas reaches the shoe. Shoe P = Phshoe + Csg P 7964 psi MAASP remains constant due to no change in Ph inside the casing. 1489 psi MAASP = Max Shoe Pressure - Phshoe Situation Fig 61 shows kill fluid fills the drill string while gas is circulated inside the casing. The gas is expanding allowing the pressure inside bubble to decrease.
Index 03 Page 188
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WELL CONTROL MANUAL
Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped. DP P = ICP - (620 x 27) 1013 psi 100 Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 785 psi
PA
PDP
PA
GAS Shoe
GAS
ANNULUS
KMW
ANNULUS
OMW
DRILL STRING
OMW
DRILL STRING
OMW
KMW
PDP
Shoe OMW
BHP
BHP
Fig 61
Fig 62
Shoe pressure is decreasing while gas moves from below the shoe until all gas inside the casing. Shoe P = BHP - Phopen hole 7718 psi MAASP start increasing from the first gas enters the casing due to change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1685 psi Situation Fig 62 shows kill fluid has filled the drill string. The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped and reach FCP when kill fluid at bit. DP P = ICP - (1812 x 27) 692 psi 100 Casing pressure increasing due to the expanding gas is displacing drilling fluid. CSG P = BHP - (Phmud + Phgas) 1050 psi
Index 03 Page 189
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WELL CONTROL MANUAL
Shoe pressure constant due to no change in Phopen hole Shoe P = BHP - Phopen hole 7718 psi MAASP increasing with the same value as the Csg P due to change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 1950 psi Situation Fig 63 shows kill fluid has displaced the top of the gas to the choke. The gas is expanding allowing the pressure inside bubble to decrease. Drill Pipe Pressure constant at FCP after kill fluid reach the bit. DP P = FCP 692 psi Casing pressure increasing due to the expanding gas is displacing drilling fluid, but slower due to kill fluid is displacing original mud. CSG P = BHP - (Phmud + Phgas + Phkill mud) 1278 psi Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7641 psi MAASP increasing with the same value as the Csg P due to change in Ph inside the casing. MAASP = Max Shoe Pressure - Phshoe 2178 psi
PDP
PA
PDP
PA
OMW
ANNULUS
KMW
ANNULUS
Shoe
DRILL STRING
OMW
DRILL STRING
KMW
GAS
KMW
BHP
BHP
Fig 63
Fig 64
Situation Fig 64 shows kill fluid has displaced all the gas out of the well bore. Drill Pipe Pressure constant at FCP after kill fluid reaches the bit. DP P = FCP
Index 03 Page 190
692 psi
KMW
Shoe
MTC
WELL CONTROL MANUAL
Casing pressure decreasing while gas is displaced out of the well bore. CSG P = BHP - (Phmud + Phkill mud) 180 psi Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole. Shoe P = BHP - Phopen hole 7641 psi MAASP decreasing while gas is displaced out of the well bore. MAASP = Max Shoe Pressure - Phshoe
1204 psi
Situation Fig 65 shows kill fluid has displaced the remaining original drilling fluid out of the wellbore. Drill Pipe Pressure constant at FCP after kill fluid reaches the bit. DP P = FCP
692 psi
Casing pressure decreasing to 0 psi while kill fluid displaces original mud out of the well bore. 0 psi CSG P = BHP - Phkill mud Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole. 7641 psi Shoe P = BHP - Phopen hole MAASP decreasing while kill fluid displace original mud out of the well bore. MAASP = Max Shoe Pressure - Phshoe 1027 psi
PA
ANNULUS
DRILL STRING
KMW
PDP
KMW
Shoe
BHP
Fig 65
Fig 66 shows the pressure relationships between drill pipe and casing.
Index 03 Page 191
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WELL CONTROL MANUAL
Drill Pipe pressure: Drill Pipe Pressure decreasing from ICP to FCP while kill fluid fills the drill string. Drill Pipe Pressure constant at FCP the remaining circulating time. Casing pressure: Casing pressure constantly increases until gas reach the choke. Casing pressure decreases rapidly while gas is displaced from the well bore. Casing pressure decreases to 0 psi while original mud is displaced with kill fluid. Shoe pressure: Increase while gas is moving up in the open hole section. Decrease while gas enters the casing. Constant until kill fluid reaches the bit. Decrease while kill fluid is moving up the open hole section. Constant after open hole has been displaced to kill fluid. MAASP pressure: Constant while gas is moving up in the open hole section. Increase rapidly while gas enters the casing. Increase until gas reaches the choke. Decrease rapidly while gas is displaced from the well bore. Decrease while original mud is displaced with kill fluid. CASING PRESSURE
DRILL PIPE PRESSURE 1500 1400 1300 1200 1100 1000 PRESSURE
900 800 700 600 500 400 300 200 100 0
1000
2000
3000
4000 STROKES
Fig 66
Index 03 Page 192
5000
6000
7000
8000
MTC
WELL CONTROL MANUAL
Annular pressure will fall to 0 PSI as soon as heavy drilling fluid appears at the choke. When this is observed the well should be dead. A flow check can now be made. If no flow is observed the blow-out preventer can be opened, and the drilling fluid can be circulated and conditioned as necessary, a trip margin can be added if it was not added to the kill drilling fluid at the start of the operation. Tripping or drilling can now take place again. 04.08 The concurrent method This is the most complicated of the three methods and its main value lies in the fact that the killing operation can be started as soon as the closed in pressures etc. have been recorded. Instead of waiting until the surface drilling fluid has all been weighted up to the kill drilling fluid weight, circulation at the reduced rate is started and the drilling fluid weight is increased while circulating. The rate of increase will depend on the mixing facilities available on the rig. The complication here is that the drill pipe can be filled with fluids of different densities, making calculation of the bottom well hydrostatic pressure difficult. Procedure for concurrent method When all the kick information has been recorded, start up the pump slowly while adjusting the choke until the initial circulating pressure has been reached at the reduced circulating rate. The drilling fluid should he weighted up at the maximum rate available with the rig equipment and, as the drilling fluid weight changes in the suction tank the choke operator is informed. He checks the pump strokes gone when the new drilling fluid weight starts on his chart, similarly with each change of drilling fluid weight, adjusting his choke pressure to suit the new drill pipe conditions as pre-recorded on his surface to bit graph. When the final kill drilling fluid reaches the bit the final circulating pressure will be reached and from this point onwards the pressure should be kept constant until the operation is completed.
Index 03 Page 193
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WELL CONTROL MANUAL
05.08 Advantages and disadvantages of the three methods The driller's method is the simplest. The only calculations required is the kill drilling fluid weight, the capacity of the drill pipe and the capacity of the annulus. While circulating out the kick the drill pipe pressure is kept constant by regulating the choke. On the second circulation while the kill drilling fluid is filling the drill pipe, the annulus pressure is kept constant. When the drill pipe is full of kill drilling fluid control is switched back to the drill pipe while the annulus is being killed. The Wait and weight method on the other hand, requires the added calculation of the pump strokes required to fill the drill pipe and the subsequent reduction in circulating pressure as the pipe is filled. The concurrent method has the added complication of possibly two or more drilling fluid weights being present in the drill pipe at the same time.
Fig. 66 shows a comparison of casing pressures under killing according to the used method. DRILLER’s METHOD
WAIT and WEIGHT METHOD
CONCURRENT METHOD
1500 1400 1300 1200 1100 1000 PRESSURE
900 800 700 600 500 400 300 200 100 0
1000
2000
3000
4000
5000
STROKES
Fig 66
Index 03 Page 194
6000
7000
8000
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WELL CONTROL MANUAL
ADVANTAGES & DISADVANTAGES METHOD DRILLER’S METHOD
ADVANTAGES Simplest to teach and understand. Very few calculations. In case of saltwater the contaminant is moved out quickly to prevent sand settling around drilling assembly
WAIT and WEIGHT METHOD
Lowest casing pressure. Lowest casing shoe pressure. Less lost circulation (if not over killed). Killed with one circulation if influx doesn’t string out in washed out sections of the hole.
CONCURRENT METHOD
DISADVANTAGES Higher casing shoe pressure if long open hole section (gas kick). Higher annular pressure (gas kick). Takes two circulations.
Requires the longest noncirculating time while mixing heavy mud. Pipe could stick due to settling of sand, shale, anhydrite or salt while not circulating. Requires a little more arithmetic.
Minimum of non-circulating time.
Arithmetic is more complicated.
Excellent for large increases in mud weight (underbalanced drilling)
Requires more on-choke circulating time.
Mud condition (viscosity and gels) can be maintained along with mud weight. Less casing pressure than Driller’s Method. Can easily be switched to Wait and Weight Method.
Index 03 Page 195
Higher casing and casing shoe pressure than Wait and Weight Method.
MTC
WELL CONTROL MANUAL
06.08 Pressure control schemes General When a kick occurs there are a lot of facts to record and analyse. These facts are recorded in a so-called work sheet, a pre-planned scheme. These work sheets, when completed will give us a complete picture of the conditions and calculations in a kick situation. These work sheets can differ greatly from company to company but they all have the same basic content. Contents of work sheets A work sheet will contain, in one way or another, the following facts: Information that is previously known. Equipment: Drill string: Drill collars:
Dimensions, capacity, etc. Inner and outer measurements, length, etc.
Bit diameter: Casing: Open Hole:
Dimensions, depth measure and true vertical, capacity, etc. Total measured depth, true vertical depth.
Pumps: Normal circulation rate and pressure. Reduced Rate Circulating Pressure Loss (PL). Pump output per stroke. Facts after the well is shut In. Standpipe pressure (SIDPP). Annulus pressure (SICP). Pit level increase (kick gain). Calculations. By using the previous mentioned work sheet (Kill Sheet) all required calculations to circulate out a kick on a safe manner is easily done. See Fig 67 Surface to bit strokes. Bit to surface strokes. Bit to shoe strokes. Kill mud weight. Initial Circulating Pressure. Final Circulating Pressure.
Index 03 Page 196
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WELL CONTROL MANUAL
Fig 67 Index 03 Page 197
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WELL CONTROL MANUAL
Fig 67a
Index 03 Page 198
MTC 09
WELL CONTROL MANUAL
CALCULATION OF DENSITY/PRESSURE GRADIENT OF AN INFLUX
01.09 General It is always important to analyse what the influx actually is when a kick is taken into the wellbore. It can be decided what the influx is (gas, oil or water) by making a calculation with height and pressure. The height of the influx is easy enough to find by the measured pit gain at the surface (bbl) and the annulus capacity that is already known in bbl/ft.
hi =
kick gain (bbls) = (ft.) annulus capacity (bbls/ft.)
If we call the depth of the well H, drilling fluid weight MWm, we can work out the different pressures in the annulus and drill string and furthermore bottom hole pressure (formation pressure). See Fig 68. SIDPP
SICP
OMW
ANNULUS
DRILL STRING
OMW
H - Hi
H
BHP H x MWm x 0.052 + SIDPP =
Hi
Shoe
INFLUX
Pf = (H-Hi) x MWm x 0.052 + Hi x Wi x 0.052 + SICP
Fig 68
Pressure from drill string ==
Formation Pressure
H x MWm x 0.052 + SIDPP ==
F.P. == (H – Hi) x MWm x 0.052 + Hi x Wi x 0.052 + SICP
Hi
:
Height of influx
Wi
:
Density of influx
The equation can now be reduced to the following formula:
Wi=
== Pressure from annulus
P sidp - P sia + MW m hi x 0,052
Index 03 Page 199
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WELL CONTROL MANUAL
As the influx is either gas, oil, water or a mixture of same the density of the influx is lower than the drilling fluid with result that SICP is greater than SIDPP the formula can be expressed as follow:
W i = MW m -
P sia - P sidp (ppg) hi x 0,052
When knowing the density of the influx pressure gradient can then be calculated as follows: Gi = Wi x 0,052 psi/ft or in the following way:
Gi = G m -
P sia - P sidp psi / ft hi
02.09 Examples Example #1: Influx OH – DC capacity Drilling fluid density TVD SIDPP SICP
25 bbl. 0.042 bbl/ft 15 ppg 7600 ft 265 psi 660 psi
Height of Influx:
hi = Gradient of Influx:
G i = 15 x0.052 -
25 (bbl) = 595 ft. 0.042 (bbl/ft) 660 − 265 psi / ft = 0.116 psi/ft 595
Comparing the pressure gradient with table Fig 06 it can be seen that the influx is gas or a mixture of gas/oil. Example #2: Same as example #1 except that SICP is 450 psi. Gradient of influx: 450 − 265 psi / ft = 0.469 psi/ft G i = 15 x0.052 595 Comparing the pressure gradient with table Fig 06 it can be seen that the influx is water. We should be aware that there could be margin in these calculations of error. The accurate annular or DC-OH capacity is not known due to wash out etc. and the results are therefore quite unsure and shall not be used for anything else than to get a rough index of what the influx is. The circulation of a kick is also not dependent on what the influx is. Therefore this Index 03 Page 200
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WELL CONTROL MANUAL
particular calculation is not relied upon to any great extent. At the same time it can be advantageous to know whether it is a gas kick or oil/water kick that we have to deal with. If it is a gas kick we can be prepared for the high casing pressure and pit volume increase towards the last stage of circulation, which will not occur if the influx is a fluid. The pressure gradients for influx are as noted below. Between 0.47 to 0.52 psi/ft. the influx is saltwater. if the influx is less than 0.16 psi/ft. the influx is gas. Between 0.31 and 0.42 psi/ft. the influx should be oil, but it could also be a mixture. See Fig 06. If we are in doubt about the result, treat the kick as a gas kick, and in this way the most dangerous situation will be expected.
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LOST CIRCULATION
01.10 General Lost circulation is one of the most serious problems that occur in rotary drilling. Lost circulation is defined as loss of drilling fluid into the formation, which can be total. As most wells are drilled there is experienced a lesser or greater loss of drilling fluid to the formation. Lost circulation is both expensive and time-consuming (price of drilling fluid and lost rig time). In connection with well killing operations lost circulation is extremely dangerous. See Fig 69. Losses can best be described as unintentional transfer of fluid from the borehole into the formation. When describing losses, the duration for which they occur needs to be taken into account, e.g. a 10 bbl loss that stops after 5 min, should not be reported as 120 bbl/hr losses! It should also be recognised that the rate of losses will change under static or dynamic conditions. The description of losses can differ from operator to operator but falls into the following categories: a. No losses - Less than 2 bbl/hour. b. Seepage Losses - Between 2 and 5 bbl/hour. c. Partial Losses - Between 5 and 50 bbl/hour. d. Severe Losses - Greater than 50 bbl/hour. e. Complete Losses - Unable to maintain a fluid level at surface with the desired mud weight, regardless of pumping rate f. Static Losses - The losses that occur when the well is not being circulated and the drill string is stationery. g. Dynamic Losses - The losses that occur when the well is circulated, or the drill string creates surge pressure. Fig 69 When a kick occurs and the well is shut in, the drill pipe pressure informs us of the extra pressure required balancing the formation. The problem is that when the well is shut in it is difficult to decide if in fact lost circulation has, or is occurring. The biggest problem is therefore the uncertainties. 02.10 Causes of lost circulation The three most common causes that lost circulation arise in connection with a kick. l.
Bad cementing job.
2.
Caused formation breakdowns.
3.
Fissured and Fractured Formations. Index 03 Page 202
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Bad cementing job One of the most common causes of lost circulation in a kick situation is a bad cement job at the base of the last casing string. Most operators insist that the cement is pressure tested after drilling the shoe, to test its strength and bond to the casing. The test pressure shall take into account the highest drilling fluid weight that is to be used in the next phase of drilling or shall follow legal requirements. A bad cement job is dangerous because it can allow gas to escape up the side of the casing to the surface. Large gas blowouts have occurred in oilfields because of this. Formation breakdown This cause of lost circulation is most common. The breakdown can be caused by large pressure fluctuations, the use of drilling fluid that is too heavy or from blowout conditions. In most cases after the pressure falls the breakdown in the formation will close itself up in a relatively short time. Such a formation breakdown often occurs around the casing shoe and in effect is exactly the same as a bad cement job. Fractured and fissured formations In hard formations fractures and fissures can be the cause of serious lost circulation problems. It can be difficult to stop these formations taking drilling fluid. In many cases these kind of formations are the actual reservoir beds, and the pressure which is used to balance the reservoir is often very close to the pressure that will cause breakdown and resultant lost circulation. 03.10 Well control with partly lost circulation In most cases the first sign that lost circulation is occurring is a fall in the drilling fluid pit level. Fig 70 and Fig 71 shows the relationships in such a situation. PDP
PIT LEVEL NATIONAL
1100
PA BOP
900 700 500
WEAK FORMATION
LOST CIRCULATION 300
100 TI
Fig 70
Fig 71
Index 03 Page 203
LOST CIRCULATION
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WELL CONTROL MANUAL
Fig. 70 shows a graph of pit. The solid line shows how the pit level changes during a gas kick, from when the kick is taken to when it is killed. The dotted line could show how the pit level will change if part-lost circulation occurs while killing a gas kick. Fig. 71 shows the situation in the well. The gas is circulated a way up the annulus and breaks out of the wellbore into a relatively weak zone. This zone cannot withstand the pressure of the choke combined with the hydrostatic pressure, and therefore drilling fluid will flow into the formation. If the fluid column falls under circulation, there are several methods that can be used to combat this problem, and are as follows: l.
If the lost volume is not too great and the drilling fluid volume can be made up by mixing new drilling fluid, go ahead. The pressure on the weak zone will decrease as the gas bubble passes upwards. The problem solves itself. When circulating with part-lost circulation the pressure at the choke will be the highest casing pressure that the formation can withstand. Every 30 minutes the choke is closed partly so the pressure in the well bore increases 100 psi. If the annular pressure does not increase, open the choke to the same setting as before and continue circulating out the influx. If the well bore pressure increases check for similar increase on the drill pipe pressure. If the drill pipe pressure does not increase, open the choke to the same setting as before and continue circulating out the influx. If both the drill pipe and annulus pressure increases the losses are decreasing and the formation is healing itself. If so shut the well in and record the new SIDPP:
2.
Stop the pump and close in the well. Give the well from 30 minutes to 4 hours to heal itself up. Hold SIDPP constant by regulating the choke. If the casing pressure rises by more that 100 psi continue to circulate out the influx.
3.
Decide on a lower circulation rate and a new initial circulation pressure. Consider the well as being closed in and proceed as follows: a.
By manipulating the choke keep casing pressure constant while the pumps are brought up to the new lower circulating rate.
b.
Adjust the choke until the annular pressure is the same as when the well was shut in (this method not good for sub-sea wellheads). Proceed accordingly now that a new initial circulation pressure of drill pipe is known.
4.
Mix a pill of lost-circulation material of a type, which will be effective on the formation in question. Normally lost circulation material is more effective in hard formations and less effective in softer plastic formations.
5.
If the losses continue after the above-mentioned solution has been tried a barite or barite/diesel plug can be pumped in attempt to seal off the weak zone.
04.10 Well control with total lost circulation Standard blowout control procedure cannot be used if the well cannot be circulated. With total lost-circulation gas can rise up to the surface, but there is also the danger of an underground
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blowout. The only way to solve the problem is first to stop loss of drilling fluid to the formation so the well can be killed with the help of standard procedure. l.
Barite plug: The best solution with a gas kick is to try and plug the gas zone with a barite plug and proceed to seal the lost circulation zone. In the meantime it is possible that there can occur a high speed underground flow of formation fluid/gas into the weak zone. This flow could possibly wash away the barite plug, so to try to prevent this a plug as large as 300 ft in height should be used. See Fig 72. BARITE PLUG MIXTURE for 300 ft.
180
15”
100 0s xB
160
Water in bbl.
140
150 lb
12-1/4”
100 9-7/8”
80
8-3/4” 60
7-7/8”
40
6-1/2”
15
Pho sph ate
700 sx B arite For a - 100 17-1 lb Ph /2” h osph ole u ate se tw ice t he m ix fo ra1 2-1/4 425 sx ” ho le Barite - 50 lb Phosp hate 335 sx B arite - 50 lb Phosp hate 270 sx B arite - 35 lb Phosp hate 185 sx Barite - 25 lb Phosp hate
120
20
arit e-
17
16
18
19
Mud Weight -lb/gal
Fig 72 Mixing procedure for barite plug: Add water, the Phosphate and finally Barite. Adjust pH to 9.0 using Caustic Soda. Use fresh clean water only. 2.
Gunk plug: A gunk plug is a plug consisting of bentonite mixed with diesel fuel and is a very fast solidifying plug that is especially effective for water flows. The plug will not start to become stiff until it comes into contact with water, so there is no danger of premature setting. When the plug is pumped down in the bottom of the well the diesel is washed away from the solids, which begin to set as they come into contact with the water. A large plug shall be used, about 300 ft. in Index 03 Page 205
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height. An oil plug shall be pumped before and after the gunk plug to prevent contamination of the plug with drilling fluid to avoid premature swelling of the bentonite. For gunk plugs in Oil Based drilling fluid Geltone II (MI product name) or similar is used. See Fig 73. Prior to pumping gunk plugs all lines must be flush and cleaned. A thick mixture of rough lost circulation material can sometimes be pumped down the annulus via the kill line, to seal off the thief zone.
GUNK MIX for 300 ft COLUMN HOLE SIZE inch
DIESEL OIL bbl
BENTONITE sacks
TOTAL VOLUME bbl
6-1/2” 7-7/8” 8-3/4” 9-7/8” 12-1/4” 15” 17-1/2”
9 13 14 20 33 50 66
27 40 49 62 98 150 200
12 18 22 28 44 66 89
Fig 73
Fig. 74 illustrates the conditions in the well with regards to the pumping of a plug to contain the kick zone, and illustrates also the manner in which lost-circulation material is pumped down into the weak zone.
HALLIBURTON
PA BOP
KILL LINE Lost Circulation M aterial
W EAK FORMATION
PLUG
Fig 74
INFLUX
Index 03 Page 206
MTC 11
WELL CONTROL MANUAL
VOLUMETRIC WELL CONTROL.
01.11 General Volumetric Method is used, if gas or gaseous influxes for one or another reason cannot be circulated out. Examples of such a situation can be: - Prior to pumping kill fluid with conventional method. - Pipe off bottom. - Drill string or bit plugged. - Drill string out of hole. - Wash out in the drill string. - If drill string have been cut and left in hole. - Repairs to pumps or other equipment failure such that normal kill procedure cannot be exercised. When the gas bubble is down hole, the Volumetric Method can be used to allow the bubble to expand while it migrates up the hole, keeping bottom hole pressure constant. The basic of this method is the knowledge that every bbl of fluid gives a certain bottom hole pressure. This pressure can be measured in psi/bbl by dividing the fluid gradient psi/ft with annular volume in bbl/ft or the volume of the well bore in bbl/ft if there is no drill string in the hole. As the gas migrates up the annulus, the annular capacity usually changes. It is therefore necessary to estimate the location of the gas, calculate the correct annular volume and control the casing pressure accordingly. In general with pipe in the hole casing/drill pipe capacity is used due to this is the longest section the gas has to migrate. The amounts of fluid which are to be bled off or pumped (lubricated) into the well, must be measured precisely enabling us to have exact control of pressure in the well bore. A migration rate exceeding 1000 ft/h (300 m/h) makes the Volumetric Method a fair alternative, but keep in mind that recent research has show that gas is able to migrate as fast as 10000 ft an hour under ideal condition even in highly deviated wells. 02.11
Volumetric method – requirements
1. Closing the well When the well is shut-in, take accurate readings of the shut-in casing pressure (SICP) and pit gain. Make note of the time when readings are taken. An increase in closed-in pressures confirms that the influx is gas and migration is taking place. 2. Estimating the migration rate When a gas influx is taken, the large density difference between gas and drilling fluid will cause the gas bubble to migrate up the hole. As the gas migrates, without expansion being permitted, the pressures throughout the wellbore will increase. The velocity of gas-migration depends on hole size, gas and fluid densities, fluid viscosity and whether gas influx is one big bubble, or distributed as many smaller bubbles.
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A common rule of thumb is to assume a gas migration velocity of between 500 ft to 1000 ft per hour. If oil base drilling fluid is in use, gas migration may be limited by solubility or gas/oil miscibility effect. The following discussion of gas migration applies to water base drilling fluid only. The distance that gas has migrated and the rate of migration may be estimated as follows See Fig 75: 300 psi
PA
12.5 ppg 10000 ft
GMD
P2 - P 1 = -------------------------MWG
GMR
GMD = -------------------------T2 - T1
Where:
GAS
GMD = Gas migration distance MWG = Mud gradient P1 = Surface pressure at time T1 P2 = Surface pressure at time T2 GMR = Gas migration rate ( feet per hour) T1 = Time 1 (hour) T2 = Time 2 (hour)
6500 psi Fig 75
03.11
Volumetric method - handling
1. Shut the well in and record the initial shut-in casing pressure SICP, Pit Gain and Initial Shut-in Time. 2. Allow the casing pressure to increase by approx. 100 psi (P1) above the original shut-in pressure for safety factor. The safety factor is used because the pressure will always fluctuate a little depending on the man at the choke, so by using a safety factor we make certain that the bottom hole pressure does not drop below the formation pressure so further influx is taken into the wellbore. P2 = SICP + P1 3. Allow a new pressure increase 50-100 psi (P3), but do not exceed the fracture pressure at the casing shoe. This pressure is called working range and will determine the amount of fluid in the well bore that represents this pressure. Index 03 Page 208
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WELL CONTROL MANUAL
P4 = SICPP + P1 + P3 = P2 + P3 4. Calculate the migration distance, corresponding to P3. P3 GMD = -----------MWG
5. Calculate the volume of fluid corresponding to the pressure increase, i.e. volume to bleed off (Vm). P3 x Cap Vm = Cap x h = -------------MWG
Cap = Hole capacity refers to the capacity directly above the bubble. In practice it is usually acceptable to use capacity of the casing below BOP’s for the following reasons: Open hole capacity is generally close to casing capacity. Only small volumes of fluid are bleed from the well, when the bubble is in open hole. Most of the increase in surface pressure and associated fluid occurs as gas approaches surface, where hole capacity is known accurately. 6. As the annulus pressure increases above P4 bleed of the calculated volume (Vm) gradually maintaining the pressure P4 at the choke. 7. After having bleed off the calculated volume (Vm), let the pressure build up to P5: P5 = P4 + P3 8. Repeat points 6 and 7 until casing pressure stabilises as the gas reaches the surface. 9. As gas is bled out of the hole the bottom hole pressure will decrease. Additional fluid should be pumped (lubricated) back into the well bore to maintain a constant bottom hole pressure to prevent an additional kick. 04.11
Lubrication technique
This method is used to reduce the casing pressure when gas is at the surface so that another operation such as stripping or snubbing can be performed. 1. Calculate the hydrostatic pressure, which will be exerted by a certain volume of drilling fluid in the annulus. If we use the same working range as before the volume will be the same. 2. Slowly pump the given volume of fluid into annulus through the kill line. Allow the fluid to ”fall” through the gas (by gravity). Low yield point fluids are preferable. A small pressure increase (∆P) may occur due to compression of the gas bubble. 3. Bleed gas from annulus until the surface pressure is reduced by an amount equal to the hydrostatic pressure of the fluid pumped in. Do not bleed off drilling fluid. Index 03 Page 209
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If the annulus pressure increases during ”pumping in” procedure, the amount of this increase (∆P) should be bled off in addition to the pressure bled for hydrostatic pressure increase. If drilling fluid starts coming back shut-in the choke and wait for the gas to percolate to the surface before continuing to bleed off. 4. Repeat this procedure until all gas has been bled off or the desired surface pressure reached. Lubrication During the pumping and gas bleeding, it will usually be necessary to decrease the volume of fluid to be pumped before the gas is bled of completely. This is because the annular volume occupied by the gas decreases with each pumping and bleeding sequence. If the Volumetric Method is going to be used it is important that we have the right equipment and drills have been carried out with all the crews. See Fig 76.
BOP
5 HALLIBURTON
1
PA 2
KILL LINE
1. Accurate pressure gauge on annulus side. 2. Adjustable choke (manual). 3. Trip or strip tank with accurate measurement.
3 4
4. Pump to empty strip/trip tank. PUMP
5. HP pump with accurate displacement tanks.
GAS
Fig 76
Index 03 Page 210
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WELL CONTROL MANUAL
05.11 Volumetric method- example Casing: Hole: EFD/Leak off: 1.
TVD/MD 5000 ft - 9-5/8” - 47lb/ft - N-80 - Cap. 0.073 bbl/ft TVD/MD 10000 ft - 8-1/2” - Cap. 0.070 bbl/ft 17.5 ppg MW: 10 ppg Pit V: 600 bbl
Shut in data: SICP:
2.
243 psi
Pit gain: 3 bbl
Overbalance (SF): (P1 = Approx 100 psi) P2 = SICP + P1
3.
P2 = 243 + 100 =
Pressure increase: (P3 = Approx 50 psi) P4 = P2 +P3
2.
P4 = 343 + 50 =
393 psi
Height of gas in Annulus corresponding to P3 P3 H = -----------MWG
5.
343 psi
50 H = ----------- = 10x0.052
96 ft
Vm = 0.07 x 96 =
6.73 bbl
Volume to be bled off Vm = Cap x H BOP
HALLIBURTON
Vm
PA Vm
KILL LINE
6
GAS
3 Vm P3 2
P3 Vm 5 P3 4
P3 6
Pa
P1 1 5
GAS
4
GAS
S I C P BLEED OFF
3
GAS
2
GAS
1
GAS
P3 P1
BHP
Index 03 Page 211
LUBRICATE
Fig 77
MTC
WELL CONTROL MANUAL
1.
Influx into the wellbore and SICP recorded to 243 psi.
2.
The gas bubble is allowed to percolate without expansion increasing the annulus and BHP with the safety factor (P1)100 psi to P2.
3.
The gas bubble is allowed to percolate further without expansion increasing the annulus and BHP with the working range (P3) 50 psi to P4. P4 = 243 + 100 + 50 = 393 psi
4.
While keeping 393 psi on the annulus 6.73 bbl of drilling fluid is bleed off allowing the gas bubble to percolate and expand. While bleeding off the 6.73 bbl the BHP pressure will decrease 50 psi (P3).
5.
After first bleed off, the well is shut in and the gas bubble is allowed to percolate further without expansion increasing the annulus pressure and BHP with the working range (P3) 50 psi to P5. P5 = 243 + 100 + 50 + 50 = 443 psi While keeping 443 psi on the annulus 6.73 bbl of drilling fluid is bleed off allowing the gas bubble to percolate and expand. While bleeding off the 6.73 bbl the BHP pressure will decrease 50 psi (P3).
6.
After second bleed off, the well is shut in and the gas bubble is allowed to percolate further without expansion increasing the annulus pressure and BHP with the working range (P3) 50 psi to P6. P6 = 243 + 100 + 50 + 50 + 50 = 493 psi While keeping 493 psi on the annulus 6.73 bbl of drilling fluid is bleed off allowing the gas bubble to percolate and expand. While bleeding off the 6.73 bbl the BHP pressure will decrease 50 psi (P3).
By continue this procedure the gas is brought to surface and the operation is reversed so 6.73 bbl of drilling fluid is lubricated into the well bore after witch (P3) 50 psi + ∆P is bleed off. See Fig 77. Fig 78 shows a work sheet to be used to keep control when using the Volumetric Method and Fig 79 illustrate the pressures in the wellbore while using the Volumetric Method.
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WELL CONTROL MANUAL
Worksheet for the Volumetric Method Pit volume increase Vm
Psi/bbl
Pressure inc. P3
Original pressure P4
New pressure
Total pit volume
Time
Fig 78
PRESSURE
Gas bubble pressure Bottom hole pressure Annular pressure Drill pipe pressure
BLEED OFF
LUBRICATE
TIME
Fig 79
Index 03 Page 213
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WELL CONTROL MANUAL
06.11 Low Choke Method - Dynamic Kill This method of well control is occasionally proposed for handling shallow gas kicks. If it is anticipated that shutting-in a kick will result in surface pressure above the maximum allowable, the well is allowed to flow through the choke (and kill) line and surface pressure is maintained slightly below the maximum allowable value. In this way the rate of influx may be sufficiently slowed to allow well control to be regained by circulating kill fluid down the drill string. There may be circumstances under which this technique can be implemented successfully, however there are inherent dangers. Initially bottom hole pressure is maintained at a value below the kicking formation pressure and inflow will therefore continue. The continued influx will reduce bottom hole pressure further as the annulus is unloaded. Only if kill fluid can be circulated into the annulus at a sufficient rate to overcome this unloading effect and increase the bottom hole pressure will well control be regained. The low choke method is an attempt to out run a kicking well, and should not be attempted except for handling shallow gas kicks. 07.11 Bullheading See Fig 80 Bullheading is generally recommended in the following circumstances: 1. If a kick is taken with the drill string far off bottom, or when no pipe in the hole. With the pipe close to bottom, stripping-in should be considered. The decision to strip, as well as the stripping procedure, must allow for the effects displacing the influx up-hole and for the effect of gas migration. If the upward force (closed in pressure multiplied by the cross-sectional area of the closed-end drill pipe) exceeds the string weight, it will not be possible to strip in. 2. If the influx has the potential for containing H2S. 3. If circulating the kick out could result in excessive gas rates through the well control system. 4. If the influx is very large, resulting in excessive surface pressures. After shutting in the well on a potential kick, the decision of whether to bullhead or circulate out the kick must be made very quickly after considering the following items: 1. Stabilised SIDPP and SICP: a. Does the pressures stabilise very quickly, indicating a kick from a high permeability formation? b. Is gas migration evident? 2. Influx volume and fluid type. 3. What are the estimated fracture pressure gradients for the shales and any exposed sand(s) in the open hole? a. How do they relate to the shoe strength (LOT)? How are shales and sands distributed in the open hole? b. Is fracturing the hole (with potentially “charged” formations) an acceptable consequence? 4. Pressure limitations of pumping equipment, wellhead equipment, and casing shoe tests. Index 03 Page 214
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WELL CONTROL MANUAL
SIDPP
SICP HALLIBURTON
SICP
SICP BOP
KILL LINE
GAS INFLUX
HALLIBURTON
KILL LINE
SIDPP
SICP BOP
BULL HEADING
INFLUX
Fig 80 5. If a gas influx is suspected (shut in pressure continues to rise indicating migrating gas in water base system), pumping rate for bullheading must be fast enough to exceed the rate of gas migration. If pump pressures increase instead of decreasing, this is an indication that the pumping (injection) rate is too slow to be successful. This can be a problem in a large diameter hole. 6. The possibility of breaking down the formation of long open hole sections beyond the last casing shoe rather than the producing formation. This could provoke the development of an underground blowout. Bullheading procedure 1. 2. 3.
4.
Ensure that sufficient fluid of the current weight is available for the operation and that the line to the kill pump suction is clear. Line up BOP and choke manifold to pump down lower kill line. Perform pressure test of the surface equipment to above the maximum injection pressure. Start the bullheading operation at a sufficiently slow rate such that the volume versus rate relationship can be monitored. Attempt to keep the rate constant during the operation and plot up volume versus rate as per leak off graph. Allow for the compressibility of the drilling fluid as the pressure is brought up to the injection pressure. As bullheading continues, the surface pressures should theoretically decrease as lower density influx is displaced by higher density fluid. Surface pressures should be monitored and plotted at regular intervals to check that the influx is being bullheaded away. If the injection pressure does not fall it may be as a result of fluid being injected into a formation above the influx. See Fig 81 Index 03 Page 215
MTC
5.
6.
7.
WELL CONTROL MANUAL
The injection pressure may increase during the operation as the permeability of the reservoir is damaged. If the injection pressure approaches the maximum allowable surface pressure, stop the pumps and allow the pressure to stabilise. Recommence at a slower rate keeping within the maximum pressure limitations. If it becomes impossible to bullhead without exceeding maximum pressure limitations i.e. fracture pressure, the decision to continue bullheading operations in excess of this pressure will depend upon the volume of the remaining influx and the position of the bit in the hole. Once the calculated volume of influx has been bullheaded back to the formation, bleed off trapped pressure and shut in the well to monitor drill pipe and casing pressures. If the shut-in pressures have fallen, then it is a fair assumption that the operation has been partially successful. It should be remembered that if the kick was taken whilst drilling. It is unlikely that the drill pipe and casing pressures will read the same due to the dissemination of the influx in the fluid. If bullheading was seen to be successful, then it should be continued until the drill pipe and casing pressures are similar. The subsequent well kill operation to secure the well will depend on how the kick was taken. a. If the influx was taken whilst drilling, then the well can be killed using the wait and weight method utilising the original shut in pressure information. b. If the pipe is off-bottom, then it will be necessary to strip back to bottom using standard stripping procedures. A circulation of minimu bottoms up should then be performed, maintaining constant bottom hole pressure, to clear the hole of disseminated gas. If the procedure is not seen to be successful, then consideration will have to be given to: a. Stripping back to bottom if necessary and circulating out the influx at a rate dependent on its size and the limitations of the surface equipment. b. Beginning operations leading to the suspension of the well.
Index 03 Page 216
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WELL CONTROL MANUAL
1300 Formation Strength 1100 900
1
Pump Pressure
700
2
500
3 300
100
Volume pumped Fig 81
1:
Bullheading taking place over the influx with plugging of the formation taking place.
2:
Bullheading taking place over the influx.
3:
Bullheading influx into the formation as pump pressure reduces.
Index 03 Page 217
MTC 12
WELL CONTROL MANUAL
KICK WITH BIT OFF BOTTOM
01.12 Introduction During drilling, completion and work-over operations it sometimes becomes necessary to trip tubular through the BOP’s under pressure. The procedures used are called Stripping and Snubbing. Stripping: This procedure is used when the pipe weight is sufficient to overcome the upward force created by well pressure acting on the cross-sectional area of the pipe. Snubbing: This procedure is used when the pipe weight is not sufficient to overcome the upward force created by well pressure on the cross-sectional area of the pipe. In this case an external force must be applied to move the pipe through the BOP’s. 02.12
Stripping
Stripping is an emergency well control procedure. It requires good planning, proper training of personnel and careful execution. The primary objective of the stripping operation shall be to maintain a constant bottom hole pressure, thus preventing a build up of excessive wellbore pressures or influx from exposed permeable zones. The following are guidelines for carrying out a successful stripping operation: 1. Pressure control is based on a volume balance. This means that for every barrel of pipe stripped into the hole, a barrel of mud must be bled off. Since it is necessary to install an Inside BOP before stripping, total displacement must be considered, including both pipe displacement and internal capacity. 2. Mud bled from the annulus must be accurately measured in order to maintain the correct volume balance. 3. Annulus pressure should not be constant while stripping pipe into the hole. It should gradually increase as the pipe is stripped into the lower density kick fluid. This is due to the increased length or height of the influx fluid in the annulus and the resultant loss of hydrostatic pressure. 4. When stripping through the annular preventer, the closing pressure on the preventer must be adjusted to allow a small amount of leakage to lubricate and reduce wear on the sealing element. The mud, which is allowed to leak past the annular preventer, should be measured along with the mud bled through the adjustable choke. 5. Drill pipe with casing wear protectors should never be stripped through the annular preventer, because excess friction and wear would be generated due to the rubber to rubber contact. 6. If stripping is to be carried out with two sets of pipe rams, then a side outlet is required between the rams. This is necessary to enable the pressure to be equalised, before opening the rams. Opening rams without equalising the pressure will shorten the life of the sealing element and create excessive pressure surge in the BOP. Pressure from the well must not be used to equalise the pressure across the rams. Note: The objective in all stripping operations is to maintain a constant bottom hole pressure, slightly greater than the formation pressure, throughout the entire operation.
Chapter 03 Page 218
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WELL CONTROL MANUAL
03.12 Closing procedures Stripping procedures must be adjusted to suit the well conditions and the equipment, which is available. A specific procedure should be developed for each situation. The following guidelines provide a basis for the design of detailed procedures closing in the well on a kick, with pipe off bottom and stripping back to bottom: To avoid excessive surface pressures, the correct closing in procedure as outlined should be adopted, i.e. Close in the well at the first indication of flow. 1. 2. 3. 4. 5. 6. 7. 8.
Install a DPSV (Drill pipe safety valve) on the drill pipe, in the open position. Close the DPSV. Close the annular preventer. Open the HCR valve. Close the automatic choke (if not already closed). Make up Topdrive. Open the DPSV. Record and monitor the drill pipe and the casing pressure.
Ensure that the above steps are executed as quickly as possible. The IBOP can be installed when ready to strip in. 04.12 Rig layout for combined stripping and volumetric method In general, the annular preventer is used for stripping pipe into or out of the hole. The annular preventer allows the use of one preventer and permits the tool joints to pass through the packing element without creating excessive pressure surge in the well bore. To minimise the wear, the pipe should be well lubricated with grease and closing pressure applied to the annular preventer kept to a minimum. A surge bottle should be installed as close to the annular preventer as possible. See Fig 82.
ACCUMULATOR BOTTLE PRECHARGE @ 400 PSI
OPEN
ANNULAR PREVENTER
Fig 82
BALL VALVE CLOSE
Chapter 03 Page 219
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WELL CONTROL MANUAL
Regardless of the method used to strip pipe into the hole and enable effective pressure control, it is very important to measure all of the fluid that comes out of the well bore. Formation fluid that has entered the well bore may be gas and during stripping operation migration may take place, so it is essential that rigs are suitably rigged-up to immediately implement the volumetric method. See Fig 83. 1.
Annular preventer. See Fig 82
2.
Accurate pressure gauge.
2
1
3.
Adjustable choke.
4.
Piping from choke manifold to trip tank.
5.
Calibrated trip tank.
6.
Calibrated stripping tank.
3
4
5
6
Fig 83
05.12 Procedure 1. After closing in the well, determine the influx volume and record pressures at two minute intervals. After closed in pressures have stabilised; further record pressures at five minute intervals. 2.
Determine a convenient working pressure increment Pw
3.
Convert the working pressure Pw of say 50 psi into an equivalent working volume V in the OH/DC annulus (the volume of fluid to be used for volumetric control steps). See Fig 84. PW x Cap V = Cap x h = -------------MWG
Chapter 03 Page 220
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WELL CONTROL MANUAL
Fig 84
Fig 85
V H2 Expansion of gas influx V
4.
H1
Determine the extra back pressure Ps to compensate for the loss of hydrostatic pressure as the bit and drill collars are run into the influx. If the influx is assumed to be in the open hole beneath the bit, an increase in surface pressure will be required to maintain BHP above Pf when this event occurs. It is unknown when the extra back pressure will be required since the exact position of the influx is unknown; it is therefore advisable to adopt a suitable safety factor from the very start of the stripping operation. Since overbalance (trip margin) will exist in nearly all wells which kick during round tripping, it is not possible to use closed in annulus pressure SICP to make an accurate estimate of the magnitude of the influx and thus the additional back pressure required to compensate for the previous mentioned loss of hydrostatic head. It is therefore essential to accurately measure the influx volume gained at surface, and by application of a factor based on the ratio open hole to DC/OH annulus, calculate the expected loss of hydrostatic head as the DC’s enter the influx. See Fig 85. (Mud Gradient - Influx Gradient) x Influx Volume Ps = ---------------------------------------------------------------------DC/OH Capacity
5.
Adjust the closing pressure on the annular preventer to a minimum, but avoid leakage. Whilst reducing closing pressure check continuously for flow.
6.
Allow annulus pressure to build up to PCHOKE whilst stripping the first stand. PCHOKE = SICP + PS + PW Initial closed in annulus pressure before second build Where SICP = up. PS = Allowance for the loss of hydrostatic head as DC’s enter the influx. PW = Working pressure increment. See Note #1 Chapter 03 Page 221
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7.
Maintain PCHOKE constant whilst further stripping pipe. The volume increase due to closed end displacement of drill pipe is purged into the trip tank and after stripping the entire stand bleed off into the stripping tank the volume equal to the closed end displacement of one stand. The increase in the trip tank volume is due to the expansion of the gas influx only and reflects the loss of hydrostatic head in the well. See Note #2
8.
Avoid excessive surge pressures by adjusting the pipe lowering rate to allow chokeman to maintain PCHOKE constant.
9.
Maintain PCHOKE constant at the above value until a volume of mud V bbl has accumulated in the trip tank while simultaneously strip pipe in the hole.
10.
When the additional mud volume V bbl has accumulated in the trip tank (at constant choke pressure), PCHOKE is allowed to increase again by value PW and now becomes PCHOKE1.
Pchoke + Pw= Pchoke1
V
PCHOKE1 = PCHOKE + PW See Fig 86 11.
Fill each stand run and file off any sharp edges or tong marks from the pipe body and tool joints. Coat drill pipe with grease prior to stripping in the hole.
Pw
Expansion of gas influx
Fig 86
12.
By repeating this cycle, as often as necessary gas is able to percolate upwards and expand while a nearby constant BHP is maintained.
13.
Values of pressure and volume should be recorded in table throughout the stripping exercise.
With the bit on bottom the well can be killed using the “Driller’s Method” first circulation, but first ensure that the entire string is full of mud. Note 1: A length of the first stand will be stripped against the closed in well until the required stripping choke pressure, PCHOKE, has been reached. Only the remainder of the stand, which is stripped at constant choke pressure, should be considered when bleeding off the closed end displacement volume. For example, if the required PCHOKE is reached after stripping two singles of the first stand, only one third of the closed end displacement volume should be bled off into the stripping tank. The same principle will of course apply when PW increment are added.
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Note 2: Should, during the stripping operation, bottom hole pressure inadvertantly drop below formation pressure (BHP < PF), a second influx will take place. The method makes allowance for this eventuality and re-established the required PCHOKE by overcompensating for the loss of hydrostatic pressure caused by the new influx. This is achieved automatically due to the manner in which PW has been calculated. PW compensates for loss of hydrostatic pressure assumed opposite the DC’s. A second influx will enter in the open hole section resulting in a volume gain at surface, where it will be interpreted as a volumetric step. The well will be closed in and PCHOKE allowed to increase by PW. The effect, of course, will be to overcompensate the underbalance that existed in the well. In other words it is impossible to loose hydrostatic control of the well since the method is self correcting. 06.12 Snubbing Snubbing involves moving pipe in and out of a well under pressure, while maintaining constant bottom hole pressure. The operation is very similar to stripping except that the pipe will not move into the well under its own weight and must be forced in through application of external force at the surface. Snubbing operations are much more dangerous than stripping operations and always involve the use of specialised equipment and personnel. Two types of snubbing system are generally employed namely mechanical snubbing units and hydraulic snubbing units. Mechanical snubbing units require the use of the drilling rig’s hoisting system, while hydraulic snubbing units are self contained.
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GAS CUT DRILLING FLUID
01.13 General Gas cut drilling fluid is the term used when the drilling fluid contains a percentage of gas in the form of small bubbles, when it returns to the surface. Generally gas cut drilling fluid does not decrease the hydrostatic pressure so much as to cause underbalance/kick situations. This is because the gas content in the drilling fluid is mostly compressed, except very close to the surface. Every atmosphere (14.7 psi) reduces the gas volume by half. Therefore the drilling fluid weight considerably reduces the volume of the gas. If the volume of the gas in the drilling fluid is very small the reduction in bottom well pressure will also be very small. Fig. 87 shows a typical example of pressure reduction bottom well caused by gas cutting of drilling fluid. 20
g
33.3% cut ppg
5 pp
-9 pg
g10 p p
50% cut
18 p
3
ppg 18 ppg - 13 .5 ppg 10 ppg - 6.66 p pg 18 ppg - 12 pp g
4
25% cut
10 ppg - 7.5
5
18 ppg - 16.2 ppg
7 6
10% cut
10 ppg - 9 ppg
DEPTH in 1000ft
10 9 8
2
1 0
20
40
60
80
100
120
DECREASE IN BHP (psi)
Fig 87 It is very important to understand that the gas expanding as it nears the immediate surface causes almost all the bottom well pressure reduction. Therefore flow line drilling fluid weight can be very low in some cases. 02.13 Causes of gas cut drilling fluid Gas cut drilling fluid can occur because of three reasons: 1.
When a gas bearing formation is penetrated the cuttings will always release an amount of gas into the drilling fluid. This will be the first gas to register at the surface, and is a positive indication that a gas bearing formation has been penetrated. This type of gas
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will not cause a drilling fluid weight reduction, but if there is any doubt, pick up the drill string, shut down the drilling fluid pumps and check for flow. 2.
Another cause of gas cut drilling fluid is that some formations with a very low permeability have a pore pressure, which is bigger than the hydrostatic pressure from the drilling fluid column. So long as the drilling fluid is circulated there is a small overbalance in the well because of pressure loss in the annulus. When circulation is stopped a small underbalance will occur, ant this causes varying amounts of gas to intrude into the wellbore. This often occurs when the pumps are shut down during a connection or during a trip and these conditions are respectively called Trip Gas and Connection Gas.
3.
The third cause of gas cut drilling fluid can be a washout in the wellbore. This washout or cavity acts as a trap for old gas cut drilling fluid which is picked up by the drilling fluid at a later period in time and transported to the surface.
Calculations to estimate the change in hydrostatic pressure caused by gas cut drilling fluid Reduction of bottom well pressure caused by gas cut drilling fluid can be calculated by using the following formula: ∆ P = 2.3 x N x Log BHP ∆P
=
Reduction in pressure in physical atmospheres where 1 ATM = 14.7 psi.
N
=
Original MW – Gascut MW Gascut MW
BHP =
Bottom hole pressure in physical ATM.
Example:
Well depth OMW GMW
12000 ft 14 ppg 7 ppg
12.000 x 0.052 x 14 14 - 7 x log------------------------------P = 2.3 x ----------= 6.37 ATM 14.7 7
94 psi
The pressure in the well (bottom well) is therefore reduced by 94 PSI which answers to a change in drilling fluid weight of 0.15 ppg. A more practical and precise method for calculating bottom hole pressure reduction is reached by using the volumetric method. The volumetric method is used in the following way. The volume increase in the drilling fluid tanks that has flowed back due to gas cut drilling fluid is measured.
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This figure can be used to calculate the change in hydrostatic pressure in psi/bbl units by the following formula: ∆P=
∆ Pit volume x (0.052 x OMW) Annular capacity at surface
Fig 87 shows that even with a flow line weight reduction of 50% through gas cutting, bottom hole pressure is not seriously affected, as the reduction is less than the change that is caused through pressure loss in the annulus. Although pressure reductions from gas cut seldom cause underbalance, there are other factors that can lead to dangerous situations. Foremost gas cut drilling fluid is an indication of (possible) low drilling fluid weights, and pump effectiveness can be seriously reduced by gas cut drilling fluid. If drilling fluid becomes seriously gas cut the pump output is seriously decreased, that can lead to a following fall in annulus pressure loss, fall in bottom hole pressure and therefore risk of influx and blowout. It is therefore most important that gas cut drilling fluid is de-gassed (gas content extracted) before it is pumped down hole again. It may be that he most common fault in connection with gas cut drilling fluid is the tendency to maintain the original drilling fluid weight with barite without removing all the gas from the drilling fluid. When a moderate gas cutting gives a relatively small change in hydrostatic pressure, it is possible that addition of barite to increase drilling fluid weight can lead, in extreme cases, to lost circulation. 03.13
Gas Kicks in Oil Based Mud
Early detection of gas kicks in oil based mud is of particular importance. The behaviour of hydrocarbon gases in an oil based drilling fluid is fundamentally different from their behaviour in a water based drilling fluid. These differences must be understood to allow safe handling procedures to be followed. The solubility of methane in diesel oil is approximately 100 times greater than in water, and therefore comparatively large gas flows (10 MMSCFD) can be taken into solution when circulating an oil based drilling fluid. The volume of the resulting solution is approximately equal to the sum of the gas and oil components, and therefore an influx will result in both a pit gain and an increase in return flow rate, as for a water based fluid. As shown in Fig 88 the expansion of a gas in oil solution, with decreasing pressure, is different from the expansion of the gas that occurs when a water based fluid is in use.
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0
0 2.000 PRESSURE (PSI)
PRESSURE (PSI)
2.000 Methane alone 4.000 6.000
4.000 6.000
8.000
8.000
10.000
10.000 1
10
100
4% Methane in diesel
1
RELATIVE VOLUME
10
100
RELATIVE VOLUME
Fig 88 When a water-based fluid is in use, gas expansion occurs continuously, and the kick is therefore comparatively easy to detect. With an oil based mud there is negligible expansion until the solution reaches the bubble point, but at pressures below the bubble point the expansion is very rapid. The bubble point can be very difficult to determine due to a lot of unknown factors, but Fig 89 shows a typical phase equilibrium. Zone A:
For pressure above the bubble point line and below the critical temperature the material in the reservoir is a liquid.
Zone B:
For pressure above the dew point line the material in the reservoir is gas.
Zone C: Zone D:
For material outside the dew line the material is always gas. For material within the phase envelope the material is a 2 phase equilibrium mixture of free gas and its associated liquid.
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7000
Zone B
Zone C 3
LIQUID
FREE GAS
1 Critical Point
6000
Lin e oin t Bu bb le P
10%
25%
2
e t Lin Poin
PRESSURE PSI
Dew
2-Phase Zone D
4
40%
0 - 200
400
TEMPERATURE F
800
Fig 89
If a hydrocarbon liquid at point 1 is expanded down line from 1 to 2, the pressure reach the bubble point line and the liquid starts to evaporate (boil) and bubbles of gas appear within the liquid. As the expansion proceeds more gas is produced at the expense of liquid. If hydrocarbon gas at point 3 is expanded down a line to point 4, the pressure is reduced to the dew point line and droplets of liquid starts to appear in the gas (the gas condenses). As the expansion proceeds, more liquid is produced at the expense of gas. 04.13 Influx volume In all previous calculations in well control we have presumed that the measured pit gain after shutting in the well was equal to the size of influx in the well bore. This prediction is due to that liquid is incompressible, witch is in fact not quit right. When performing a leak off test a certain amount of fluid is required to obtain pressure in the well bore. The greater the annular capacity is and the higher pressure applied the more volume has to be pumped into the well bore. This pressure/volume effect will also be applicable when looking on the size of an influx into the wellbore. As we drill deeper and longer the annular capacity is greatly increased and compression of the fluid has to be taking into consideration to determine if the handling capacity of our surface equipment is sufficient.
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Fig 90 shows the compressibility of a water base drilling fluid system: Barrels of Water-base drilling fluid pressurised
Applied Pressure
500
600
700
800
900
1000
1100
1200
1300
1400
1500
500
0.75
0.90
1.05
1.20
1.35
1.50
1.65
1.80
1.95
2.10
2.25
1000
1.50
1.80
2.10
2.40
2.70
3.00
3.30
3.60
3.90
4.20
4.50
1500
2.25
2.70
3.15
3.60
4.05
4.50
4.95
5.40
5.85
6.30
6.75
2000
3.00
3.60
4.20
4.80
5.40
6.00
6.60
7.20
7.80
8.40
9.00
2500
3.75
4.50
5.25
6.00
6.75
7.50
8.25
9.00
9.75
10.50
11.25
3000
4.50
5.40
6.30
7.20
8.10
9.00
9.90
10.80
11.90
12.60
13.50
3500
5.25
6.30
7.35
8.40
9.45
10.50
11.55
12.60
13.65
14.70
15.75
4000
6.00
7.20
8.40
9.60
10.80
12.00
13.20
14.40
15.60
16.80
18.00
Fig 90
Example: A 10 bbl measured influx in a water base drilling fluid system of 1400 bbl and a SIDPP of 1000 psi. Influx to handle on surface:
10 bbl + 4.20 bbl = 14.20 bbl
This means that the 10 bbl influx measured as pit level increase is actual a 14.20 bbl influx, witch means that the volume of gas we have to handle on surface is 42% higher than expected. When drilling with oil base drilling fluid the problem increases considerably and especially in the HPHT wells we are drilling to day we have to take this fluid compression seriously when evaluating handling method of an influx into the well bore. See Fig 91. Example: A 10 bbl measured influx in an oil base drilling fluid system of 1400 bbl and a SIDPP of 1000 psi. Influx to handle on surface: 10 bbl + 7.00 bbl = 17.00 bbl This means that the 10 bbl influx measured as pit level increase is actual a 17.00 bbl influx, witch means that the volume of gas we have to handle on surface is 70% higher than expected. Barrels of Oil-Base drilling fluid pressurised
Applied pressure
500
600
700
800
900
1000
1100
1200
1300
1400
1500
500
1.25
1.50
1.75
2.00
2.25
2.50
2.75
3.00
3.25
3.50
3.75
1000
2.50
3.00
3.50
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
1500
3.75
4.50
5.25
6.00
6.75
7.50
8.25
9.00
9.75
10.50
11.25
2000
5.00
6.00
7.00
8.00
9.00
10.00
11.00
12.00
13.00
14.00
15.00
2500
6.25
7.50
8.75
10.00
11.25
12.50
13.75
15.00
16.25
17.50
18.75
3000
7.50
9.00
10.50
12.00
13.50
15.00
16.50
18.00
19.50
21.00
22.50
3500
8.75
10.50
12.25
14.00
15.75
17.50
19.25
21.00
22.75
24.50
26.25
4000
10.00
12.00
14.00
16.00
18.00
20.00
22.00
24.00
26.00
28.00
30.00
Fig 91
Chapter 03 Page 229
MTC 14 01.14
WELL CONTROL MANUAL
DEVIATED AND HORIZONTAL WELL CONTROL Introduction
From its early beginnings in the 1920s when it was regarded as a “black art”, directional and horizontal drilling has evolved to the point where it can truly be regarded as a science, although not always an exact science. The offshore and onshore drilling industry is founded on directional and horizontal drilling. Without the use of directional drilling techniques, it would not be economical to produce oil from most offshore fields. Improvements in directional drilling tools and techniques coupled with advances in production techniques have led to a steady increase in the production of wells drilled directionally and horizontal rather than vertically. As the search for oil and gas extends into ever more hostile and demanding environments, this trend will continue. This also means that normal well control practices used in vertical wells have to be altered to meet the new demand for deviated/horizontal well control. The true vertical depth of the wells drilled to day is getting less while the measured depth is increasing making it harder to control bottom hole pressure and ensure that the influx is circulated out. The normal preferred method in circulating out an influx is the “Wait and Weight” witch means that the increasing hydrostatic pressure causes the drill pipe pressure to fall when circulating kill fluid from surface to bit. Pump strokes represent a certain measured length of fluid in the drill pipe. In a vertical well, the measured length of the fluid is the same as the vertical length of the fluid. In a deviated well, the vertical length of the fluid is less than the measured length of the fluid. This means that the pressure will drop less in a deviated well than in a vertical well per stroke. By calculating an average pressure drop across both the vertical and deviated sections of the well, the pressure will drop too slowly in the vertical section of the well. This means that by using our regular kill sheet in a deviated or horizontal well we tend to overpressure the well, which can lead to stuck pipe and lost circulation. These problems not only exist in deviated wells, but can also be created in vertical wells. We will have a look on a few pressure developments while circulating out an influx using the “Wait and Weight” method.
5 bbl
Ph
5 bbl
Ph
In a drill string with different size tubular (tapered string) the internal diameter change witch means that 5 bbl drilling fluid in a 5” drill pipe does not create the same column height as if the 5 bbl was contained in a 3-1/2” drill pipe. This means that the hydrostatic pressure created when pumping kill fluid through the 5” drill pipe per stroke is less than through a 3-1/2” drill pipe. This requires that the pump pressure must be reduced faster per pump stroke in smaller size pipe. See Fig 92.
H
H
Fig 92
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With a tapered string in the well bore using the “Wait and Weight” method the red dotted line represent the theoretical pressure graph when circulating kill fluid to the bit from ICP to FCP. The blue line represents the true pressure graph to follow using “Wait and Weight” method. By using the theoretical pressure graph it can be seen that while kill fluid is circulated to the bit the well is in underbalance creating further influx into the well bore with resulting higher annulus pressures. See Fig 93. FCP
Fig 93
ICP
FCP
In a deviated well with a uniform string using the “Wait and Weight” method the red dotted line represent the theoretical pressure graph when circulating kill fluid to the bit from ICP to FCP. The blue line represents the true pressure graph to follow using the “Wait and Weight” method. By using the theoretical pressure graph it can be seen that while kill fluid is circulated to the bit the well is in overbalance witch can lead to further serious well control problems like lost circulation that again can lead to underground blow-out. See Fig 94.
Fig 94
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ICP
In a “S” shaped well with a uniform string using the “Wait and Weight” method the red dotted line represent the theoretical pressure graph when circulating kill fluid to the bit from ICP to FCP. The blue line represents the true pressure graph to follow using the “Wait and Weight” method. By using the theoretical pressure graph it can be seen that the well is first in overbalance witch can result in losses and then later the well becomes underbalanced taken in more influx with resulting higher annulus pressures. See Fig 95. Fig 95 FCP
IC P
FCP
Fig 96
In a horizontal well with a uniform string using the “Wait and Weight” method the red dotted line represent the theoretical pressure graph when circulating kill fluid to the bit from ICP to FCP. The blue line represents the true pressure graph to follow using the “Wait and Weight” method. By using the theoretical pressure graph it can be seen that while kill fluid is circulated to the bit the well is in extreme overbalance witch can lead to serious additional well control problems. See Fig 96. By using the deviated well control sheet the true pressure graph can be calculated. Chapter 03 Page 232
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Fig 96a
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96b
Chapter 03 Page 234
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96c
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02.14 Complications When taking a gas influx into a horizontal well bore some associated problems might be encountered and have to be taking into consideration. The density of the gas is lower than the density of the drilling fluid with the result that the gas will accumulate in the top of the well bore in the horizontal section. See Fig 97.
Fig 97
When a gas influx is taken in the horizontal part of the well bore it can be hard to detect. The gas will not percolate and expand before it reaches the deviated section. An undetected swabbed gas kick in a horizontal section can be dangerous due to that no surface pressure will be observed and the first indication will take place when new tubular are run into the well bore or circulation is resumed. See Fig 98. Fig 98
Open hole sections are not looking like a gun barrel due to that there will be angle deviations, hole enlargement and the well can be inverted with the result that gas influx in horizontal section will be accumulated in these pockets. To be able to flush the gas out of the well bore the annular velocity must be high to force the gas to move in the horizontal section. See Fig 99.
Fig 99 Attempt to circulate gas out of the horizontal section with normal kill rate pressure will not be successful due to flow being laminar and the high density kill fluid having a tendency to flow along the lower part of the well bore. See Fig 100. Fig 100
A gas kick taking in a horizontal well section is most likely due to drilling through a fault with the result that there is a great chance for losses at the same time due to the difference in formation pressure.
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03.14 Horizontal well control example
KOP TVD/MD 4200 ft
SHOE
Hole size Hole TVD Hole MD KOP MD/TVD EOB TVD EOB MD Csg 10-3/4” TVD Csg 10-3/4” MD BHA DP cap. DC cap OH/DC cap OH/DP cap Csg/DP cap SIDPP SICP Influx volume RRCP
8-3/4” 6130 ft 16330 ft 4200 ft 5470 ft 6178 ft 6200 ft 8200 ft 80 ft 0.01755bbl/ft 0.0066 bbl/ft 0.03014 bbl/ft 0.04896 bbl/ft 0.07373 bbl/ft 410 psi 450 psi 8.2 bbl 450 psi
TD TVD 6130 MD 16330
EOB TVD 5470 ft MD 6178 ft
Fig 101
By using the example in Fig 101 the kill sheet can be filled capacity/stroke data be obtained: Internal Surface to KOP 73,7 bbl KOP to EOB 34,7 bbl EOB to BHA 176,8 bbl BHA 0,5 bbl External BHA/OH 2,4 bbl DP/OH 394,1 bbl DP/Csg 604,6 bbl
out and the following 703 stks 331 stks 1.687 stks 5 stks 23 stks 3.760 stks 5.769 stks
Calculations: A) Calculate the required kill fluid density: SIDPP 410 KMW = OMW + ----------------= 14.3 + -----------------= 15.6 ppg TVD x 0.052 6130 x 0.052
B) Calculate initial circulation pressure: ICP = RRCP + SIDPP = 450 + 410 = 860 psi
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C) Calculate final circulating pressure: KMW = 450 x ----------15.6 = 491 psi FCP = RRCP x -----------OMW 14.3
D) Calculate dynamic pressure loss at kick off point: 4200 = 461 psi RRCP at KOP = RRCP + (FCP - RRCP) xKOPmd ---------- = 450 + (491 - 450) x ----------TDmd 16330
E) Calculate remaining SIDPP at kick off point: SIDPP at KOP = SIDPP - (KMW - OMW) x 0.052 x KOPtvd = 410 - (15.6 - 14.3) x 0.052 x 4200 = 126 psi
F) Calculate circulating pressure at kick off point: CP at KOP = (D) + (E) = 461 + 126 = 587 psi
G) Calculate dynamic pressure loss at end of build: 6178 = 466 psi RRCP at EOB = RRCP + (FCP - RRCP) xEOBmd ---------- = 450 + (491 - 450) x ----------TDmd 16330
H) Calculate remaining SIDPP at end of build: SIDPP at EOB = SIDPP - (KMW - OMW) x 0.052 x EOBtvd = 410 - (15.6 - 14.3) x 0.052 x 5470 = 40 psi
I) Calculate circulating pressure at end of build: CP at EOB = (G) + (H) = 466 + 40 = 506 psi
J) Calculate pressure drop per 100 strk from surface to KOP: (B - F) x 100 (860 - 587) x 100 = 38 psi Pdrop = -------------------------= -----------------------strokes 703
K) Calculate pressure drop per 100 strk from KOP to EOB: (F - I) x 100 - 506) x 100 = 24 psi Pdrop = -------------------------= (587 -----------------------strokes 331
L) Calculate pressure drop per 100 strk from EOB to TD: (I - C) x 100 - 491) x 100 = 1 psi Pdrop = -------------------------= (506 -----------------------strokes 1692
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04.14 Wait and weight method The “Wait and Weight” method is also called the “balance method” witch means that the kill fluid is pumped to the bit holding BHP constant by adjusting the choke to keep the precalculated drill pipe pressure on schedule according to the graph. To use “Wait and Weight” method in horizontal wells is not recommended due to that it requires a lot of calculations and the kill fluid has to be pumped to the bit at reduced rate to control the drill pipe pressure, with the result that the influx will stay trapped in the horizontal section. The following graph shows the drill pipe and casing pressure while circulating out the influx at the previous example using “Wait and Weight” method. See Fig 101.
1200 1100 1000 900
ICP
800
KOP
700 500
EOB
PRESSURE
600
FCP
400
Csg. Pressure
300
Gas at EOB
200 100 000 0
1500
3000
4500
STROKES
6000
7500
Fig 101
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9000
10500 12000
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WELL CONTROL MANUAL
05.14 Driller’s method This method is also called the “constant drill-pipe pressure method” and consists of two steps. First step to circulate out the influx without changing drilling fluid density and second to displace OMW with the KMW. This method does not require the same calculations as the “Wait and Weight” method and are therefore more simple, but not recommended due to using reduced rate for circulating the result could be that the influx will stay trapped in the horizontal section. The following graph shows the drill pipe and casing pressure while circulating out the influx at the previous example using “Driller’s Method”. See Fig 102.
1200 1100 1000 DP Pressure
900 800 PRESSURE
700 600 500 400
KMW at EOB Csg. Pressure
300
Gas at EOB
200 100 000
STROKES
0
3000
6000
9000
12000
15000 18000 21000 24000
Fig 102
06.14 Horizontal well kill method To circulate out a influx in a horizontal well bore the annular flow must be so high that the flow becomes turbulent and test have showed that a annular velocity of at least 100 ft/min is required. The industry recommendation is to use the “Driller’s Method” with modification to handle an influx in a horizontal well and the following is only guidelines:
• • • • •
Prepare calculations for using “Driller’s Method”. Calculate open hole strokes from bit to end of horizontal section. Keep constant casing pressure while bringing pumps to required SPM to give minimum 100 ft/min annular velocity. Keep constant drill pipe pressure while flushing influx out of horizontal section. Keep constant casing pressure while bringing pumps down to reduced circulating rate. Chapter 03 Page 240
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WELL CONTROL MANUAL
Continue circulating influx out of the well bore using “Driller’s Method” With influx out of well bore keep constant casing pressure while pumping kill fluid to bit using reduced circulating rate. With kill fluid at bit keep constant casing pressure while bringing pumps to required SPM to give minimum 100 ft/min annular velocity. Keep constant drill pipe pressure while flushing light drilling fluid out of the horizontal section. Keep constant casing pressure while bringing pumps down to reduced circulating rate. Continue circulating light drilling fluid out of the well bore using “Driller’s Method”.
Chapter 03 Page 241
MTC 15
WELL CONTROL MANUAL
RUNNING / PULLING PIPE.
01.15 Introduction Most well control incidents take place during tripping pipe for different reasons, but in general they can all be considered to be negligence from the drilling team. The negligence could be due to a single circumstance or a combination of several circumstances. The reasons for well control incidents during tripping could for the following reasons: 1.
The effect of pumping a slug.
2.
Inadequate hole fill.
3.
Hole not taking correct amount of fluid.
4.
Hole not giving correct amount of fluid.
02.15 Pumping slug Pumping a slug prior to pulling out of hole is a well-known procedure in the drilling industry. The slug is a heavy pill of drilling fluid with a density higher than the drilling fluid used during drilling. The slug is pumped into the drill pipe prior to start pulling the drill string out of hole and due to its higher density will create a U-tube effect allowing the fluid level inside the drill string to drop. The drill string can then be pulled dry avoiding any pollution on the rig floor, so the roughnecks do not get in contact with the drilling fluid. Prior to pumping a slug it is important that calculation are made to determine the amount of fluid that will be drained back into the trip tank due to the U-tube effect as this will be indicating if the well is in balance. Tripping should not start before the U-tube effect is finished and the correct amount of this effect has been measured in the trip tank. As the amount of slug pumped is known together with the internal capacity of the drill pipe in use the following formulas can be used to determine the level drop inside the drill pipe and the volume to be drained back into the trip tank:
Slug pumped (bbl) Length of slug = ----------------------------------DP Capacity (bbl/ft) Slug MW (ppg) Level Drop = Length of slug (ft) x -------------------------- — Length of slug (ft) Original MW (ppg) Trip tank return = Level Drop (ft) x DP Capacity (bbl/ft)
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Example: Drilling fluid density Slug density Slug volume Drill pipe capacity
12.6 14.5 22 0.01776
ppg ppg bbl bbl/ft
The slug is pumped and the surface lines displaced by original drilling fluid. The Topdrive is disconnected and the slug allowed to drop. See Fig 103 Calculate:
Length of slug. Level drop. Trip tank return
22 bbl Length of slug = ----------------------- = 0.01776 (bbl/ft)
1239 ft
14.5 (ppg) Level Drop = 1239 (ft) x ------------------- — 1239 (ft) = 187 ft 12.6 (ppg) Trip tank return = 187 (ft) x 0.01776 (bbl/ft) = 3.32 bbl
PDP NATIONAL
PDP NATIONAL
Level drop Length of slug Length of slug Trip tank increase
Fig 103
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Effect on Bottom hole Pressure Pumping a slug prior to pulling pipe out of hole will not have any immediate effect on the bottom hole pressure due to the U-tube effect where pressure hydrostatic inside the drill pipe and in the annulus equalise. The bottom hole pressure will first be affected when the pipe is pulled so far out of the wellbore that the slug is starting getting out of the bit and the heavy slug density get mixed with the drilling fluid density. The increase in bottom hole pressure is not very high and is normally not taken into consideration. In HPHT wells where a very small margin exist between Pore pressure and Fracture pressure and a lot of tripping takes place consideration must be made to the effect on the bottom hole pressure when pumping a slug. Effect of pumping slug when running tapered string Slug calculations are normally based on pumping a heavy slug into a uniform string i.e. 5” drill pipe from surface to the BHA. Several time this is not the case due to that drilling takes place through 7” liners where either 4-1/2” or 3-1/2” drill pipe is used in the lower part of the drill string. The effect of pumping a slug into a tapered string are many time not understood by the drilling crew and the well shut in for the wrong reason with loss of rig time and unnecessary concern. To understand the problems with a slug in a tapered string it must be understood that every feet of drilling/slug fluid represent a certain pressure hydrostatic in the wellbore. When a slug goes from a 5” drill pipe into a smaller diameter drill pipe the length of the slug will increase and thereby also the pressure hydrostatic created by the slug. This will result in a further level drop and a trip tank increase. If this effect is not understood by the drilling crew and the increase in the trip tank is not calculated before hand this increase could be interpenetrated as an influx and the well shut in. Example: Drilling fluid density Slug density Slug volume Drill pipe capacity ( 5” ) Drill pipe capacity ( 4-1/2” )
12.6 14.5 22 0.01776 0.0142
22 bbl Length of slug in 5” DP = ----------------------0.01776 (bbl/ft) 22 bbl Length of slug in 4-1/2” DP = ----------------------0.0142 (bbl/ft) Trip tank return = (1549 ft - 1239 ft) x 0.0142 bbl/ft
ppg ppg bbl bbl/ft bbl/ft
= 1239 ft = 1549 ft = 4.4 bbl
or Ph of slug in 5” DP =
1239 ft x 14.5 x 0.052
= 934 psi
Ph of slug in 4-1/2” DP = 1549 ft x 14.5 x 0.052
= 1168 psi
(1168 psi - 934 psi) x 0.0142 bbl/ft Trip tank return = --------------------------------------------- = 4. 4 bbl 14.5 ppg x 0.052
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As can be seen on the calculation an expected extra return into the trip of 4.4 bbl must be expected when slug enter the 4-1/2” drill pipe and this volume needs to be calculated prior to tripping to avoid any misunderstandings when pulling pipe out of hole. 03.15 Inadequate hole fill. When pulling pipe out of hole it is important that the hole is kept full all the time to maintain the pressure hydrostatic in the well bore. If the pipe is pulled without adequate hole fill the level will drop in the well bore with the result of a decrease in the bottom hole pressure. If the decrease in the bottom hole pressure gets severe the well might get in underbalance resulting in an influx into the well bore. As all displacement and capacity figures is known for the pipe in use on a drilling rig the pressure drop for tripping pipe can easily be calculated using the following formulas: Pulling dry Drill Pipe: Drilling fluid density(ppg) x 0.052 x DP metal displacement(bbl/ft) Pressure drop per ft. pulling dry pipe = ------------------------------------------------------------------------------------------Casing capacity (bbl/ft) - DP metal displacement (bbl/ft)
Pulling wet Drill Pipe: Drilling fluid density(ppg) x 0.052 x DP closed end displacement(bbl/ft) Pressure drop per ft. pulling wet pipe = ------------------------------------------------------------------------------------------------Annular capacity (bbl/ft)
Pulling dry Drill Collars: Length of DC (ft) x DC metal displacement (bbl/ft) Level drop for pulling dry DC = -------------------------------------------------------------------------Casing capacity (bbl/ft)
Example: Pulling wet Drill Collars:
Length of DC (ft) x DC closed end displacement (bbl/ft) Level drop for pulling wet DC = -------------------------------------------------------------------------------Drilling fluid density 12.6 ppg Casing capacity (bbl/ft)
Drill pipe capacity ( 5” ) Drill pipe metal displacement ( 5” ) Drill Collar capacity ( 6-3/4” ) Drill Collar metal displacement ( 6-3/4” ) Length of Drill Collars Casing capacity ( 9-5/8” – 47 lbs/ft )
0.01776 0.00852 0.00768 0.03658 450 0.07287
Calculate the pressure drop per ft. pulling dry Drill pipe: 12.6 x 0.052 x 0.00852 ----------------------------------- = 0.0867 psi/ft 0.07287 - 0.00852
Calculate the pressure drop per ft. pulling wet Drill pipe: 12.6 x 0.052 x (0.01776 + 0.00852) ------------------------------------------------ = 0.3696 psi/ft 0.07287 - (0.01776 + 0.00852)
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bbl/ft bbl/ft bbl/ft bbl/ft ft bbl/ft
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Calculate level drop for pulling dry Drill Collars: 450 x 0.03658 ----------------------- = 226 ft 0.07287
Calculate level drop for pulling wet Drill Collars: 450 x ( 0.03658 + 0.00768) ------------------------------------- = 273 ft 0.07287
For different reasons it could be necessary drop the level in the annulus, but by doing so the bottom hole pressure will be reduced. If pulling pipe without filling the hole the amount of pipe that can be pulled before the well loses its overbalance can be calculated by using the following formulae: Pulling dry Drill Pipe: Overbalance (psi) x (Casing Capacity - DP metal displacement) Pipe to pull before well starts to flow (ft) = ------------------------------------------------------------------------------------------Drilling fluid density x 0.052 x DP metal displacement
Pulling wet Drill Pipe: Overbalance (psi) x (Casing Capacity - DP closed end displacement) Pipe to pull before well starts to flow (ft) = ------------------------------------------------------------------------------------------------Drilling fluid density x 0.052 x DP closed end displacement
Example: Drilling fluid density Drill pipe capacity ( 5” ) Drill pipe metal displacement ( 5” ) Drill Collar capacity ( 6-3/4” ) Drill Collar metal displacement ( 6-3/4” ) Length of Drill Collars Casing capacity ( 9-5/8” – 47 lbs/ft ) Depth of well (TVD/MD) Formation gradient
12.6 0.01776 0.00852 0.00768 0.03658 450 0.07287 10000 0.6995
ppg bbl/ft bbl/ft bbl/ft bbl/ft ft bbl/ft ft psi/ft
Dry pipe to pull before the well starts to flow: 10000 x (0.6995 - 12.6 x 0.052) x (0.07287 - 0.00852) -------------------------------------------------------------------------- = 5107 ft 12.6 x 0.052 x 0.00852
Wet pipe to pull before the well starts to flow: 10000 x (0.6995 - 12.6 x 0.052) x [(0.07287 - (0.00852 + 0.01776)] ---------------------------------------------------------------------------------------- = 1198 ft 12.6 x 0.052 x (0.00852 + 0.01776)
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04.15 Hole not taking correct amount of fluid. As mentioned before then all displacement and capacity of the tubular used on a drilling rig should be known so the correct calculated amount of fluid can be measured filling the hole as the pipe is pulled out of the hole. This measurement is carried out by the use of the Trip tank where the fluid volume can be measured either visual or by an electronic measuring devise. Any deviation in the correct calculated amount of fluid means that some abnormalities is taking place down hole and tripping must be stopped and the problem evaluated and rectified. If the hole is taking more fluid than calculated per stand tripped out of hole either wet or dry some dynamic losses is taking place and the situation needs to be evaluated. Minor dynamic losses when pulling out of hole could turn into severe losses when running back into the hole due to surge pressure created. Consideration should be made to run back to bottom and cure losses prior to comments tripping. If the hole is taking less fluid than the calculated per stand tripped out of hole either wet or dry indicates that the hole could be swabbing. The reason for swabbing could be due to balled bit/ BHA or due to very high viscosity combined with a low BHA annulus capacity. The less amount of fluid that the hole has taken could be formation fluid that has been swabbed into the well bore and depending on the amount of swabbed fluid the bit should be run or strip back to bottom and the well circulated clean prior to commence tripping or alternative pumping out of hole. If the formation is tight the swabbed fluid could come from the drill pipe with the result that the fluid level inside the drill pipe has been lowered and thereby the pressure hydrostatic. If the level drop inside the drill pipe becomes severe the hydrostatic pressure inside the drill pipe might drop below formation pressure. This result could be that the formation starts producing and formation fluid could enter the drill string creating complications. Prior to tripping it is of extreme importance that swab pressure is calculated and the correct pulling speed found to avoid swabbing tendency. 05.15 Hole not giving correct amount of fluid. When running the drill string into the well bore it is of equal importance that the fluid coming back for the pipe run is measured as any deviation from the calculated amount means that some abnormalities is taking place down hole. The tripping has to stopped and the problem rectified prior to continue running in. If the volume coming back is higher than the calculated volume this could indicate that the bit or drill string is plugged and that the pipe is not filled as running in. Circulation has to be established and the bit/string unplugged before continue tripping. If a drill pipe float is installed in the drill string circulation should be broken every 1500 ft to avoid excessive collapse pressure on the drill string. If the volume coming back is less than the calculated volume the reason could be that the tripping speed is to high and excess surge pressure is created on the formation which results in losses. Prior to tripping it is of extreme importance that surge pressure is calculated and the correct running speed found to avoid breaking down the formation.
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Chapter 4
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Chapter 04 Page 250
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Chapter 5
Chapter 05 Page 251
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Chapter 05 Page 252
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Chapter 6
Chapter 06 Page 253
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Chapter 06 Page 254
