Well Control Manual
Well Control Manual
Rev 1.01, June 2010
FOREWORD This Well Control Manual has been prepared to document the requirements of KCA D EUTAG with respect to Well Control Management and assist in the implementation of proper Well Control practices and procedures. This document is not a a Training Manual (for which the reader is referred to the KCA D EUTAG DART Well Control Training Manual) and assumes the user has Well Control knowledge to the level of IWCF or WellCAP. However, where appropriate, some theory and additional information has been included such that all appropriate background information is included in one reference document. The Manual has been based on the input from many sources, and has been agreed by representatives of each Area and the E&M Function and therefore expressly documents KCA DEUTAG’s mandatory requirements with respect to Well Control, together with additional recommendations which should be considered for implementation on a local basis. The manual is not intended to cover all possible well control eventualities and cannot replace sound judgement based upon a thorough knowledge of well control principles or local knowledge of a particular set of circumstances. The custodian of this Manual is Training Department. Any recommendations for changes can be made via the relevant General Manager to the Head of Training.
Well Control Manual
Rev 1.01, June 2010
CONTENTS 1
2
Responsibilities & Summary of Well Control Requirements .......................................... 6 1.1
Responsibilities ......................................................................................................... ......................................................................................................... 6
1.2
Training Requirem ents........................................................................ ents.............................................................................................. ...................... 7
1.3
Compliance & Exem ption Process ........................................................................... 8
1.4
Summary of W ell Control Requirements .................................................................. 8
Well and Operational Planning .......................................................... ......................................................................................... ............................... 12 2.1
Well Planning .......................................................................................................... .......................................................................................................... 12 2.1.1 General Considerations............................................................................. ................ 12 2.1.2 Bridging Documents .................................................................................................. 12 2.1.3 H2S Contingency Planning ........................................................................ ................ 12 2.1.4 Minimum Stock Levels ......................................................................................... ..... 12 2.1.5 Formation Considerations .................................................................................... ..... 13 2.1.6 Shallow Gas .............................................................................................................. 16
3
Hardware Requirements ................................................................................................... 17 3.1
Kick Detection (Hardwar e) .................................................................. ...................................................................................... .................... 17
3.2
Diverter Equipment Requirements .................................................................... .......................................................................... ...... 18 3.2.1 Diverter Selection Criteria ................................................... ...................................... 18
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4.5 5
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Causes of kicks ............................................................ ....................................................................................................... ........................................... 32
Preparation for, Prevention and Detection of Kicks ...................................................... 38 5.1
General Preparation Requirements in order to be prepared to handle a kick ........ 38 5.1.1 Equipment Checks and availability ............................................................ ................ 38 5.1.2 Flow Checking ........................................................... ................................................ 38 5.1.3 Determining the Maximum Allowable Annular Surface Pressure (MAASP) (MAASP) .............. 39 5.1.4 Slow Circulation Rate Friction Losses (SCR) ............................................................ 39 5.1.5 Establishing the Barite Mixing Capacity of the Rig .................................................... 39 5.1.6 Capacities and Strokes for Drillstring and for Annulus .............................. ................ 39 5.1.7 Pre-kick sheets .......................................................... ................................................ 40
5.2
Indications that a Kick may be in Progress W hile Drilling ....................................... 40
5.3
Indications that a Kick may be in Progress While Tripping T ripping..................................... 44
5.4
Kick Drills ................................................................................................................ ................................................................................................................ 45 5.4.1 Kick Drill Recommended Recommended Procedures........................................................ ................ 45
6
5.5
Casing & Cementing ........................................................................... ............................................................................................... .................... 46
5.6
Stripping Drills .......................................................................... ......................................................................................................... ............................... 47
Shut-in Procedures .................................................................. ............................................................................................................ .......................................... 48 6.1
Responsibilities for implementing im plementing Well Control Procedures ................................... ................................... 48
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Stripping Operations ............................................................................................... ............................................................................................... 76 7.5.1 Preparation for Stripping ................................................................ ........................... 76
7.6
Potential problems while well killing ............................................................... ........................................................................ ......... 81 7.6.1 MAASP is reached .................................................................................... ................ 81 7.6.2 Equipment Failure ................................................................................................ ..... 81 7.6.3 Hydrates......................................................... ........................................................... 82 7.6.4 Well Kill Problem - Quick Check List & Trouble Shooting Charts .............................. 82
8
Appendix 1: Forms, Calculations, Calc ulations, Worked Examples Ex amples ................................................... 88 8.1
Kick Drill Sheets: Pit/Kick Drill Report – Report – Hard/Fast Hard/Fast Shut In .................................... 89
8.2
Kick Drill Sheets: Pit/Kick Drill Report – Report – Soft Shut .................................................. 90
8.3
Kick Killing Worksheets W orksheets (IWCF Forms) .......................................................... ................................................................... ......... 91
8.4
Stripping For m ...................................................................................................... 100
8.5
Stripping Check Sheet .......................................................................................... .......................................................................................... 101
8.6
Form for Completing a Leak off Test .................................................................... .................................................................... 103
8.7
Calculation of Reservoir Pr essure (& Kill K ill Mud Weight) ........................................ 105
8.8
Kick Behaviour ...................................................................................................... ...................................................................................................... 107
8.9
Influx Gradient .............................................................. ....................................................................................................... ......................................... 108
8.10
Gradients of som e common wellbore Fluids......................................................... F luids......................................................... 109
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Rev 1.01, June 2010
1 Responsibilities & Summary of Well Control Requirements 1.1
Responsibilities On all operations it is the responsibility of the senior onsite KCA D EUTAG representative (normally the Rig Superintendent, Toolpusher or OIM), to ensure the implementation of proper well control practices and procedures. Prior to spud it is the responsibility of the Rig Manager to ensure that all the appropriate issues have been addressed in conjunction with the Client in order that the risk of a well control incident is as low as reasonably practicable. Where the Drilling Programme or Client instructions (whether written or verbal) conflict with requirements of this Manual or good oilfield practice the issue must immediately be raised through line supervision and, if not resolved, raised to the Rig Manager, Operations Manager or Country Manager as required. Responsibilities during a well control event It is the responsibility of the senior onsite KCA D EUTAG representative to ensure that the required responsibilities are allocated and appropriately disseminated to those involved These responsibilities include:
safeguarding personnel
protecting the environment and
protecting KCA DEUTAG drilling rig and its associated equipment
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Rev 1.01, June 2010
During killing operation, follow the pumping schedule in accordance with the approved Surface BOP Kill Sheet and Toolpusher's instructions. Record pressures; pump rate, volume pumped, and time. Compare the actual parameters with the kill graph and if any significant changes alert the Toolpusher. Rig Superintendent or Toolpusher: To maintain full control over the behaviour of the well to prevent blowout from happening. Notify the Company Representative, the Mud Engineer, the Drilling Engineer and Rig Manager. Evaluate borehole situation upon presumed influx. Select the most appropriate killing procedure depending on the type of kick and hole size. Calculate his Surface BOP Kill Sheet and compare it with the Driller's, the Company Representative's, and / or the Drilling Engineer's to avoid any mistakes. Be in charge of the killing operation, controlling backpressure and timing. To communicate with the Company Representative the BOP testing schedule, and the pressures and intervals. To instruct the Driller to which pressures the BOP must be tested according to the Drilling Program and as agreed with the client. Ensure the BOP manufacturer's engineering data for the specific equipment is readily available. To be aware of the annular preventer closing pressures to retain wellbore pressure in order to minimize excessive wear on the packer element particular when reciprocating the drillstring. Drilling Engineer: To assist the Toolpusher in evaluating borehole situation, calculate independently IWCF or WellCAP Surface BOP Kill Sheet and compare same with the Toolpusher's. Assist the Toolpusher during
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Rev 1.01, June 2010
(only allowable when formation pressures isolated from the wellbore) must be directly supervised by somebody with current well control certification. Additional training may be required dependent upon the types of well to be drilled and any local legislation or contractual requirements. All crews must be trained ‘on t he job’ through the regular reg ular use of kick drills which are to be conducted in accordance with section 5.4 section 5.4 of this document. 1.3
Compliance & Exemption Process The practices and procedures included in this Manual are minimum requirements and are not to be reduced to comply with any governmental or Client requirements. The well control practices must, however, be adjusted accordingly to comply with any more rigorous local regulations of either the relevant local authorities or the Operator. Any changes or selection of alternatives to be used in a well control situation must be documented in the Bridging Document. Whilst the Manual dictates certain mandatory requirements, in other areas options or a preferred procedure may be mentioned. In these cases the detailed local knowledge and expertise is to be taken into account in determining which course of action will be instigated. In this document the following terms are used to express a course of action:
“May”
indicates one possible cause of action
“Should”
indicates a preferred course of action
“Must”
indicates a mandatory course of action (and is the equivalent of “shall”)
It is a requirement that all relevant KCA D EUTAG personnel must know of and comply with the Company’s approved well control Standard and Procedures as included in this manual. It is the responsibility of the Senior KCA D EUTAG Representative to assure implementation of the appropriate
Well Control Manual
Rev 1.01, June 2010
Competency & Supervision The following personnel must have current well control certification; Rig Managers, Rig Superintendents (Toolpushers), Asst Rig Superintendents (Night Toolpushers), Drillers, OIMs.
1.2
Compliance: All requirements (“musts”) included in this manual are mandatory. Dispensations can only be granted after suitable risk analysis and approval by the Country Manager
1.3
Chemical Stocks Sufficient stocks of barite, chemicals and associated additives must be on location to allow for the weighting up of the mud system by 0.5 ppg (60 3 3 kg/m ) on development wells or 1 ppg (120 kg/m ) for exploration wells.
2.1.4
For offshore rigs and land rigs where logistics preclude a readily available supply of cement, enough cement must be onsite to enable the setting of a 500 ft (150 m) cement plug in open hole. Kick Tolerance 3
3
For kick tolerances of between 25 bbl (4m ) and 50 bbl (8m ) the Operations Manager must be informed and any additional precautions implemented as 3 advised. For kick tolerances of below 25 bbl (4m ) the Country Manager must be advised.
2.1.5.6
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Superintendent or Asst Rig Superintendent (Toolpusher or Night Toolpusher) BOP Testing is to take place with with water and charts maintained. A low and high pressure test must be undertaken with suitably calibrated gauges. Acceptance is a stabilised (zero) pressure drop. All gauges are to be calibrated at least yearly Each rig is to have its own detailed testing procedure and referenced valve schematic BOP Testing Frequency All BOP and related equipment must be pressure tested ever y 14 days or st during the 1 trip thereafter but never exceed 21 days
3.7.2
All BOP equipment is to be function tested upon installation and every 7 days or during the subsequent trip and must never exceed 14 days The accumulators precharge pressures are to be checked prior to the commencement of drilling each well or at a frequency not exceeding 3 months, or after any repair of the system. The operating lines to the BOP components shall be pressure tested to rated working pressure at least every 3 months
3.7.3
BOP Maintenance Routine BOP maintenance must be undertaken in accordance with this manual, approved PMRs, and at the specified frequency of the approved PMRs
3.8
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and suitable crossovers must be available on the drillfloor Relevant information (pre-kicksheets) must be available and up to date at the wellsite at all times
5.1.1, 5.1.4, 5.1.1, 5.1.4, 5.1.6, 5.1.7 5.1.6, 5.1.7
Flowchecks must be held:
5.1.2
Prior to a trip
Prior to pumping a slug
During a trip when:
o
Collars are at the shoe,
o
Collars are at the BOP
o
Improper hole fill is observed
During drilling when: o
Mud weight changes
o
When a change in flowrate is observed
o
When a change in pit level is observed
o
o
When a drilling break is observed (unless the area is known to be trouble free) When there are signs of water or gas cut mud
Kick Drills: Kick drills are to be conducted with each crew on a weekly basis. All drills are to be reported on the Daily Drilling Report
5.4
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2 Well and Operational Planning Preventing a kick will always be the best well control method and therefore certain planning activities are to be implemented on all KCA D EUTAG operations. 2.1
Well Planning Whilst KCA D EUTAG is not normally responsible for preparing the Well Programmes there are a number of actions that KCA D EUTAG personnel can take at the planning stages to reduce the likelihood of a well control event. Ultimately the Senior Wellsite Representative Representative (normally Rig Superintendent or Toolpusher) and Rig Manager are responsible for the overall safety of the operation and are therefore encouraged to participate in pre-spud meetings and required to review the Client’s drilling programme. Such a review may well highlight areas where extra vigilance may be required with respect to Well Control.
2.1.1
General Considerations It is common practice for the Operator to hold a pre-spud meeting with Operator, Drilling Contractor and Service Contractor personnel. personnel. At these meetings each step of the well programme is normally reviewed and due consideration given to any specific aspects. At this meeting the following points should be addressed:
Previous field experience regarding lost circulation experiences, magnitudes and depths depths of any anticipated abnormally pressurised formations Possible shallow gas sources The accuracy of the geological prognosis
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2.1.5
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Formation Considerations The Rig Manager and Senior onsite Representative must be aware of the expected formation pressures and whether normally or abnormally pressured formations are to be expected during the drilling operations. These issues are to be discussed at the pre-spud meeting and documented within the drilling programme.
2.1.5.1 Normally Pressured Formations The average figure for normal formation pressure gradient is 0.465 psi/ft (or 0.108 bar/m or 10.8 kPa/m). This is the pressure gradient produced by a column of water of 100,000 ppm chlorides as opposed to a typical value for seawater as 23,000 ppm. Unless other information is available via the Operator regarding the specific well, this average figure can be used for estimating the formation pressure. 2.1.5.2 Abnormally Pressured (or surcharged) Formations Abnormal formation fluid pressures can arise from a number of reas ons:
Differential fluid pressure Surcharged shallow formations Sediment compression Salt beds Mineralisation
The pressures that can result in overpressured or abnormally pressured formations will depend upon a number of factors and should therefore be subject subj ect to discussion at the Client’s pre -spud meeting. Further background information regarding the causes of abnormally pressured formations can be found in the DART Well Control Training Manual.
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5.
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Pump mud slowly using using a high pressure, low volume pump until the pressure builds up to approximately half the anticipated maximum surface pressure. a.
Pump small volume to flush out all the lines and circulate mud all the way around;
b.
Open the HCR HCR valve on the choke line and close the valve directly upstream of the choke,
c.
Close the remote controlled choke,
d.
Close the pipe rams around the drillpipe, and then
e.
Close in the lower kelly cock.
f.
Open the annulus between the current and the previous casing strings, where applicable.
6.
Pump uniform uniform increments of 0.1 to 0.25 bbl. (15 Litres to 40 Litres) and and wait wait for 2 minutes or the time required for the pressure to stabilise. stabilise. Note where low low pressures are expected and the volume is small, i.e. shallow weak formations, plot the pump strokes against the pressure, this is a far more accurate method than using the displacement tanks which at best are accurate to 0.25 bbls (40 ltrs).
7.
Note and record the cumulative mud volume pumped (strokes), the final pumping and final static pressure on the Leak-Off Test report as per section 8.6 of this manual.
8.
Repeat items items (5) and (6) and plot pressure versus cumulative mud volume (strokes) curves for each increment of pumped volume.
9.
Continue this this procedure until the the trend of the final pumping pressure curve deviates from that of the final static pressure curve after an appropriate waiting time, or until a predetermined
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Some control panels of remote controlled chokes have an automatic MAASP control which keeps the MAASP constant as soon it is reached. It is a KCA DEUTAG requirement that such devices devices must be disabled. The maximum casing shoe, or weakest formation pressure, must be used to calculate the MAASP before any well killing starts. During well control operations and the influx is below the last casing shoe if the pressures indicate that MAASP will be exceeded the following options should be considered: 1.
Reduce circulation rates to reduce annular pressure losses (and adjust drillpipe pressure accordingly)
2.
Continue with kill procedures and exceed MAASP (in which case there is a risk of formation breakdown)
3.
Continue kill procedures but open choke as needed needed to limit limit casing pressure to MAASP (in which case there is a high risk of an additional influx)
The choice between these options will depend upon the data available regarding formation permeability, shoe strength etc. Once the influx has passed the shoe the MAASP will be based on the allowable pressure ratings of the following:
The Casing burst pressure
Wellhead rating
BOP rating
It is therefore important to know the position of the influx at all times such that the appropriate
Well Control Manual
the reaction time of the crew to a well control situation
the difference between mud weight and pore pressure
the reservoir porosity and permeability
the influx type
the reliability and sensitivity of the detection equipment
the well shut in procedure used
the time of BOP closure
Rev 1.01, June 2010
Although wells may have the same kick tolerance, this does not necessarily mean that the risks risk s are equal. It is a requirement that the rig crew know what the kick tolerance is for the section being drilled and how that relates to the abilities of the crew and equipment to detect a kick and close in the well. 3
If kick tolerances are above 50 bbl (4m ) no specific additional precautions are required. For kick 3 3 tolerances of between 25 bbl (4m ) and 50 bbl (8m ) the Operations Manager must be informed and any additional precautions implemented as advised. For kick tolerances of below 25 bbl the Country Manager must be advised. 2.1.6
Shallow Gas Shallow Gas kicks have to be handled in a substantially different manner than Conventional kicks as primary well control is the only means to protect the well from blowing out, with secondary well control techniques not normally applicable in top hole drilling operations. All Shallow Gas aspects of well control are therefore included in a separate Appendix 2 (Section 9) to this Manual.
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3 Hardware Requirements This section provides KCA D EUTAG’ EUTAG’s selection, configuration, testing and maintenance requirements and recommendations with respect to Kick Detection, Diverter, BOPs and associated equipment. Only with with adequately selected, configured and maintained equipment can well control situations be adequately mitigated. If any of the equipment categorised as “must” is inoperable and drilling with BOPs is under way the Rig Manager must be informed. All BOPs, choke manifolds, m anifolds, diverters, valves, risers, adapters and spools, hoses and flexible piping, and associated equipment must have valid certification available at the rig site with copies being held in the office. 3.1
Kick Detection (Hardware) The following kick detection equipment is either mandatory or recommended in order to be able to detect kicks as efficiently as possible.
3.1.1
Flowline Recorder The flow line recorder is the best kick indicator because the flow line is the first point at which an increase in flow from the well can be detected. When out of the hole, the flow recorder also makes it impossible for the well to unload without warning. All KCAD rigs (owned or managed) rigs must therefore be fitted with a Flowline Recorder.
3.1.2
Pit Volume Totaliser
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(b) Mud volume in pits (c) Pressure on the annulus (or choke) (d) Pump pressure or pressure on the drillpipe (or standpipe). (e) Pump speed (f) Rate of Circulation (g) String weight (h) Weight on bit
3.2
Diverter Equipment Requirements Diverter Systems and their control systems are to be in accordance with API specifications or recommended practices (currently API 16D latest revision, and API RP 53 latest revision).
3.2.1
Diverter Selection Criteria The decision to install a BOP or Diverter on the conductor string depends on the expected formation strength at the conductor shoe and the rig's capability to detect and handle an influx successfully. The rig should be equipped with a diverter system instead of a BOP if circulating out such influx would result in formation breakdown and subsequent cratering of the well. All wells to be drilled where there is a possibility of shallow gas and a BOP cannot be installed for the above reasons, must be equipped with a diverter system in an attempt to preserve wellbore integrity and to enhance the safety of personnel.
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3.2.3
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Diverter Equipment Specifications The following must be considered when selecting diverter equipment: 1.
The equipment equipment must be selected to withstand the maximum anticipated surface pressures and in accordance with API specifications or recommended practices.
2.
The minimum rated working working pressure of diverter equipment is based on the anticipated backpressure during a shallow gas blowout and therefore largely depends on the size of the diverter lines. The minimum rated working pressure of the recommended large bore diverter line system is 500 psi (3450 kPa) WP. It should be noted that the dynamic forces are much higher in the initial stage of diverting a well, when the expanding gas is forcing the mud out of the diverter system.
3.
Welded flange or hub connections must be used on diverter systems. Quick connections in diverter lines are not allowed.
4.
A diverter system can be a BOP stack system with a diverter spool, or a specifically designed and developed diverter system. A faster closing closing diverter unit is is preferred over a large and slowly closing annular preventer.
5.
The diverter diverter and mud return lines should be separate lines, not partially integrated lines, lines, to avoid gas entering the rig system in case the separating valve between both lines fails to operate properly.
6.
Diverter valves must be full opening valves with with an actuator (pneumatic or hydraulic). hydraulic). The bore of the diverter valves must be equal to the bore of the diverter lines.
7.
Each diverter system should incorporate a facility (including a check valve) to be able to pressure and function test the system and to be able to pump water through the diverter
Well Control Manual
29 -1/2 “
Bag type preventer
Actuator Diverter spool Diverter line
V N R e l i n l l i
P
P
Diverter line
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Rev 1.01, June 2010
When a pipe-ram type preventer is included in the diverter system, casing rams should be installed and function tested prior to running and cementing the surface casing string (see Figure 3-2, Option 3-2, Option C).
20“ Bag type
preventer
P Valve (pressure operated, remote controlled, fail safe Open)
Bag type preventer
20“
Pipe Rams
20“ Bag type
P
preventer Kill line
NRV
BL/SH Rams
Diverter line Kill line
P
P Diverter line
Kill line
BL/SH Rams
NRV
Actuator Actuator
Actuator Actuator Diverter spool
P Choke line
Diverter line P
Diverter spool
Choke line Actuator Actuator
Diverter spool P
Diverter line
Diverter line
P
P Diverter line
NRV
Casing housing
Conductor String
Casing housing
Conductor String
Casing housing
Conductor String
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1.
The equipment must be selected to withstand the maximum anticipated pressures and temperatures.
2.
The BOP stack shall consist of remotely controlled equipment capable to close in the well with or without pipe in the hole.
3.
Welded, flanged or hub connections must be used on all pressure systems, exposed to well pressure. Threaded connections must not be used for pressures above 2000 psi (13800 kPa) and diameters above 1 inch.
4.
When operating in an area where sour service equipment is required the complete high pressure BOP system must consist of materials resistant to sulphide stress cracking (super trim).
5.
Dedicated kill lines must not be smaller than 2" nominal and should be fitted with two two valves and one NRV (check valve). Choke lines should not be smaller than 3" through bore and the outer valve of each choke line should be hydraulically operated.
6.
During drilling and workover operations the BOP should be equipped with one shear shear ram capable of shearing the DP in use and to provide a proper seal. If the shear/blind rams are unable to shear through the string in the hole then this must be made clear that these rams are only to be used as blind rams and a notice posted on the drillfloor accordingly. If shear rams are unable to shear the pipe used the Country Manager must also be informed.
7.
As per API 16D, closing systems systems on surface BOPs must be capable of closing any ram preventer within 30 seconds. For annular preventers up to 20" the closing time must not exceed 30 seconds, and 20" and more the time must not exceed 45 seconds.
8.
All master and and remote operating panel handles should, at all time, be in the full closed or open position. All four-way valves should be either in the fully open or closed position. They
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3.5
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BOP Arrangements The following sections show the KCA DEUTAG recommended BOP configurations. Specific operations and Operator requirements may differ and the actual configurations are to be agreed with the Operator prior to the commencement of operations. The BOP requirements of each well must be suitable for the specific application. Adequate redundancy must be in place in keeping with the equipment specifications, the well programme and emergency contingencies. Ensure the shearing capabilities for the blind/shear rams meet the requirement for the drillpipe in use and if they cannot shear the pipe in use then they must only be used as blind rams. This must be communicated to all appropriate personnel and a notice to that effect posted on the drillfloor. If the shear rams cannot shear the pipe in use the Country Manager must be informed Note on each BOP configuration 2 side outlet valves should be installed on the last casing head housing. These will allow access below the lowermost rams if required. All other casing annuli should have a single valve and pressure gauge to allow the annulus pressure to be observed during well operations.
3.5.1
BOP 13800 kPa 2000 psi without a Casing Spool
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3.5.2
BOP 20700 kPa 3000 psi 34500 kPa /5000 psi without a Casing Spool
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3.5.3
BOP 34500 kPa 5000 psi with a Casing Spool (Dual Ram option)
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3.5.4
BOP 34500 kPa 5000 psi and/or 69000 kPa 10000 psi with Casing Spool
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3.5.5
BOP 103500 kPa 15000 psi.
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3.6
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Control System Requirements for Surface BOP Stacks The minimum requirements for Surface BOP Stack control systems are as per API 16D and as follows: 1.
Control system for BOP stacks shall have have one independent automatic accumulator unit rated for 3000 psi 20700 kPa WP with a control manifold, clearly showing open and closed positions for preventers and the hydraulic operated kill / choke line valves.
2.
The Control Units are to be equipped with a 0- 3000 psi 0 - 20700 kPa regulator valve (TR-5) which will not fail open causing complete loss of operating pressure.
3.
The minimum accumulator capacity capacity must be as per API 16D i.e. without recharging, the accumulator capacity shall be adequate for closing the annular and all ram preventers and opening the valves on the side outlet and have enough spare capacity to further close the annular and a set of rams while still holding the side valves open against full rated BOP pressure.
4.
The control unit must be located in a safe area, and itit should be equipped with low level and low pressure warning alarm.
5.
All installations installations should have one remote control panel, appropriately sited, in addition to the closing unit, clearly showing open or closed for each function.
6.
The operation of the BOP stack functions must be possible within the work area of the driller.
7.
Control hoses are to be high pressure fire-resistant with a working pressure of 3000 psi 20700 kPa. Steel swivel joints are also acceptable.
Well Control Manual
3.7.3
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Accumulator and Control System Tests The accumulators precharge pressures are to be checked prior to the commencement of drilling each well or at a frequency not exceeding exceeding 3 months, or after any repair of the system. The operating lines to the BOP components shall be pressure tested to rated working pressure at least every 3 months.
3.8
General Maintenance Requirements for Wellhead and BOP Equipment Routine BOP maintenance must be undertaken in accordance with this manual, the manufacturers requirements, approved PMRs, and at the specified frequency of the approved PMRs. The following minimum maintenance and overhaul requirements apply to all BOP and Control equipment 1.
Every 5 years, all BOPs and related equipment must be overhauled. This also applies to all valves used in the side outlets and equipment up to and including the choke manifold as well as any other related equipment such as diverters. After re-assembling, a body test should be performed and where witnessed by a competent party. The test pressure used must be to at least the working pressure and, where welded repairs have been undertaken, to the rated test pressure.
2.
Maintenance on a routine basis should include that after each well the BOPs are opened, rams removed and all cavities and related equipment is checked for wear or damage.
3.
After working on BOPs ensure ring grooves are clean and new and clean ring gaskets of the correct type and pressure rating are installed. Ring gaskets are NOT reusable.
4.
Ensure the rams are installed correct way up.
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rams. This must be communicated to all appropriate personnel and a notice to that effect posted on the drillfloor. If the shear rams cannot shear shear the pipe in use the Country Manager must be informed. An actual shear test is advised advised before installation of the BOP stack with with the drillpipe size and grade to be used. To obtain maximum shearing shearing capabilities the the installation of large bore shear bonnets and tandem boosters on the closing side of the BOP can be considered. 17. Ensure that the manufacturer's BOP manual is is followed and no alterations are made without without either Manufacturers or E&M Functional written consent. NEVER NEVER weld cut or modify any BOP equipment. 18. Original Equipment Manufacturer spares must be used unless a dispensation has been made by E&M Function in accordance with their and GSM relevant Group Standards. Sufficient consumables and spares stocks are to be held onsite.
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4 Well Control Principles The prevention of a kick (i.e. maintaining Primary Well Control) is always the best well control method and method and therefore an understanding of the causes of kicks is essential. For further information see the KCA DEUTAG DART Well Control Training Manual. The following conditions must always be met : (a) (b) (c) (d)
The hole must, at all times, be kept full of mud of the agreed mud density. The correct BOP equipment must always always be installed on the well, operational, and be suited to the specific conditions. All relevant personnel on site site must understand and be experienced in the use of the installed BOP equipment. All drilling personnel on site must be constantly alert for the danger signs and be able to act quickly and correctly when they occur.
This section defines KCA D EUTAG’s Barrier Policy, Primary, Secondary and Tertiary Well Control and then describes the causes and conditions of kicks in order that the implementation of relevant operational safety precautions can be fully understood. 4.1
Barrier Policy During any well operations after surface casing is set a minimum of two independent barriers must be in place. A well barrier can be mud hydrostatic (providing there are no losses during drilling and the well is shown to be overbalanced), a ram-type BOP, an annular BOP, a cement plug, casing, casing float valve, mechanical plug, subsea safety valve, permanent packer, tubing or kill-weight fluid. (A
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the associated warning signs as described in section 5.2 are critical in effectively controlling the situation via the Secondary Well Control equipment and appropriate well killing procedures. When primary well control is lost and an influx may occur (kick) the blowout preventer equipment (BOPs) must then be used to enable the 'kick' to be controlled by one or more of the 'kill procedures', outlined in this manual. 4.4
Tertiary Well Control
An emergency well control situation exists when both Primary Primar y and Secondar y Well Control procedures have been unable to control the influx of fluids into the well, or another unusual well control situation arises requiring specialist techniques, expertise and/or equipment. 4.5
Causes of kicks The main causes of kicks and therefore losing Primary Well Control are the following: 1.
Failing to fill the hole by controlling the volumes and going in and out properly when tripping
2.
Swabbing in a kick while tripping, (moving string too fast). Particularly in situations situations with balled up stabilisers and overpull
3.
Insufficient mud density
4.
Abnormal formation pressures
5.
Lost circulation
6.
Shallow gas sands
7.
Excessive drilling rates in bearing sands
Note:
The most common causes of kicks are attributable to items 1 and 2 above.
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This reduction in pressure is called a swabbing or suction effect and it is created in a borehole when the pipe is pulled out too fast. This reduces the bottom hole pressure on the well section below the bit. Balled up BHA and tight spots in the open hole section will increase this effects. If the bottom hole pressure (BHP) is reduced to the extent that the overbalance is lost, the formation contents will enter the wellbore. The chances of this occurring are much greater when the bit is close to bottom, therefore extra care must be taken in the initial stages of a round trip. The dangers in this operation are two-fold and cumulative. The very action of swabbing pulls mud out of the hole. If formation fluids enter the well bore, they will also displace mud out of the hole. Bottom hole pressure fluctuations, which could cause a kick, are likely to occur whenever the pipe is moved in the hole. The swabbed in kick is particularly hazardous since often a brief swabbing episode is followed by normal tripping practice. If the small discrepancy in string displacement volume is not noted, it will probably be overlooked. An overall influx of gas, for instance, swabbed into an open annulus, may only displace a very short head of mud. The net decrease in BHP is small and likely to be well below the normal range of 'trip margin' overbalance. No further flow of gas will occur into the well and, if the well is shut in, no pressures will show on either DP or casing gauges since the well is still in balance. However, gas will slowly migrate up the well and expand as it does so. At first the expansion is very slow and it is unlikely that any significant flow will be seen at the surface unless the influx is very large, or very close to surface. The possibility to detect a kick by its expansion will be normally first given when the gas bubble has reached the middle of the well.
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Whenever there are signs that the borehole is taking less than the calculated volume of mud, (this decision can normally be made within the first ten stands pulled), (d)
the drillpipe should immediately be run back into the hole - to bottom, if possible,
(e)
the hole circulated clean and a flow check made.
The Rig Supt or Asst Rig Supt (Toolpusher or Night Toolpusher) must be on the drillfloor for the first 10 stands of any trip to witness the commencement of tripping operations and until he is confident that the hole is taking the correct volume of fluid. 4.5.3
Insufficient Mud density The hydrostatic pressure exerted by the column of mud in the hole is the primary means of preventing kicks. Insufficient mud density can result from: (a) penetration into an an unexpected, abnormally high-pressure zone, or (b) by deliberate balanced or underbalanced drilling methods. The benefits of keeping the mud density as low as possible include: (a) Increased rate of penetration. (b) Minimising the possibility of differential sticking of drillstring. (c) Creating a small filter filter cake. (d) Pumping water pills while stuck in salt formations. Other circumstances where insufficient mud density is brought about accidentally include:
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Drilling personnel rely on the Geologist and/or Drilling Engineer and the Mud Logger or Well Logger to warn them of possible high-pressured formations. This is done via the Drilling Programme from offset well records. Once drilling commences, it is done on the basis of evidence accumulated as the well progresses. For the under compacted formations, since the transition from normal to high pressure formations usually occurs via a transition zone of which the thickness may or may not be predictable, the Engineer or Mud Logger can also assist in forecasting the latter by analysing changes which occur in the drilling variables and by analysing the shape, character, and volume of formation cuttings throughout this transition zone. By gradually increasing the mud density prior to reaching an anticipated high-pressure zone, there is a greater possibility that primary control can be retained should signs of a kick appear. Generally, whenever a permeable zone containing fluids is pressured above the normal gradient, then appropriate mud densities should be run. 4.5.5
Lost Circulation Loss of circulation is a very serious drilling problem and every effort should be made to prevent its occurrence. If the loss of mud to natural or artificially induced fractures is sufficiently great, then all returns from the well can cease. If the level of mud in the well annulus drops, it will lower the hydrostatic pressure and may lead to an influx or kick. The influx can be from an upper or a lower formation which will start to flow into the well, then either down or up to exit into the weaker or broken down formation. This type of kick may rapidly become very severe since a large influx can occur before any rise in annulus. Should this occur, and if mud supplies are limited, the annulus must be filled with water or
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necessary to divert the flow rather than to shut the well in and risk fracturing the casing shoe with the possibility of gas coming up around the outside of the well (broaching). As bottoms up time are very short, th e Driller and crews m ust be very alert to all the early ear ly signs of a kick. The flow sensor may be the only piece of equipment to give a warning early enough. Pit level gains, although positive indication, are generally too late to indicate flow in this situation. Swabbing can easily reduce hydrostatic head. Also, there may be just sufficient ‘core’ gas, or gas released from the drill chips of the drilled permeable gas sand, to reduce the ECD (equivalent circulating density) below the formation pore pressure as the chips are transported to the surface. There is only one method of attempting to kill a shallow gas kick and that is dynamic killing, which means that the hole is filled with mud or water in excess to the production rate of the formation. It is recommended to speed up the pumps to the maximum possible rate. At first sign of flow, the following action is required: (a) Open diverter valve and close diverter element. (b) Pump mud immediately at maximum pump rate and be prepared to abandon the location (c) If the well continues to flow, pump heavier mud at maximum pump rate (generally 0.12 Kg/l, 1 ppg, 1.175 kPa/m). It is recommended when drilling in shallow gas areas to have at least the pilot hole content premixed and ready for pumping. If the well continues to flow after the heavy mud has been pumped, carry on pumping mud at a
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(b) know the steps to be taken to prevent kicks from becoming blowouts, (c) are properly and regularly trained and tested, (d) remain constantly alert for all signs of danger, and develop a sense of, or a feel for, the onset of a "kick". (e) Competence assurance. The rig crew will then be able to respond correctly and automatically whenever a positive sign of a kick occurs.
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5 Preparation for, for, Prevention and Detection of Kicks 5.1
General Preparation Requirements in order to be prepared to handle a kick In order to limit the likelihood of taking a kick and in order to be prepared to handle a kick efficiently and effectively, a number of Pre-kick preparation actions are necessary. Ensure drillfloor personnel know which tool to use to shut-in the drillpipe while tripping, the kelly cock or the Gray valve.
5.1.1
Equipment Checks and availability The following equipment checks must be made to ensure that on any sign of a kick the well can efficiently be closed in:
Ensure equipment for blowout prevention is always operational and available.
Ensure an up-to-date pre-kick record (kill-sheet) is available at all times.
Check the capacity of the Koomey unit is in accordance with API RP 53 and API 16D (i.e. in accordance with section 3.6 section 3.6 of this manual). Check that the following are present: a.
Adequate fluid in the accumulator
b.
Kelly cock (in open position) with wrench on the rig floor
c.
Crossovers on the kelly cock for tubulars in the drillstring or tubing
d.
Gray valve (non return string valve) and matching circulating sub and crossovers, on the rig floor
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During drilling when: o
Mud weight changes
o
When a change in flowrate is observed
o
When a change in pit level is observed
o
When a drilling break is observed (unless the area is known to be trouble free)
o
When there are signs of water or gas cut mud
Normally a flow check will take around 15 minutes, however in a lot of cases a flow check has taken much longer time to recognise a flow. A negative flowcheck can be assumed if zero flow is noted for a period of 10 minutes. 5.1.3
Determining the Maximum Allowable Annular Surface Pressure (MAASP) During killing operations, the maximum allowable hydrostatic pressure opposite the weakest formation is a determining factor and must be known at all times (see section 2.1.5.5) Unless evidence is available to the contrary, the weakest point is taken to be the formation immediately below the shoe. This pressure is: MAASP = (formation breakdown strength gradient at shoe, minus hydrostatic mud gradient), multiplied by (vertical distance from surface to shoe). The formation strength at the shoe will either have been determined by a Formation Strength Test (or Borehole Integrity Test, or Leak-off Test, as it is sometimes known) performed after drilling out the shoe and the cement; or it will be known from previous drilling experience in the area. The hydrostatic head due to the mud column will vary with the mud gradient. The MAASP must
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Pre-kick sheets In the event of the unexpected loss of Primary Well Control, and order to avoid unnecessary delay in taking action to control a kick and kill the well, certain relevant information must be kept up to date and available at the wellsite at all times. The above information is therefore to be recorded on the International Well Control Forum (IWCF) Surface BOP Kill Sheet or equivalent form approved by the KCA D EUTAG or the Client. Examples of the IWCF forms are shown in Appendix 1 and the appropriate forms are available via the BMS. These Kill Sheets are available for vertical and deviated wells. The units of measurement for both a vertical and a deviated well kill sheet are available in “Field” (Bar/litre), SI (metric) and “Field” (API) via the BMS . The IWCF Surface BOP Kill Sheet must be constantly up-dated during drilling operations to amend depth and mud-dependent data. Typically, this update will be done
whenever 1000’ (300m) of hole has been drilled
if the mud density has been changed
5.2
at the beginning of each shift
whenever any change occurs in any relevant parameters such as casing and hole size, mud properties / gradient, drill string configuration, bit nozzle sizes, formation characteristics etc.
Indications that a kick may be in Progress while Drilling In order to reduce the impact of a kick, simplify any well killing procedure and limit the seriousness of a well control incident , it is necessary to limit the volume of any influx to as small a volume as possible. It is therefore necessary for the well to be shut in as soon as possible after the signs of a
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Flow Rate Increase An increase in the return flow rate indicates that more mud is flowing from the well than is being pumped in. This can only be due to fluid from the formation entering the well bore and displacing the circulation mud. This is a certain sign of a kick. When the Driller observes an increase in the return flow rate, drilling and pumping must cease and the well closed in immediately and observed for pressure build-up. The man at the mud pit mustalso inform the Driller at once when the increase in return flow is observed. A flow sensor provides a means for measuring quite small variations in flow. However, if a kick is coming from a relatively low permeability formation, it is unlikely that this slow bleed in will make an observable variation in flow rate. A very small flow also can occur in situations using oil based mud and having a gas kick. If a flowrate increase is observed the well should be closed in immediately and observed for pressure build-up.
5.2.2
Well Flows with the Pump Stopped If, after stopping the pump, the well continues to flow, the well must be closed in immediately and observed for pressure build-up. The explanation of the cause is the same as for 5.2.1, for 5.2.1, Flow Flow Rate Increase. The exception to this rule is when a pill of heavy mud was spotted in the drillpipe prior to pulling out; in which case the flow is from a temporary imbalance or U-Tubing U- Tubing and it would soon stop. A drillstring consisting of 5” and 3 1/2” drillpipe will indicate a second imbalance when heavy mud was spotted in the drillpipe prior to pulling out
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The opposite signs (pump pressure increase) may be observed if the mud used is normally weighted, 9.5 ppg (1140 kg/m3), and a saturated magnesium chloride salt water of 12.5 ppg (1500 kg/m3) is encountered. 5.2.5
Drilling Break One common sign that an abnormally high-pressure formation has been penetrated is a sudden increase in the rate of penetration. A gradual penetration increase may signal an increase in permeability and a loss of pressure overbalance. It is rare for the drilling break to indicate a kick is in progress though it is an indicator that conditions are changing and perhaps formation pressure is raising. These "drilling breaks" should always be regarded as an indication of a possible kick. Always check what the torque is doing when the drilling break took place – place –was was there an increase or decrease? Was this change steady or erratic? The difference between the pressure exerted on the bottom of the hole by the column of mud (the Bottom Hole Pressure) and the formation pore pressure has a considerable influence on the rate of penetration. The greater the difference, the lower the rate of penetration. This pressure difference causes the Chip Hold-down Effect. When a new formation is penetrated in which the pore pressure is higher than previously, the pressure difference or overbalance is reduced and the bit will penetrate faster. If the formation pore pressure is so high that the overbalance is lost, then the well will kick. A continuous increase in penetration rate is a fairly reliable sign, if confirmed by the lithology, that a transition zone above an abnormal pressure formation is being drilled. On the other hand, some formations are just softer and easier to drill than others. In these cases an
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Decrease in Values of Shale Density with Depth Abnormal pressures can sometimes be forecast by measuring the density of shale cuttings, since undercompacted shales have a lower density than when normally compacted. Very accurate measurements, which are seldom possible on site, are necessary and many other factors, which could affect the density, should be expertly considered. The value of this warning sign is marginal.
5.2.9
Increase in Mud Temperature The increase implied is in addition to that normally found with increasing depth, and could be associated with undercompacted clays/shales above an abnormally pressured permeable zone. There are, however, so many variables affecting flow line temperature that this sign only has some degree of reliability in areas where extensive drilling has already provided adequate data.
5.2.10 Gas, Oil or Salt Water Cut Mud Gas, oil or salt water cut mud as a sign of a possible kick. This can be caused by:
cuttings entering the borehole or
influx from the formation.
At any sign of gas or water cut mud the Driller must investigate by flow checking the well. If the Mud Logger detects small quantities of gas influx at intervals this may correspond with connections (pumps stopped) which is known as “Connection Gas”. While drilling with connection gas the times when making connection with pump off should be as short as possible. Before making a new connection in this situation be sure that the bubble from last connection has reached surface.
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5.2.13 Increased torque and drag. Increased drag and rotary torque are often noted when drilling into over pressured shale formations due to the inability inability of the under balanced mud density to hold back physical physical encroachment of the formation into the wellbore. Drag and rotating torque are both indirect and qualitative indicators of hole instability and other mechanical problems. Torque and drag trend increases often indicate to the driller driller that a transition zone is being drilled. Up drag and down drag as well as average and torque figures should be recorded on each connection. These trends are valuable when comparing other trend changes. 5.2.14 Decrease in D-exponent. The D- exponents will be plotted by the well loggers and maintained current all the times. This value was introduced in the mid-60s to calculate a normalised penetration rate in relation to certain drilling parameters and has been used with moderate success in predicting abnormal pressure.
5.3
Indications that a Kick may be in Progress While Tripping Approximately 40% of all blowouts are the result of kicks taken whilst round tripping. Flow into the wellbore will cause improper hole fill up, if this is seen a flow check must be performed. (a) If the flow check is positive then the well must be shut in. (b) If the flow check is negative the drillstring should be run back to bottom to circulate bottoms up (stripping may have to be used here).
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In situations using water based mud and having a gas kick, the decision running back to bottom can become critical. When through passing the gas kick, the height of the kick will increase significantly and a great loss in bottom hole pressure can occur. Due to this pressure loss, a new kick could enter the wellbore. Under this circumstances it is absolute necessarily to control the volumes coming out when tripping back. If there will be any uncertainty, close in the well and strip back to bottom by using the volumetric stripping method. If the well is killed at some distance higher than the TD, a higher mud density is required than it would take if the well were killed on bottom as the original mud density exists from beneath the bit to TD. If this is the case, the well may need to be killed in stages. Alternately, if the rig cr ew is very familiar with str ipping into the borehole, boreho le, it m ight be more prudent to get as close to bottom as possible by stripping, then to kill with the correct mud density. 5.3.2
Well Flows when Running In It is equally important to check the mud volume in the pits while running in because it is easy not to notice a kick at this time. Mud is continually being displaced from the well as the pipe is run in and unless positive measurements are made at the pit and compared with the theoretical displacement of the string, a flow based on influx from the formation can be missed. If additional flow is suspected, the well should be observed, and if necessary closed in and steps taken to kill it.
5.3.3
Hole Keeps Flowing Between Stands When running into the hole, if the well has n ot stopped flowing by the time the next stand is ready r eady for running in, it is probable that flow may be occurring in the well.
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6.
The Driller raises the elevators a few metres and the Floormen stab the kelly cock on the pipe as quickly as possible and torque up same.
7.
Close the kelly cock using the wrench.
8.
The Driller Driller opens the H.C.R. H.C.R. valve on the BOP and then closes closes the appropriate preventer.
The times taken to install and close the kelly cock and to close the BOP (including opening the H.C.R. valve) should be recorded individually. The total time are to be filled in on the kick drill sheet (example shown in the Appendix 1). With the well now shut in: 9.
Connect the top drive or kelly.
10. Open the kelly cock. 11. Observe and record SIDPP and SICP. If it is decided to strip the drill string to bottom continue as follows: 12. 13. 14. 15.
Close the kelly cock and bleed off any pressure from top drive. Disconnect the top drive and remove the pup joint from the the kelly cock. Install the Gray valve and connect the top drive. Open the kelly cock and test the Gray valve.
Note the above assumes the topdrive kelly cock has an OD that allows it to be stripped into the well. In many wells the r egular egular 6 5/8” Kelly cock will not pass through 9 5/8” casing. This aspect should be considered during the well planned phase.
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Stripping Drills The purpose of the strip drill is threefold:
Training of personnel to obtain a level of routine and familiarity, including communication aspects.
Check on correct function of equipment (rig’s and contractor’s)
Determination of the required annular closing pressure and strip in resistance.
The strip drill should be held in casing casing prior to drilling out the shoe-track. It can be combined with a pit drill. Prior to conducting a strip drill determine whether there is a risk of drillpipe collapse or casing burst. Prior to commencing the strip drill refer to the Stripping Checklist in Appendix 1. 5.6.1
Stripping Procedure (based on a Pit Drill alarm) 1.
Install the Kelly cock cock on the drillstring and close the Kelly cock.
2.
Open HCR.
3.
Close annular preventer.
4.
Close the valve before/after the choke.
5.
Install the Gray Valve on the Kelly Cock (drillstring).
6.
Pressure up the well to 30 bar via the kill line.
7.
Reduce the annular closing pressure to the lowest leakage free level.
8.
Check the stripping bottle pre-charge pressure (plus/minus 50% of the
annular closing
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6 Shut-in Procedures 6.1
Responsibilities for implementing Well Control Procedures The shut in procedure and the preferred kick killing method to be used, is to be made known to the crew by the Rig Manager and Operator, not later than the spud meeting. Any agreed procedures and the methods should be in accordance with the procedures in this Manual. The Driller is responsible for monitoring his instrumentation, evaluating any changes and information given to him, performing flow checks and, where there are indications of a kick, shutting in the well and informing the Rig Superintendent or Toolpusher.
6.2
General Shut-in Procedures
6.2.1
Shut in Procedures whilst drilling The preferred shut-in procedure must be agreed between KCA DEUTAG and the Operator before drilling begins and should should be discussed at the pre-spud meeting. KCA DEUTAG’s preferred shut in procedure is the hard (or fast) shut-in (i.e. choke closed) method. The agreed shut-in procedure shall be clearly posted on the rig floor before drilling begins Once a kick has been detected, or is suspected, the decision must be made to shut the well in as quickly and as safely as possible. The success of the well control operation depends upon the response of the crew at this most critical phase. When any positive indication of a kick is observed such as a sudden increase in flow or an increase in pit level, then the well well must be shut in immediately even without doing a flow check The procedures which follow our generalised suggestions and not necessarily applicable to any
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a.
the shut-in drillpipe pressure - SIDPP Note: if a back pressure valve or drillpipe float (non-return valve) is installed in the string, pump very slowly and stop as soon as the pressure increase is noted on the casing side, then read the drillpipe pressure. Record this as SIDPP
b.
the shut-in casing pressure - SICP
c.
Measure the pit-level increase.
Record these data on the IWCF Surface BOP Kill Sheet. The Choke is to be in the closed position while drilling in preparation for a hard shut in. 6.2.1.2 Soft shut in procedure The soft shut in procedure is not preferred as the well is open via the choke while the rams or annular is closed. However if this procedure procedure is to be consi considered dered then the following steps would apply. 1.
Stop rotating the string.
2.
Raise the drillstring with pumps on to a convenient position where no tool joints are at the pipe rams or annular preventer(s). (When a kelly is in use, raise the string until the lower kelly cock is above the drill floor.)
3.
Stop pumps and check for flow, if positive:
4.
Open (hydraulic, HCR) choke line valve.
5.
Close annular or pipe ram BOP.
6.
Close choke. If the choke is not a positive closing choke than one should close a valve
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5.
Open choke line HCR valve.
6.
Close the choke upstream valve and check check the complete system for leaks. leaks.
7.
Call supervisor and check pressures.
8.
Install inside blowout preventer (Gray valve, non return valve or IBOP).
9.
Open safety valve
10. Reduce annular preventer pressure and prepare for stripping drillpipe in the hole The choke will be in the closed position while tripping With the swab kick where flow is observed there are mainly four options to consider: (a)
Strip back to as close as bottom as possible.
(b)
Perform a volumetric bleed.
(c)
Bullhead kick back into formation.
(d)
Perform off bottom kill then return to bottom and circulate well to desired mud density.
In any shut in procedure it is prudent to line up the annulus to the trip tank above the annular or rams. This will assist in double-checking to see if they are leaking. 6.2.2.2 Shut in procedures while tripping on drill collars If there is an indication of swabbing and well flows during a flow check the recommended option for closing the well if collars are in the BOP is as follows: 1.
Set the slips.
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6.2.3.1 Shut-in procedure while running casing Shutting in a well while running casing is similar to shutting in a well when tripping drillpipe. The main differences involves a device used to stop potential flow up the casing and whether to close a bop or a diverter, which depends on the type of casing being run. When running surface casing, the bop stack is not usually nippled up, since there is no casing head to nipple onto. In such cases, crew members will have to use a diverter or other procedures to close in the well. Because casing is normally run with a float shoe, once the diverter or bops are closed, the shoe prevents backflow through the casing. A cement circulating head can also be used to prevent flow up the casing. Self fill up shoes are not to be used when running casing casing into productive zones. zones. When running casing into a productive zone casing rams should be installed or a suitable crossover system considered. It is important to remember to plan for having having to close in around casing, with ram bops needing to be properly sized to close around the casing. Further, annular closing pressure may need to be reduced to prevent collapsing the casing. 6.2.3.2 Shut-in procedure while cementing During cementing operations, it should be remembered that joints of casing shorter than normal may be run into the well to ensure that the casing shoe hangs at the correct depth near the bottom. With joints shorter than normal, space out becomes important such that the bops will be able to close on the casing body and not on a coupling. If a kick is detected, the driller should first ensure that the casing is properly spaced out prior to the cement pump being shut down, the bop closed (usually the annular), and the supervisor notified.
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Verifying shut in As mentioned earlier, regardless of the procedure used to shut in a well, it is important to verify that the well is completely shut in. Otherwise formation fluids could continue to enter the hole, making it difficult or impossible to regain control of the well. To confirm shut in, it is good practice to use the following procedures.
6.3.2.1 Annulus To ensure that the annulus is close, check to be sure that the annular bop is completely close on the well and is holding pressure. Then be sure that no fluids are flowing out of the mud return (flow) line. It is best practice to line up the trip tank across the top of the BOPs to confirm the rams or annular is not passing. 6.3.2.2 Drillstring To confirm that pressure is holding on the drillstring, check to be sure that the mud pumps pressure relief valves have not popped open and that closing pressure will not exceed the pressure at which the relief valves will open; then, check the standpipe standpipe manifold. Every joint should be pressure tested with no leaks. 6.3.2.3 Wellhead and BOPs On surface stacks crew members should ensure that the casing valve on the wellhead is closed and, once closed, is capable of holding the anticipated annular pressures. Further, they should check for pressure broaching to the surface outside the wellbore. 6.3.2.4 Choke and choke manifold Finally, the choke and choke manifold should be checked to ensure ensure that the choke, when
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7 Well Killing Procedures 7.1
Killing Considerations & Preparation After the shut-in procedure, start reading and recording every two minutes: a.
The shut-in drillpipe pressure – pressure – SIDPP SIDPP If a back pressure valve or drillpipe float (non-return valve) is installed in the string, pump very slowly and stop as soon as the pressure increase is noted on the casing side, then read the drillpipe pressure. Record this as SIDPP.
b.
The shut-in casing pressure – pressure – SICP SICP
c.
Measure the pit-level increase.
Record these data on the Surface BOP Kill Sheet. As quickly as possible, using the Surface BOP Kill Sheet make the necessary calculations and determine: d.
the mud density required to balance balance the formation pore pressure (see Appendix 1).
e.
the pumping speed (unless already determined), based on the pre-established mixing rate of the barite; but not more than half the speed used in normal drilling operations.
f.
The number of pump pump strokes required to displace the influx to the casing casing shoe.
Confirm that all persons involved with the well kill are aware of the proposed kill method and procedures to be used. In case the manual operated choke needs to be used, it is convenient to have a means of reading
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in situations with danger of differential sticking (highly deviated and horizontal wells) and/or plugging of the annulus.
The well can be controlled, even if weighting material supply is inadequate. Easier to use in vertical vertical wells with a taper string, in highly deviated wells and horizontal horizontal wells.
The principal disadvantages of the Driller's Method are:
The well will be closed in under pressure longer. The maximum pressure at the casing shoe and against the formation might be higher if the influx is gas however this depends on the borehole and the drillstring configuration. The downhole pressures of both methods will be the same as long as the drillstring - open hole capacity is the same or less than the internal drillstring capacity. The maximum choke pressure when the top of the influx reaches the surface will be higher if the influx is gas.
In more complex situations the volumetric method or the bull heading can be considered. All these methods are described in the following sections: 7.1.3
Initial Preparation Prepare the killing graph according to which well kill method has been chosen, to show the standpipe pressures to be maintained against the elapsed pump strokes during the killing operation. While making the above calculations, the well should remain closed in, with the closed-in pressures being observed and recorded continuously. If gas migration (percolation) occurs, SIDPP and SICP will continue to rise simultaneously after the initial build-up and, unless remedial action is taken,
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By a determining the initial circulation pressure in this way the SCR can be re calculated as: Slow circulation rate = initial circulating pressure - shut in drill pipe pressure
This procedure is satisfactory at any time during a kill providing the mud density in the drillstring is stable during the process. It is however preferable to maintain pump rate constant as much as possible. Any decision to change pump rate should be taken early.
7.2
Drillers Method In this method the well is killed in two steps (circulations). 1.
In the first step (circulation) is the influx circulated out, using the original mud and applying backpressure to the bottom hole, equal to the excessive BHP
2.
second step (circulation), when when weighted up mud is available, the well is killed.
Before using the Driller's method, it is essential to confirm that exposed formations and casing can support the higher pressures, which may be developed during the first circulation. 7.2.1
Kill Procedure Prior to undertaking the following procedure it is assumed that the well is shut in as per the Shut-in Procedure described in 6 in 6 and all pre-kick information is recorded on the pre kick sheet as follows: Pre-recorded Information items on the Surface BOP Kill Sheet can be noted as follows: 1.
Formation Strength Data: a.
Leak-Off Test pressure (A)
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Once well killing procedures have been discussed and agreed the well kill procedure should commence as follows: 3.
Open the choke about one-quarter, start the pump and break circulation; then bring the pump up to the kill rate (the time to bring up the pumps to kill speed should be one minute no less no more)
4.
While the driller is bringing the pump up to the kill rate, the choke operator should operate the choke so as to keep the casing pressure at/or near the closed in casing pressure reading.
5.
Once the pump is up to the kill rate, the choke operator should should transfer his intention to the drill pipe pressure gauge and adjust the choke choke to maintain the initial circulation pressure on the drill pipe pressure gauge. If there is no slow circulation rate pressure or uncertainty about it, the pressure reading on the drill pipe gauge, by keeping the casing pressure constant, will be the established initial circulating pressure (remember the time delay between drill pipe and casing pressure gauges).
6.
The initial circulating pressure is held constant constant on the drill pipe pressure gauge by adjusting the choke throughout the whole of the first circulation, until all of the kick fluid has been circulated out of the well. The pump rate must also be held constant at the kill rate throughout this period.
7.
To confirm that there is no more kick in the well, shut in drill pipe pressure and shut in casing pressure should be near same (pumps off) and the suction pit level should be nearly the same like before the kick.
8.
Once the kick is out of the hole, shut in the the well in and continue to mix up the kill kill mud density density required as per the following formulae
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7.2.3
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Second step (kill circulation) Having successfully circulated out the initial influx the second step is to circulate the well to kill mud as follows: 1.
Line up suction to kill mud.
2.
Open the choke about one-quarter, start the pump and break circulation. Then bring the pump up to the kill rate.
3.
While the driller is bringing the pump up to the kill rate, the choke operator should operate the choke so as to keep the casing pressure steady at the same pressure as when closed in after the first step (circulation) .
4.
While the drill pipe is being filled with with the heavy mud there are two options for keeping BHP constant, either keep the casing pressure constant or follow a graph going from ICP to FCP. When killing highly deviated, horizontal wells or vertical wells with a taper string it is recommended to keep the casing pressure constant. Notes:
If the influx was gas gas and all the gas was not removed during the first step (circulation), the first option of keeping casing pressure constant could lead to higher annular pressures and a new kick. The drill pipe pressure will go down as the drill pipe is is being slugged with with the heavier mud. In practice, if all the kick was properly removed in the first step (circulation), the choke should not need to be touched once the pumps are steady at the kill rate, until kill mud reaches the bit.
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7.3
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Wait and Weight Method This method is also a lso known as the “balanced” or “Engineers” method. This method is normally used if the bit is on bottom, or after the bit has been stripped to the bottom, and if enough barite is on the location. With this method the well is killed in one step (circulation). However, at least two circulations are usually made:
to circulate and clean the well,
to fully condition the entire mud system, and
to add the necessary trip margin to the trip out without swabbing.
Once the well is shut in and pressure still remains, the shut in drillpipe pressure is used to calculate the kill mud weight. Mud off the required weight is made up in the mud pits. When ready, kill mud is pumped down the drillpipe. At commencement, enough drillpipe pressure must be held to circulate the mud, plus a reserve equivalent to the original shut-in drillpipe pressure. This total steady decreases as the mud goes down to the bit, until with kill mud at the bit, the required pressure is simply that needed to pump kill mud around the well. The choke is adjusted to reduce drillpipe pressure while kill mud is pumped down the string. With kill mud at the bit, the static head of mud in the drillpipe balances formation pressure. For the remainder of the circulation, as the influx is pumped to the surface, followed by drillpipe contents and the kill mud, the drillpipe pressure is held at the final circulation pressure by choke adjustment. Ensure sufficient barite is on location and the mixing capacity is according to the selected pump rate. The wait and weight method uses the same calculations already described for a drillpipe pressure
Well Control Manual
7.3.1
c.
Hole Data: Size
d.
Pre-recorded Volume Data:
e.
Volume of surface equipment (no provision on the sheet )
f.
Drill String tubular sizes
g.
Length of HWDP and Drill Collars
h.
Volume of all tubulars in use
i.
Volume between all tubulars in use and open hole/casing
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Preparation to kill 1.
Inspect the surface BOP equipment and and ensure all equipment is is holding without without leaks.
2.
Continue observing and record the SIDPP, (PDP ) and and the SICP, (PAn ).
3.
Keep the drillpipe pressure constant while mixing up the new mud.
4.
Complete the applicable IWCF Surface BOP Kill Sheet and compare it with the Toolpusher to avoid mistakes. Set up a graph and the step down chart for the correct situation of the well and drill string for pumping down the kill mud to the bit.
5.
Select pump rate, determine the height and gradient of the influx, and and travel times as per the balanced method above.
6.
Calculate the MAASP at casing shoe and on surface. If below critical pressures start killing the well by using the balanced method.
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in steps according to the IWCF Surface BOP Kill Sheet and the graph until the kill mud has reached the bit. As long as the heavy or kill mud interface is still inside the drillstring there should be very little change in the choke opening position. If the drillpipe pressure must be adjusted to correspond with the pressure line on the IWCF Surface BOP Kill Sheet , that pressure change should be made using the annulus pressure gauge. Allow sufficient time for that pressure transient to work its way back to the drillpipe gauge. Typically, at the speed of sound in the drilling fluid, or about 1 second per 1000 ft (300 m) for the travel path. Where the kick is a small one, at or near the bottom of the hole, the drillpipe pressure tends to drop of its own accord as the kill mud moves down. Little or no choke adjustment is required. Only in cases of diffused gas kicks with gas far up the annulus will significant choke adjustments be needed during this period. DO NOT ATTEMPT TO INCREASE THE STANDPIPE PRESSURE BY CHOKE MANIPULATION AGAINST THE DIRECT READING OF THE STANDPIPE PRESSURE. This will result in excess pressure build-up and possible formation breakdown. 16. After kill mud has reached the bit, the drillpipe pressure is maintained at the final circulating pressure, until the kill mud returns to surface. As an option the pump can be stopped and the well shut in. The shut in drillpipe pressure now should be zero. The behaviour of the choke pressure is different depending on the type of influx. When the gas starts to reach the surface there will be big variations in choke pressure due to slugs of
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Figure Figure 7-3 Profile of Circulating Pressure while killing by Wait and Weight Method
Well Control Manual
7.4
Other Kick Killing Methods
7.4.1
Concurrent Method
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This method is also known as the slow slow weight - up method. This method was used in the past when the mud mixing facilities were not as efficient as they are today. It is, however, a method which can be used if circumstances warrant it, therefore an understanding of how the method works is desirable. As soon as the shut in pressures have stabilised following a kick, circulation is started immediately with the current drilling fluid. Bottom hole pressure is kept equal to or slightly above formation pressure by manipulation of the choke, to keep the casing pressure constant at the shut in value, while bringing the pump up to the desired slow circulation rate. The kill mud density, ICP, FCP, strokes and time to displace are calculated and adjusted the same as for the wait and weight method. Weight up of the mud is now started by 0.1 ppg (0,012 kg/l, 11,2 kg/m3 ) increments in the suction pit, while circulating, until such time as the calculated kill mud density is reached. This means that several different mud densities are in the drill stem between surface and bit, at one and the same time. It is of prime importance therefore to keep an accurate record of the strokes and time (and the corresponding drillpipe pressure), at which each incremental weight up is started down the drill stem and the time and strokes (and corresponding drillpipe pressure), at which each incremental weight up will reach the bit. When preparing a pressure schedule, the ICP and FCP have to be recalculated for each increase in mud density. Calculations have to be made while circulating which which is what makes this method rather complicated and prone to error.
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Although the method is theoretically viable, caution should be exercised during implementation to avoid further influx influx gains. gains. 7.4.2.1 Volumetric Method with the Bit Off Bottom Prior to undertaking a volumetric kill consideration should be given to stripping to bottom and killing the well conventionally. Should it be deemed necessary to undertake this technique the precedure to be followed should be as follows: 1.
Close in the well, record Pa and determine the volume of the influx (V influx).
2.
Make a kill graph and fill in the IWCF Surface BOP Kill Sheet.
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underbalanced. The safety margin should be reduced for critical wells; such as where a low MAASP does not allow for excess pressure to be applied to the well bore. 4.
Bleed off mud (V1) from the well, while maintaining Pchoke constant. V1 =
Pw x OH / DC cap
p1
5.
When the additional mud volume has accumulated in the trip tank the well is closed in until Pchoke rises, under the influence of the migrating gas influx, by one increment of Pw.
6.
By repeating step (5) and (6) as often as necessary, gas is allowed to migrate upward and expand while a nearly constant BHP is maintained.
7.
When gas is considered to be above the bit (calculated (calculated by migration rate), use a conventional well killing to remove the influx from the well.
8.
If conventional well killing killing is still not not possible, the method has to be continued until gas has reached the surface.
9.
Gas has to be replaced with mud by pumping mud into the well intermittently through the kill line. This procedure is called “Lubricating”.
10. Pump mud
V2
= Pw x (CSG/DP cap.) (pmud in use ) into the annulus.
11. Allow the gas to migrate to the surface again. 12. Bleed off gas ONLY until the choke pressure (the pressure prior to pumping reduced by one Pw increment.
2 mud) is
13. Repeat the lubricating exercise until all gas has been replaced with mud and the well is under control noting that this method has not killed the well; it has only removed the influx .
Well Control Manual
Figure 7-6 Volumetric Kill Graph
3.
Allow the pressure to build up to Pchoke where: Pchoke
=
Pa + Pw + safety margin
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13. Strip back to bottom and kill the well by using the Driller's Method (after solving the initial circulation problems). Note:
Proper records should be kept during the well killing operation:
Pchoke versus time to identify an increase in the number of pressure build build ups, which is an indication of gas entering annular capacities. Pchoke versus
7.4.2.2 Kick Control by Using Combined Stripping and Volumetric Method When the drillstring is partly or completely out of the hole, and there is a kick situation, then an attempt to get the bit as far back to bottom as possible must be made, while, at the same time, maintaining well control.. The string needs to be stripped back preferably through the annular preventer. This should be a smooth and efficient operation. It requires knowledge of equipment and procedures used by all rig crew. Refer to Figure to Figure 7-9 “Rig Layout for combined Stripping and Volumetric Method”. When applying the combined stripping and volumetric method, estimates of worst case pressures applied to the wellbore can be calculated by using the well control formula in the volumetric method described previously. Combined Stripping and Volumetric Procedure When applying the combined stripping and volumetric method a worst-case estimation of the pressures acting along the wellbore can be obtained by using the formula above. Actual pressures during volumetric killing operations will depend on the following:
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3.
Line up the choke manifold outlet to the trip tank.
4.
Calibrate the trip tank and the strip tank.
5.
Ensure the annular preventer operating pressure is adjustable between 100 and 3000 psi (7 – 207 – 207 bar, 700 – 700 – 20700 20700 kPa).
6.
Empty the trip tank to approximately 50%, measure the distance top trip tank –top –top fluid level.
7.
Install the inside BOP on the kelly cock, open the kelly cock and ensure the inside BOP is holding the pressure.
8.
Adjust closing pressure on the annular BOP low enough to maintain a seal on the drill pipe with a slight amount of drilling fluid leakage as the tool joint passes trough the packing. This fluid leakage indicates optimum seal off for minimum packing unit wear.
9.
After stripping stripping back to bottom readjust the closing pressure to the recommended pressure.
10. Close ram type preventer, due to wear on the annular preventer when on bottom. Stripping with the Annular Preventer and one Ram Preventer 1.
If kelly-cock / inside BOP or other string components will will not strip through the annular preventer, try to bring the tool joint to above the annular preventer.
2.
Close bottom ram preventer.
3.
Bleed off pressure in between annular and ram preventer.
4.
Open annular preventer. Remember the vent line in 3.1 step (2).
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Stripping Ram to Ram 1.
Are additional preventers and spools installed?
2.
Close the top rams, bleed off to approximately 800 psi closing pressure and observe for leaks.
3.
Strip in and tag the top rams. Pick up the string in tension before closing the bottom rams.
4.
Close the bottom rams. Check if they are closed.
5.
Bleed off all pressure between the rams.
6.
Open top rams. Check they are fully open.
7.
Strip in and tag bottom rams. Pick up the string in tension before closing top rams.
8.
Close top rams. Check if they are fully closed.
9.
Pressure up between the rams to the well pressure.
10. Open the lower rams. Check Check if they are fully open. 11. Continue to strip in the hole by repeating steps (4) through (11) in sequence. 12. Make a kill graph.
Well Control Manual
Vinf =
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3
Initial influx volume, (litre, m or bbl) 3
OH / DC cap = Open hole / DC annular capacity, (m /m, l/m or bbl/ft 3
OH cap =
Open hole capacity, (m /m, l/m or bbl/ft)
P1 =
Mud gradient, (kPa/m, bar/m or psi/ft)
Pinf =
Estimated influx gradient, (kPa/m, bar/m or psi/ft)
Pw =
Working pressure increment.
Note: Convenient values for working pressure increments are between 350 to 700 kPa (50 to 100 psi or 3.5 to 6.5 bar) depending on scale divisions on the pressure gauges. In critical cases where a low MAASP does not allow excessive pressures to be applied to the well bore; a smaller pressure increment could be used until the influx is above the DCs. 14. Once the required choke pressure is reached, Pchoke is kept constant while while the drillpipe is stripped back in the hole. Excess pressure is bled off via the choke manifold into the trip tank. 15. The closed-end pipe displacement displacement of each stripped in stand of drillpipe drillpipe is then drained from the trip tank into a stripping tank. 16. The string is then stripped into the hole until a volume of ∆V1 has accumulated in the trip tank. ∆V1 = Pw x OH / DC cap p1
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25. Continue to kill the well by using the Driller's Method. If it is a swab kick, the normal normal mud can be used as it is proven (during drilling) that it was overbalanced. 7.4.3
String Out of the Hole If the string is out of the hole when an influx is detected and the closed in surface pressure allows lowering the first stands of DCs or DP into the well, stripping should be started, as it will improve the well control situation. The kelly or the top drive may have to be used for extra weight on the first stands. The maximum surface pressure that can be overcome by the weight of the first stand, ignoring the friction between the annular preventer and the string is: Max. surface pressure = ( Weight of first stand in mud )/(Cross sectional area of the s tand)
Once calculations have confirmed that the weight of the first stand can overcome the recorded surface pressure proceed as follows: 1.
Install a bit sub with float valve on the first stand of DC DC (and/or gray valve) or an inside BOP on the first stand of DP when stripping with DP only.
2.
When stripping with DC, make up a bit without nozzles to reduce the chance of plugged nozzles.
3.
Lower the stand to the top of the blind / shear rams and close close the annular preventer.
4.
Open the blind / shear rams and strip through the annular preventer. Allow the choke pressure to increase by Pw, and maintain it constant thereafter.
5.
Fill the string with mud.
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7.4.4
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Killing by Bullhead Squeezing WARNING: Bullhead squeezing is not a routine operation and the execution has to be discussed with the drilling management in detail. If normal well killing techniques with conventional circulation is not possible or will result in critical well control situations, bullhead squeezing may be considered. Bullhead squeezing means that mud and influx are displaced or squeezed back downhole into the weakest exposed open hole formation. Bullheading can be a valuable tool for fighting kicks under circumstances such as the following:
The influx contains more H2S than the operation can tolerate.
Plugged or parted drillpipe cannot get kill mud to bottom.
A weak zone below the kick takes mud too fast for a kill kill by circulation.
Disadvantages of the Bullheading Squeezing Method are:
In many cases it will be doubtful if the well can be killed by squeezing the influx back into the formation. There is a potential risk of fracturing formations anywhere in the open hole, which can lead into a underground blow out situation. In the case of shallow casing setting depths this could lead to cratering.
The weakest weakest formation may not be the formation from where the influx influx were were coming.
Bullhead squeezing may require very very high pressures pressures to be applied at surface equipment. equipment.
Even if squeezing fluid back into the formation is possible to some extent, it may not be
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Note: These rates obviously assume that the there exists a formation which is able to take this volume per minute. 7.4.5
Kick Control in Deviated and Horizontal Wells Most of the well control methods are applicable to deviated and horizontal wells. However, when the string is off bottom, or when circulation at bottom is not possible, well control options become limited. The volumetric method or bullhead squeezing are most likely to be unsuccessful or ineffective in the horizontal section. All hydrostatic pressure related calculations need to be based upon true vertical depth (T VD) values. This means the standpipe kill graph of a deviated well has a different curve as compared to the graph for a vertical well due to the behaviour of Pdp . It applies only for Phase 1 balanced method, since the standpipe pressure remains constant for the other phases. When the standpipe kill graph for a deviated hole is constructed, higher than required BHP will occur in Phase 1 during the well killing. Especially in deep, highly deviated holes, and horizontal wells, this overbalance can be relatively high and should be taken into account. Well control formulas used also apply for deviated deviated holes as long as the hydrostatic pressure related calculations are based upon true vertical depths. For hydrostatic pressure related calculations the TVD of the deepest part of the horizontal section should be used. However, a bottom hole angle of 90° cannot be used in the calculations due to arithmetical reasons. A maximum bottom hole angle of 89° should be used instead.
7.4.5.1 Kick Control Considerations for Horizontal Wells
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Figure 7-8 Standpipe Kill Graph for Deviated Wells
4.
Connect the points A - B - C - D obtained obtained in steps (1), (2), and (3) with straight lines. This profile represents the standpipe pressure while pumping the new mud from surface to bit. Note:
The standpipe pressure at point of interest is calculated using following formula:
Well Control Manual
An. Cap. shoe TV =
6.
Rev 1.01, June 2010
Volume of Influx at bottom Heightof Influx AH AH at shoe x Cos(holeincclination at shoe)
Proceed with applying standard well control calculations as per vertical wells.
7.5
Stripping Operations
7.5.1
Preparation for Stripping If the well kick whilst tripping, it is important that decisions are made quickly and that the procedures to be used are implemented as soon as possible. If pipe stripping is an alternative, everything is to be arranged to implement the stripping operation quickly. This means that there must be away of accurately measuring any mud volume bled off, accurate gauges must be available, pressure regulators on blowout preventers must be in good working order, and the equipment and procedures to be used mustd be known and practised. Strip drills in addition to the usual pit drills should be considered to train crews and to evaluate the stripping characteristics of the preventer in use. Additionally, even if stripping cannot for some reason be considered , it is essential that well control is maintained whilst decisions are made concerning the most effective well killing method to be employed. To this end, it is essential that equipment is rigged up to immediately implement the volumetric method.
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Well Control Manual
Figure 7-12 Effective of Running into the Influx
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7.6
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Potential problems while well killing A number of problems, can arise during a killing operation. Those most m ost likely to be encountered are discussed below, and are followed by a Quick Check List. Also refer to the Trouble Shooting Charts in section 7.6.4. section 7.6.4. Since there are a number of possible causes of an abnormality during the killing operation, keep in mind that:
If in doubt stop the pumps
Shut in the well
Observe the pressures
A logical analysis of the evidence available will almost invariably point to the solution required. Drop in Circulation Pressure This could be due to loss of a bit nozzle, a leak in a tool joint or a wash-out in the drillpipe, pump valve or piston, leakage in surface equipment. As before, suggested action to be taken can be found in the Trouble Shooting Chart, Section 7.6.4. Section 7.6.4. Lost Circulation If standpipe pressure Pst and choke pressure do not respond to either opening or closing of the choke and it is is noted that the mud returns returns have decreased (or ceased). This may mean circulation has been lost either directly to the formation, or through a bad cement job, or a hole in the casing. Possible courses of action are given in the Trouble Shooting Chart, Section 11.24. 7.6.1
MAASP is reached
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Once the well is closed in, SICP and SIDPP must be continuously observed. If both start to show signs of an increase, it will be due to upward migrating gas. The gas should be allowed to expand by opening the choke until SIDPP reverts to the closed-in pressure observed at the time of equipment failure. (If circulation is stopped after the kill fluid reaches the bit, SIDPP will normally be zero.) Once repairs have been completed the killing procedure can be restarted. 7.6.3
Hydrates The formation of hydrates is dependent upon a combination of the following conditions: a.
Presence of free water
b.
Gas at or below it's dew point
c.
Low temperature
d.
High pressure
The hydrate problem is aggravated by pressure drop / gas expansion (through the choke) and pressure pulsing. As the gas passes through these restrictions the resulting pressure drop plus the sudden increase in velocity cause “expansion cooling” of the gas immediately downstream of the choke. Hydrates can cause severe problems by plugging valves or chokes and completely blocking flow. Upstream pressure increases and this compounds the problem. Prevention of hydrates will always be easier and better than the cure. It may be necessary to inject methanol or glycol to suppress hydrate formation. Ports can be modified into the choke manifold for
Well Control Manual
Rev 1.01, June 2010
7.6.4.1 Drillpipe Pressure and Casing Pressure BOTH UP the same amount
Action to take
Result
Problem
Solution
Check pump rate.
Pump rate too fast.
Circulating pressure is too high because the pump is running faster than was planned.
Slow the pump rate down to the planned rate. If pressure comes down, everything is OK. If not, continue down chart.
Increase choke opening.
Drillpipe pressure and casing pressure will come down.
Choke opening was too small.
If the pressure come down when the choke opening was increased, everything is OK. If not, continue down chart.
Open choke all the way.
Drillpipe and casing pressure will come down.
Either choke opening was to small or the choke is on way to plug.
If pressures come down, everything is OK. If not, continue down chart.
Stop the pump.
Drillpipe and casing pressure will come down.
The choke manifold has started to plug up.
Switch to alternate chokeline. If pressure come down, go back to kill the well, if not continue down chart.
Shut the
Pressures stay up.
Manifold is plugged.
Switch to alternate chokeline. if
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7.6.4.2 Drillpipe pressure UP, and Casing pressure UP just a small amount
Action to take
Result
Problem
Solution
Check pump rate.
Pump rate too fast.
Circulating pressure is too high because the pump rate is faster than planned.
Slow the pump rate down to the planned rate. If pressures come down, everything is OK. If not, continue down chart.
Increase choke opening.
Drillpipe pressure and casing pressure will come down.
Choke opening was too small.
If the pressure come down when the choke opening was increased, everything is OK. If not, continue down chart.
Casing pressure comes down, but not drillpipe pressure.
Wait at Wait at least 2 minutes to see if there is a long lag between choke movement and drillpipe pressure.
Allow for a long time lag with big gas kicks. If pressure will not come down, continue down chart.
Drillpipe pressure does not come down.
A mud ring or pack off near the bit.
Raise or reciprocate the drillpipe. If drillpipe pressure comes down, OK. If not, continue down chart.
Plugged jets.
Restore casing pressure to where it was before the trouble started..
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7.6.4.3 Drillpipe pressure changed UP abruptly; Casing pressure NO CHANGE Excessive Standpipe Pressure This could be due to plugged bit nozzles, plugged annulus below the influx or a plugged choke. Evidence of the first two is an increase in standpipe pressure with no increase in choke pressure. If both standpipe pressure and choke pressure increase, it is an indication of a plugged choke. Suggested action to be taken in these circumstances can be found in the Trouble Shooting Chart, below. Action to take
Result
Problem
Solution
Check pump rate.
Pump rate too fast.
Circulating pressure too high because rate is faster than planned.
Slow the pump to the planned rate.
Increase choke opening.
Casing pressure gets very low before drillpipe pressure comes down.
A mud ring or pack off near the bit.
Raise or reciprocate the drillpipe. If drillpipe pressure comes down, OK. If not, continue down chart.
Increase choke opening.
Casing pressure gets very low before drillpipe
Plugged bit.
Either: taking the new drillpipe pressure as the constant circulation
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7.6.4.4 NO CHANGE to Drillpipe pressure; Casing pressure DOWN or NO CHANGE.
Action to take
Result
Problem
Solution
Increase or decrease in choke opening.
Pressure does not seem to respond to choke movement.
Lost circulation, bad cement job, or a hole in the casing. Check pit volume.
Take a new slow circulating rate. Add circulation material. Add barite plug. Add cement plug over barite plug
Check pit volume.
Volume OK.
Check of the choke for failure.
Switch to alternate choke.
7.6.4.5 Drillpipe pressure DOWN; and Casing pressure DOWN
Action to take
Result
Problem
Solution
Check pump rate.
Pump rate too slow.
Pump rate is lower than planned
Increase the pump rate to the planned rate. If pressures
Well Control Manual
Continually decreasing choke opening.
Rev 1.01, June 2010
Pressures increase but Kelly hose jumps and drillpipe pressure surges.
Pump trouble.
Change pumps or repair pump.
Drillpipe pressure stays the same, casing pressure goes up.
Hole in the drillpipe.
Stop the pump and shut in the well in. You may have to strip out to replace a joint of pipe.
7.6.4.7 Drillpipe pressure ABRUPTLY DOWN; Casing pressure NO CHANGE Action to take
Result
Problem
Decrease choke opening.
Drillpipe and casing pressure go up.
Washout in bit or in drillpipe.
Solution Stop the pump and shut in the well in. You may have to strip out to replace a joint of pipe.
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8 Appendix 1: Forms, Calculations, Worked Examples
Well Control Manual
8.1
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Kick Drill Sheets: Pit/Kick Drill Report – Hard/Fast Shut In
Pit / Kick Drill Report HARD/FAST SHUT IN Date: Time:
Location: Driller:
Rig: Depth:
m
Bit depth:
m
Pit drill during tripping Duration Omit not applicable steps
Time Time Time Time Time Time Time
to recognize kick to place Kelly cock (and close) to open HCR valve to close annular preventer to close pipe rams to place top drive to Kelly cock
sec. sec. sec. sec. sec. sec.
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8.2
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Kick Drill Sheets: Pit/Kick Drill Report – Soft Shut
Pit / Kick Drill Report SOFT SHUT IN Date:
Location: Driller:
Rig: Depth:
m
Bit depth:
m
Time:
Pit drill during tripping
1 Duration Omit not applicable steps
Time to recognize kick Time to place Kelly cock (and close) Time to open HCR valve Time to close annular preventer Time to close pipe rams Time to close choke (close valve in front)
sec. sec. sec. sec. sec. sec.
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8.3
Kick Killing Worksheets (IWCF Forms)
8.3.1
IWCF Kill Sheet Vertical Well (Bar/Metric) Page 1 of 2
Rev 1.01, June 2010
PAGE 1 OF 2
International Well Control Forum
DATE :
Surface BOP Kill Sheet - Vertical Vertical Well (Metric/Bar) (Metric/Bar)
NAME :
C U R R E N T W E L L D A TA TA : :
FORMATION STRENG TH DATA: DATA:
SURFACE LEAK -OFF PRESSURE FROM FORMATION FORMATIO N STRENGTH TEST
(A)
bar
DRILLING FLUID DENSITY AT TEST
(B)
kg/l
MAX. ALLOWABLE DRILLING FLUID DENSITY = (A) x 10.2 (B) + = (C) SHOE T.V. DEPTH
C U R R E N T D R I L L I N G F L U I D: D:
kg/l
DENSITY
kg/l
I N I TI TI A L M A A S P =
((C) - Cur Curre rent nt De Dens nsit ity) y) x Shoe TVD 10.2
PUMP NO. 1 DISPL.
= C A S I N G S H O E D A TA TA :
PUMP NO. 2 DISPL. l / stroke
SIZE
in
M. DEPTH
m
T.V.. DE PTH T.V
m
l / stroke
(PL) DYNAMIC PRESSURE LOSS [bar]
HOLE DATA:
Well Control Manual
8.3.2
Rev 1.01, June 2010
IWCF Kill Sheet Vertical Well (Bar/Metric) Page 2 of 2 PAGE 2 OF 2
International Well Control Forum
DATE :
Surface BOP Kill Sheet - Vertical Well (Metric/Bar)
NAME :
KICK DATA : SIDPP KILL FLUID DENSITY
KMD INITIAL CIRCULATING PRESSURE ICP FINAL CIRCULATING PRESSURE FCP
(J) = ICP - FCP
bar
SICP
bar
CURRENT DRILLING FLUID DENSITY .................
litres
SIDPP x 10.2
+
+
PIT GAIN
TVD =
................ kg / l
DYNAMIC PRESSURE LOSS + SI DPP ................. + ................. =
............... bar
KILL FLUID DENSITY CURRENT DRILLING FLUID DENSITY
x DYNAMIC PRESSURE LOSS
x ................. ................. =
Bar
............... bar (J) x 100 --.--------(E)
=
Bar/100 strokes
Well Control Manual
8.3.3
Rev 1.01, June 2010
IWCF Kill Sheet Vertical Well Field Units) Page 2 of 2 PAGE 2 OF 2
International Well Control Forum Field Units
Surface BOP Stack - Vertical Well
KICK DATA : SIDPP KILL FLUID DENSITY KMD INITIAL CIRCULATING PRESSURE
psi
SICP
psi
CURRENT DRILLING FLUID DENSITY ................. +
barrels
SIDPP
+
X 0.052
PIT GAIN
=
ppg
DYNAMIC PRESSURE LOSS + SIDPP ................. + ................. =
ICP
(J) = ICP - FCP = ........... ................... ........ - ........... ................... ........ = ............ .............. .. psi
(J) x 100 (E)
=
X 100
=
psi 100 strokes
Well Control Manual
8.3.4
Rev 1.01, June 2010
IWCF Kill Sheet Deviated Well (Bar/Metric) Page 1 of 3 PAGE 1 OF 3
International Internation al Well Control Forum
DATE :
Surface BOP Kill Sheet - Deviated Deviated Well (Metric/Bar) (Metric/Bar)
NAME :
FORMATION STRENGTH DAT DATA: A:
CURRENT WELL D AT ATA: A:
SURFACE LEAK -OFF PRESSURE FROM FORMATION STRENGTH TEST
(A)
bar
DRILLING FLUID DENS. AT TEST
(B)
kg/l
DRILLING FLU ID DATA: DENSITY
kg/l
GRADIENT
bar/m
MAX. ALLOWABLE DRILLING FLUID DENSITY = (B) +
(A) x 10.2 (A) x
=
SHOE T.V.D
(C)
kg/l
INITIAL MAASP = ((C) - Current Density.) x Shoe T.V.D T.V.D 10.2
P U M P NO . 1 D I S P L .
=
KOP M.D.
m
KOP T.V.D.
m
EOB M.D.
m
EOB T.V.D.
m
bar
P U M P NO . 2 D I S P L . l / stroke
DEVIATION DATA:
CASING SHOE DAT DATA: A: l / stroke
SIZE
in
M. DEPTH
m
T.V. DEPTH
m
Well Control Manual
8.3.5
Rev 1.01, June 2010
IWCF Kill Sheet Deviated Well (Bar/metric) Page 2 of 3 Internationall Well Control Forum Internationa
DATE :
Surface BOP Kill Sheet - Deviated Deviated Well (Metric/Bar)
NAME :
KICK DATA : SIDPP
KILL FLUID DENSITY KMD
INITIAL CIRC. PRESS. ICP
FINAL CIRCULATING PRESSURE
bar
S I CP
bar
CURRENT DRILLING FLUID DENSITY .................
+
LOSS AT KOP (O)
+
litre
SIDPP x 10.2 TVD =
DYNAMIC PRESSURE LOSS + SIDPP
KILL FLUID DENSITY CURRENT DRILLING FLUID DENSITY
FCP
DYNAMIC PRESSURE
PIT GAIN
................ kg / l
................. + ................. =
............... bar
x DYNAMIC PRESSURE LOSS x ................. ................. =
PL + (FCP-PL) x
KOPMD TDMD
= .......... + (...........-............ (...........-............)) x
............... bar
=
............... bar
Well Control Manual
8.3.6
Rev 1.01, June 2010
IWCF Kill Sheet Deviated Well (Bar/metric) Page 3 of 3 PAGE 3 OF 3
International Internation al Well Control Forum
DATE :
Surface BOP Kill Sheet - Deviated Deviated Well (Metric/Bar) (Metric/Bar)
NAME :
] r a b [ E R U S S
Well Control Manual
8.3.7
Rev 1.01, June 2010
IWCF Kill Sheet Deviated Well (Field Units) Page 1 of 3 PAGE 1 OF 3
International Well Control Forum
DATE :
SURFACE BOP KILL SHEET
NAME :
DEVIATED
WELL
UNITS : FIELD
FORMATION STRENGTH DAT DATA: A:
CURRENT WELL D AT ATA: A:
SURFACE LEAK -OFF PRESSURE FROM FORMATION STRENGTH TEST
(A)
psi
DRILLING FLUID DENS. AT TEST
(B)
ppg
DRILLING FLU ID DATA: DENSITY
ppg
GRADIENT
psi/ft
MAX. ALLOWABLE DRILLING FLUID DENSITY = (B) +
(A) SHOE T.V. T.V. DEPTH x 0.052
=
(C)
ppg
INITIAL MAASP = ((C) - CURR. DENS.) x SHOE T.V. DEPTH x 0.052 psi
=
P U M P NO . 1 D I S P L . bbl / stroke
P U M P NO . 2 D I S P L . bbl / stroke
DEVIATION DATA: KOP M.D.
ft
KOP T.V.D.
ft
EOB M.D.
ft
EOB T.V.D.
ft
CASING SHOE DAT DATA: A: SIZE
in
M. DEPTH
ft
Well Control Manual
8.3.8
Rev 1.01, June 2010
IWCF Kill Sheet Deviated Well (Field Units) Page 2 of 3 PAGE 2 OF 3
International Well Control Forum
DATE :
SURFACE BOP KILL SHEET
NAME :
DEVIATED
WELL
UNITS : FIELD
KICK DATA : SIDPP
KILL FLUID DENSITY
ps i
S I CP
psi
CURRENT DRILLING FLUID DENSITY .................
INITIAL CIRC. PRESS.
DYNAMIC PRESSURE LOSS + SIDPP
ICP
................. + ................. =
FINAL CIRCULATING PRESSURE FCP
DYNAMIC PRESSURE LOSS AT KOP (O)
+
.................................
KMD
..................... x 0.052
KILL FLUID DENSITY
KOPMD TDMD
bb l
SIDPP
+
TVD x 0.052 =
................ ppg
............... psi
CURRENT DRILLING FLUID DENSITY .................... x ................. ................. = ....................
PL + (FCP-PL) x
PIT GAIN
x DYNAMIC PRESSURE LOSS
= .......... + (...........-....... (...........-............) .....) x
............... psi ............ ............
=
............... psi
Well Control Manual
8.3.9
Rev 1.01, June 2010
IWCF Kill Sheet Deviated Well (Field Units) Page 3 of 3 PAGE 3 OF 3
International Well Control Forum
DATE :
SURFACE BOP KILL SHEET
NAME :
DEVIATED
] i s p [ E R U S
WELL
UNITS : FIELD
Well Control Manual
8.4
Stripping Form
Pchoke = Pan + Ps + Pw
= ………..
Pan
= ………..
F – factor
= ………..
Volume influx
= ………..
Ps = F x Vi
= …………
Pw selected
= …………
divisions in triptank
Triptank level with required Pchoke
T. T. Level
Pch
Rev 1.01, June 2010
Well Control Manual
8.5
Rev 1.01, June 2010
Stripping Check Sheet
Step
Stripping Check List
1
Has one person being designated to supervise the entire stripping operation?
2
Is the bop stack spaced for stripping and are drawings with measurement available?
3
Is shut-in pressure recorded?
4
Was a heavy pill pumped into the hole before they started out of the hole?
5
Has an inside bop been installed in the drillstring?
6
Is there any evidence of gas migration?
7
Is there everything rigged up for the combined stripping and volumetric method?
8
Has the effective string weight being calculated?
9
Has wellbore force being calculated to verify that the string can be stripped back either through the annular preventer or ram preventer?
10
Has open hole capacity and open hole to DC capacity been calculated?
11
Are spare parts available for a lower kelly cock?
12
Will all the fluid which will be bled off go into the calibrated trip tank?
YES
Well Control Manual
Rev 1.01, June 2010
Stripping Calculations and Formulae A worst-case estimation of the pressures acting along the wellbore can be obtained by using the following formula. It is assumed the original influx volume was on bottom when the well was closed in, after which the BHP is established at (D x p 1).
Vinf.x = [(Dh x p1) - Pf ] x (Vinf.o x pop1) Px Where: A =
(X x p1 ) - Pf x ( OH.cap Av.cap.x)
Px =
Pressure at the top of the influx at point of interest ( x )
Av.cap.x =
Average annular capacity of influx at point x.
pinf.o =
Original influx gradient
p1 =
Mud gradient
po =
Pore pressure gradient
Pf =
pinf.o x hinf.o x p1 / po
X=
Depth of point of interest.
Well Control Manual
8.6
Rev 1.01, June 2010
Form for Completing a Leak off Test
Leak-Off Test Report
Well:
Area:
Date: Init. Press Final Press
P r e s s u
Well Control Manual
Rev 1.01, June 2010
Calculation of MAASP Calculation of the maximum pressure (at the top of the gas) when the gas influx reaches the shoe can be done either by calculation or graphically as follows: Calculation of the maximum pressure (at the top of the gas) when the gas influx reaches the shoe
us ing the formula formula: Px = 0.5A + [ 0.5A + { Po - ( hinf.o X pinf.a )} x p2 x (Vinf.o /AV.cap.x )] 1/2 where: A = Po - (D - X)p2 + D1(p2 - p1) - ( hinf.o x pinf.o) Px = Pressure at the top of the gas point X Po = Formation pressure hinf.o = Height of gas column at the bottom of the hole pinf.o = Original influx gradient p1 = Original mud gradient p2 = Kill mud gradient Vinf.o = Original influx volume AV.cap.x = Average annular capacity of influx volume at point x AV.cap.o = Average annular capacity of influx volume at bottom D = Depth of the hole X = Depth of point x D1 = Height of p1 mud in the annulus after it has been displaced from
Well Control Manual
Rev 1.01, June 2010
Figure 1: Graphic Determination of MAASP
Draw up the influx height and extend this line to the top, parallel with the BHP line. If this line is crossing the formation break down line below the shoe line the MAASP will be exceeded. (Line b in the graph). If crossing is above the shoe line the pressure at the shoe will be below the MAASP. (Line a in the graph). MAASP = MAASP = FBP - Head of mud in use to shoe.
Note:
The MAASP must be re-calculated if:
(a) The mud density is is changed. (b) A weaker formation has been detected. (c) A hole or or leak develops develops in the casing. (d) The cement bond around the shoe of the the casing fails Every time the mud density is changed, the MAASP changes and must be recalculated, hence the equation above can be rewritten as: MAASP = MAASP = (Breakdown gradient - Mud gradient) x Shoe TVD If a Maximum equivalent mud density is being used as formation strength then the above shall become:
Well Control Manual
Rev 1.01, June 2010
Once the formation pressure is known, the mud density required to kill (balance) can be calculated thus: Kill mud density (ppg) = Formation press. (psi)
Kill mud density (kg/l) = Formation press. (bar) 3
Kill mud density (kg/m ) = Formation press. (kPa)
SIDPP Drillpipe
SICP Annulus
Figure 8-1 U-tube method to determine reservoir pressure
Well Control Manual
8.8
Kick Behaviour
8.8.1
A comparison between oil and water base muds.
Rev 1.01, June 2010
Due to high temperatures and pressure a small gas kick can turn into a serious well control problem with oil base muds. Solution gas can become dissolved and miscible. miscible. The reason for this is that the gas remains in the solution until it reaches its bubble point. In the same way that gas in a disposable lighter remains in its liquid phase until the pressure is relieved. In the Figure the Figure 8-2 three barrels of gas have entered the wellbore at 10.000 ft, but we would see no pit gain while drilling until the gas has been circulated up to 2600 ft. The gas then expands rapidly and there is the real danger of blowing out sufficient mud to put the entire well underbalanced. This problem is easier to detect in in water based mud (figure 2) because the original volume of the gas gas will expand much earlier as the pressure above the gas is reduced. The problem in oil base muds is that if a kick has entered the wellbore undetected it is impossible to know where the top of the gas is. For example if the pump rate is say 80 SPM and the pump ou tput is 0,117 bbls then in an 8.5” hole section with 5” drill pipe the influx would travel 203 ft for each minute that the kick is undetected. In extreme cases the gas could be 6000 - 7000 ft away from the surface without the driller realising anything is wrong. Under these conditions it may be prudent to count all drilling breaks as primary indicators. Stop drilling, shut off the pumps and close the well in. The gas can then be circulated through the choke in a safe manner utilizing the first circulation of the driller's method. Some procedures advised that the gas should be circulated to 2500 feet (750m) below the bop before the well is shut in and the gas circulated through the choke. It may be the case that the bubble point is lower and unless this information is known, even though the first procedure may take a little longer, remember safety is always our main concern.
Well Control Manual
Rev 1.01, June 2010
Well Control Manual
Rev 1.01, June 2010
In any other case the results can become negative or result in an incorrect gradient for the influx. The solution is for each kick has to be handled as a gas kick.
The relationship between surface pressures, influx height and density is: Grad. of influx, psi/ft = Grad. of mud, psi/ft - [(SICP - SIDPP) Influx height, ft]
8.9.1
Example Influx gradient Calculations
8.9.1.1 Example using API Field units: When drilling at 12500 ft with 14 ppg mud we took a pit gain of 20 bbls. When the well was closed in, the SIDPP read 300 psi, and the SICP read 705 psi. If annular volume around drill collars is 0.03 bbls/ft, calculate the influx gradient. Influx height = Kick volume Annular volume = 20 bbls 0.03 bbls/ft = 667 ft Grad. of mud = 14 ppg x 0.052 = 0.728 psi/ft Grad. of influx = 0.728 psi/ft - [(705 - 300) 667] = 0.728 - 0.607 = 0.12 psi/ft 8.9.1.2 Example using Bar / Litre units: When drilling at 3810 m with 1,68 kg/l mud we took a pit gain of 3180 litres. When the well was closed in, the SIDPP read 21 bar, and the SICP read 50 bar. If annular volume around drill collars is 15,14 l/m, calculate the influx gradient. Influx height = Kick volume Annular volume = 3180 l 15,14 l/m = 210 m
Well Control Manual
Rev 1.01, June 2010
Further, if that same mass of gas is taken to a different absolute pressure, then it will also occupy a different calculable volume. Note:
The effects of compressibility and temperature must also be taken into account for absolute precision but may be neglected for most field determinations.
For a unit of gas we have a unit of pressure, but we can compress that unit of gas to half it's original size by doubling the pressure upon it. Original pressure x Original volume = New pressure x New volume, or, P1 x V1 = P2 x V2 Working this equation will show the extremes that occur with gas kicks. 8.11.1.1 Example Calculation Examples using API Field Units: When drilling with 10 ppg mud at 10000’ we take a kick of 30 bbls. If the kick was allowed to travel to surface and expand freely, the following would be true: At 10000' the hydrostatic pressure of the mud and the kick (ignoring formation pressure) would be:
Well Control Manual
Rev 1.01, June 2010
As the bubble reach es 1530 153 0 m with a hydrostatic hea d of 180 bar, the volum e of the gas bubble is now: P1 x V1 = P2 x V2 360 x 4.77 = 180 x V 2 V2 = (360 x 4.77)
3
180 or V2 = 9.54 m .
(But as the gas bubble breaks out at surface in atmospheric (1 bar), the original 4.77 m gas now becomes:
3
influx of
P1 x V1 = P2 x V2 360 x 4.77 = 1 x V 2 V2 = (360 x 4.77)
3
1 or V2 = 1717 m .
This is a much greater volume than the entire annular capacity so the well would be blowing wildly. 8.11.2 Gas Migration If the well is closed in, the gas bubble will migrate up the annulus and hence cause the Shut In Casing Pressure (SICP) to increase. Unless there is a float sub in the bottom hole assembly, the pressure increase will also be reflected on the Shut In Drillpipe Pressure (SIDPP). If the bubble is allowed to rise but is NOT allowed to expand, then the rising bubble will bring the bottom hole pressure (BHP) up the well and cause the pressure to increase both ahead of and
Well Control Manual
Rev 1.01, June 2010
Migration rate ft/min = (New SICP - Original SICP) (Mud Grad. x Difference in time of SICP's)
Note: In horizontal wells and while the gas is in the horizontal section there will be no noticeable migration of gas. In highly deviated wells the migration can be very slowly or even zero. Even in vertical wells it can be that no migration takes place.
8.12
Hydrates The formation of hydrates is dependent upon a combination of the following conditions: a.
Presence of free water
b.
Gas at or below it's dew point
c.
Low temperature
d.
High pressure
The hydrate problem is aggravated by pressure drop / gas expansion (through the choke) and pressure pulsing. As the gas passes through these restrictions the resulting pressure drop p lus the sudden increase in velocity cause “expansion cooling” of the gas immediately downstream of the choke. Hydrates can cause severe problems by plugging valves or chokes and completely blocking flow. Upstream pressure increases and this compounds the problem. Prevention of hydrates will always be easier and better than the cure. It may be necessary to inject
Well Control Manual
8.13
Rev 1.01, June 2010
Worked Examples
8.13.1 Example Calculations – Kick Tolerance 8.13.1.1 Example using API Field Units: We are drilling at 8000' with 12 ppg mud. The casing shoe is at 3500' and the current MAASP is 810 psi. A 40 bbl gas influx (gradient 0,100 psi/ft) enters the well and a nd the surface pressures after close in are SIDPP = 520 psi, SICP = 692 psi. Max. tolerable pressure at shoe = MAASP + Hydrostatic pressure at shoe: = 810 + (3500 x 12 x 0.052) = 2994 psi. Formation pressure = SIDPP + Hydrostatic at TVD: = 520 + (8000 x 12 x 0.052) = 5512 psi Kick tolerance max. height of influx: = (MAASP - SIDPP) ÷(Grad. of mud - Grad. of influx) = (810 - 520) ÷0.624-0,100) = 553 feet, and if annular capacity is 8.23 ft/bbl then 553 ft becomes 67 bbls. This is the maximum volume of
Well Control Manual
Rev 1.01, June 2010
= (MAASP - SIDPP) ÷(Grad. of mud - Grad. of influx) = (57 - 36) ÷(0.141 - 0.0271) = 184 m, 3
3
and if annular capacity is 19 m/m then 184 m becomes (184 x 19) = 9.68 m . This is the maximum volume of influx that we could have at the shoe and if we calculate back using Boyles Law to find a tolerable volume of original influx, the equation reads thus: P1 x V1 = P2 x V2 or (211 x 9.68) ÷380 = V2 = 5.37 m
3
3
Calculating our 6.360 m influx, then the volume at the shoe would be: 3
V2 = (380 x 6.36) ÷211 = 11.45 m . This is clearly not viable to circulate out using the Driller’s Method. However, if the annulus volume below the shoe is greater than the string volume then there will be kill mud in the annulus prior to the bubble getting to the shoe and hence lowering the pressure at the shoe.
Well Control Manual
Rev 1.01, June 2010
8.13.2 Example Calculations: Barite Addition 8.13.2.1 Weight of Barite required for mud density increase. For mud density in ppg: Lbs. Of Barite required/bbl mud =
1490 x(new muddensity old mud density ) ( 3,55 new mud density )
For mud density in kg/l : Kg. of Barite required/m3 mud =
(new muddensity old mud density ) ( 4,2 new mud density )
8.13.2.2 Volume increase due to Barite addition For mud density in ppg: Volume increase (bbls) =
For mud density in kg/l :
(new muddensity old mud density ) ( 3,55 new mud density )
x 4200
Well Control Manual
Rev 1.01, June 2010
Volume to take out of original mud due to Barite addition without increasing the volume of mud amount:
Volume increase to original mud volume: 3
(L/m ) =
(new muddensity old mud density ) ( 4,2 old mud density )
x 1000
Weight of Barite required for mud density increase after reduced mud amount For mud density in kg/l :
Volume to add Barite after reduced mud amount: 3
(kg/m ) =
(new muddensity old mud density ) ( 4,2 old mud density )
(1,59 1,44 ) ( 4,2 1 44 )
x 4200
x 1000 = 54.34 L/ m
3
Well Control Manual
8.14
Rev 1.01, June 2010
Field Worked Example – Drillers method Scenario In a straight hole with the last casing at 1066 m a drilling break is experienced at a depth of 2438 m. The pump is stopped and the string is picked up. It is observed that the well is flowing and therefore it is closed in immediately. The shut-in drillpipe pressure, SIDPP, SIDPP, stabilises at 36 bar, and the shut-in casing pressure, SICP, SICP, at 49 bar. A check of the pit level recorder indicates a volume gain of approximately 2.4 m³. This information is added to the pre-recorded data on the IWCF Surface BOP Kill Sheet. We assume the decision is made to circulate the influx out first. Then with another full circulation the well will be killed. Record the remaining data on the Kill Sheet
Hole Data: Measured depth and TVD Volume Data: Length of DP
Calculate remaining Volume Calculate displacement in pump strokes and time (min) Circulating out the influx Calculate
Initial Circulating Pressure ICP (w/ kill fluid density)
Complete the graph with DP pressure versus strokes
Draw a horizontal line for the amount of strokes with with the ICP from surface to to bit.
Well Control Manual
Rev 1.01, June 2010
Kill Sheet Page 1 Driller`s Method. PAGE 1 OF 2
International Well Control Forum
DATE :
Surface BOP Kill Sheet - Vertical Well Well (Metric/Bar)
NAME :
C URR ENT W ELL DATA:: DATA::
FORMATION STR ENG TH DATA: DATA:
SURFACE LEAK -OFF PRESSURE FROM FORMATION FORMA TION STRENGTH TEST
(A)
65
bar
DRILLING FLUID DENSITY AT TEST
(B)
1,30
kg/l
MAX. ALLOWABLE DRILLING FLUID DENSITY = (A) x 10.2 1,92 = (C) (B) + SHOE T.V. DEPTH
C URRE NT DRILLING FLUID: FLUID:
kg/l
DENSITY
1,44
kg/l
INITIAL INIT IAL MAASP =
((C) - Current Density) 10.2
x Shoe TVD
=
50
C AS ING SHO E DATA: DATA:
SIZE
PUMP NO. 1 DISPL.
13,89
PUMP NO. 2 DISPL. l / stroke
13,89
in
M. DEPTH
1066
m
T.V. DEPTH
1066
m
l / stroke
RESSURE OSS RESSURE [bar] (PL) DYNAMIC P L
13 3/8”
HOLE DATA:
Well Control Manual
Rev 1.01, June 2010
Kill Sheet Page 2a Driller`s Method. Step 1: Circulating out all the Kick. PAGE 2 OF 2
International Well Control Forum
DATE :
Surface BOP Kill Sheet - Vertical Vertical Well (Metric/Bar) (Metric/Bar)
NAME :
KICK DATA : SIDPP KILL FLUID DENSITY
KMD INITIAL CIRCULATING PRESSURE ICP FINAL CIRCULATING PRESSURE FCP
(J) = ICP - FCP
36
bar
49
SICP
CURRENT DRILLING FLUID DENSITY .....................
bar
2400
litres
SIDPP x 10.2 10.2
+
+
PIT GAIN
TVD =
............... kg / l
DYNAMIC PRESSURE LOSS + SIDPP ...36...... + ....36......... =
72 bar ...............
KILL FLUID DENSITY CURRENT DRILLING FLUID DENSITY
x DYNAMIC PRESSURE PRESSURE LOSS
x ................. =
Bar
............... bar (J) x 100 --.--------(E)
=
Bar/100 strokes
Well Control Manual
Rev 1.01, June 2010
Kill Sheet Page 2b Driller`s Method. Step 2: Circulating in the Kill Mud. PAGE 2 OF 2
International Well Control Forum
DATE :
Surface BOP Kill Sheet - Vertical Vertical Well (Metric/Bar) (Metric/Bar)
NAME :
KICK DATA : SIDPP KILL FLUID DENSITY
KMD INITIAL CIRCULATING PRESSURE ICP
36
FCP
(J) = ICP - FCP
49
SICP
CURRENT DRILLING FLUID DENSITY ......1,44...........
2400
PIT GAIN
litres
SIDPP x 10.2 10.2
+
36 x 10,2 2438
+
bar
TVD ....1,59.... kg / l
=
DYNAMIC PRESSURE LOSS + SIDPP ...36...... + ....36......... =
72 bar ...............
KILL FLUID DENSITY
FINAL CIRCULATING PRESSURE
bar
CURRENT DRILLING FLUID DENSITY
1,59 1,44
x DYNAMIC PRESSURE PRESSURE LOSS
36 x ................. = 32
Bar
40 bar ............... (J) x 100 --.--------(E)
=
2
Bar/100 strokes
Well Control Manual
8.15
Rev 1.01, June 2010
Field Worked Example – Wait & Weight method Scenario In a straight hole with the last casing at 1066 m a drilling break is experienced at a depth of 2438 m. The pump is stopped and the string is picked up. It is observed that the well is flowing and therefore it is closed in immediately. The shut-in drillpipe pressure, SIDPP, stabilises at 36 bar, and the shut-in casing pressure, SICP, at 49 bar. A check of the pit level recorder indicates a volume gain of approximately 2.4 m³. This information is added to the pre-recorded data on the IWCF Surface BOP Kill Sheet. Record the remaining data on the Kill Sheet
h of DP
Calculate remaining Volume Calculate displacement in pump strokes and time (min) Calculate the following:
Kill Fluid Density
uid gradient)
Well Control Manual
Rev 1.01, June 2010
Kill Sheet Wait and Weight Method Page 1. PAGE 1 OF 2
International Well Control Forum
DATE :
Surface BOP Kill Sheet - Vertical Vertical Well (Metric/Bar) (Metric/Bar)
NAME :
C URR ENT W ELL DATA:: DATA::
FORMATION STR ENG TH DATA: DATA:
SURFACE LEAK -OFF PRESSURE FROM FORMATION FORMAT ION STRENGTH TEST
(A)
65
bar
DRILLING FLUID DENSITY AT TEST
(B)
1,30
kg/l
MAX. ALLOWABLE DRILLING FLUID DENSITY = (A) x 10.2 1,92 = (C) (B) + SHOE T.V. DEPTH
kg/l
C URR ENT DRILLING FLUID: FLUID:
DENSITY
1,44
kg/l
INITIAL INIT IAL MAASP =
((C) - Current Density) 10.2
x Shoe TVD
=
50
C AS ING SHO E DATA: DATA:
SIZE
PUMP NO. 1 DISPL.
13,89
PUMP NO. 2 DISPL. l / stroke
13,89
in
M. DEPTH
1066
m
T.V. DEPTH
1066
m
l / stroke
RESSURE OSS RESSURE [bar] (PL) DYNAMIC P L
13 3/8”
HOLE DATA:
Well Control Manual
Rev 1.01, June 2010
Kill Sheet Wait and Weight Method Page 2. PAGE 2 OF 2
International Well Control Forum
DATE :
Surface BOP Kill Sheet - Vertical Vertical Well (Metric/Bar) (Metric/Bar)
NAME :
KICK DATA : SIDPP KILL FLUID DENSITY
KMD INITIAL CIRCULATING PRESSURE ICP
36
FCP
(J) = ICP - FCP
49
SICP
CURRENT DRILLING FLUID DENSITY ......1,44...........
2400
PIT GAIN
litres
SIDPP x 10.2 10.2
+
36 x 10,2 2438
+
bar
TVD ....1,59.... kg / l
=
DYNAMIC PRESSURE LOSS + SIDPP ...36...... + ....36......... =
72 bar ...............
KILL FLUID DENSITY
FINAL CIRCULATING PRESSURE
bar
CURRENT DRILLING FLUID DENSITY
1,59 1,44
x DYNAMIC PRESSURE PRESSURE LOSS LOSS
36 x .. ................. ............... = 32
Bar
40 bar ............... (J) x 100 --.--------(E)
=
2
Bar/100 strokes
Well Control Manual
Rev 1.01, June 2010
9 Appendix 2: Shallow Gas Requirements 9.1
Introduction Shallow gas is considered to be gas that is encountered in a well, normally near the surface, which cannot be closed in as the casing scheme has not yet reached a stage where normal BOP protection can be installed. Shallow gas can be a hazard in the following operations:
rig installation
conductor driving
top hole drilling.
An understanding of all applicable procedures relating to the avoidance of a shallow gas influx and the application of sound drilling practices are the most important factors preventing shallow gas incidents. Whilst the avoidance of drilling in known shallow gas areas is the primary mitigation of risk and the Operator’s responsibility; the presence of shallow gas cannot be ruled out in many cases and certain operational precautions are required. This appendix is designed to serve as a guide for all parties concerned with equipment, well planning and operations. This section gives guidance regarding various operational aspects of top hole drilling and precautions that should be taken at the rigsite. Guidance on the selection of diverter equipment is is included in section 3.2 section 3.2 of this manual. Drilling small pilot holes for shallow gas investigation is considered an acceptable and reliable method of shallow gas detection and problem mitigation and should be discussed at the pre-ops
Well Control Manual
9.2.1
Rev 1.01, June 2010
Well Planning Considerations During pre-spud meetings for exploration, appraisal or other wells falling into the categories described above, KCA D EUTAG personnel should always enquire about the risks of shallow gas and proposed mitigation procedures. If there is a possibility of shallow gas and a pilot hole is proposed this should be planned to be evaluated by:
9.3
monitoring gas readings at flowline
evaluating cuttings (mud logging)
logging the open hole for hydrocarbons (wireline logging or LWD )
Shallow Gas Kick Prevention A shallow gas kick may be encountered as a result of the following:
drilling into overpressured shallow gas
loss of primary well control
drilling into a producing well
Overpressured shallow gas kicks are difficult to avoid once overpressured gas zones have been penetrated. The well cannot be closed in and the only alternative is to divert the flow until it subsides or until attempts to kill the well dynamically are successful. Meanwhile steps should be taken to prepare for evacuation of the rig To minimise the loss of primary well control, each rig must prepare shallow gas procedures specific to each rig.
Well Control Manual
9.4
Rev 1.01, June 2010
Equipment Selection The equipment selection and specification criteria for Diverter systems is included in section 3.2 of this manual.
9.5
Shallow Gas Drilling Practices
9.5.1
Operational Planning Prior to commencing operations the plans are to be developed and drills conducted that consider the following.
Ensuring the personnel on the rig floor and in in the immediate immediate vicinity vicinity are minimised.
Putting in in place place detailed plans for monitoring during drilling, drilling, i.e. a bubble watchers. watchers.
9.5.2
Putting in place detailed plans for actions actions in the event of shallow shallow gas, there are clear actions to take and who takes these decisions. Carrying out drills to test response times and ensure individual responsibilities are clear such as winching off location. Ensuring standby vessels are briefed, aware and stand off up wind.
Shallow Gas Drills Shallow Gas drills must be performed at the start of each shift when the possibility of shallow gas has been identified in the Drilling Programme.
9.5.3
Pilot Hole Drilling Practices The pilot hole drilling method provides limited additional blowout protection due to increased
Well Control Manual
9.5.4
Rev 1.01, June 2010
Top Hole Drilling Practices The more common drilling practices which are applicable for top hole drilling in general, and diverter drilling, in particular are summarised below. (a)
Penetration rate should be restricted and particular care should be taken to avoid an excessive build-up of solids in the hole which could cause formation breakdown and losses. Drilling with heavier mud returns could also obscure indications of drilling through higher pressured formations. The well may kick during circulating the hole clean. Restricted drilling rates also minimise the penetration into the gas bearing formation which in turn minimises the influx rate. An excessive drilling rate through a formation containing gas reduces the hydrostatic head of the drilling fluid, which may eventually result in a flowing well.
(b)
Every effort must be made to minimise the possibility of swabbing. Pumping out of hole at optimum circulating rates is recommended for all upward pipe movements (e.g. making connections connections and tripping). Especially in larger hole sizes (i.e. larger than 12-1/4 inch) it is important to check that the circulation rate is sufficiently high and the pulling speed sufficiently low to ensure that no swabbing will take place. A Top Drive System or Circulating Drillpipe Elevator (Regan Fast Shut-Off Coupling) will facilitate efficient pumping out of hole operations.
(c)
The drilling assembly must be as short as possible and the use of stabilisers should be minimised as they will increase the risk of swabbing.
(d)
All gas detection equipment must be properly calibrated and functioning and a differential flowmeter used. Accurate measurement and control of drilling fluid is most critical in order to detect gas as early as possible.
Well Control Manual
Rev 1.01, June 2010
If tripping out with an exposed shallow gas zone the following precautions must be followed after performing a flow check and lining up the trip tank:
9.5.6
The Drilling Supervisor must be on the drillfloor for the whole trip Pump out of the hole, circulating out singles for a Kelly rig, as per appropriate drilling practices, until at least three joints above the gas zone. Whilst handling the bha the hole must continue to be kept full and the fill-up volume monitored closely
Follow-Up from pilot hole Logging MWD logging is the preferred method of evaluation vs. wireline logs since early detection obviously enhances the safety of the operation. If, from the logging results of a pilot hole, hydrocarbons are indicated it may be possible to establish the the saturation, porosity and permeability of the hydrocarbon-bearing zone(s), and its estimated flow capacity. Depending on these results, one of the following options may be carried out: (a)
open up the hole and set casing at the initially programmed depth;
(b)
plug back to above hydrocarbons, open up the hole and set casing (if the resulting changes in casing design are acceptable, otherwise the well should be abandoned);
(c)
abandon the well and shift to a location which is expected to by-pass the shallow hydrocarbon accumulation.
If it is not certain whether hydrocarbons have been penetrated at the bottom of the hole, the
Well Control Manual
9.6
Actions to be taken in the event of a Shallow Gas Kick
9.6.1
Shallow Gas Kick Whilst Tripping
Rev 1.01, June 2010
If a kick is experienced whilst tripping, the first option is to pump all available kill mud as soon as possible in an attempt to dynamically kill the well as per section 9.6.2 below. If successful and flow has stopped, the string should be run back to bottom immediately and the well circulated. If the dynamic kill attempt with kill mud is unsuccessful, an attempt may be made to strip the string back to bottom, depending on the severity and type of flow. 9.6.2
Shallow Gas Kick Whilst Drilling Procedures for diverter operation vary depending on the type of rig and the area in which the well is being drilled. Following are general guidelines for use of the diverter system in controlling a kick: 1.
At first sign of flow or improper hole fill up, pick up the drill string to clear the kelly sub (or the tool joint if equipped with a top drive). Do not turn off the mud pump.
2.
Advise drill floor and service service personnel of potential for drilling drilling fluid discharge from diverter vent line(s) and annular sealing device leakage.
3.
Open the diverter vent line(s) considering wind direction.
4.
Close the diverter diverter packer and the shale shaker / mud return line valve.
5.
Line up both pumps into the tank containing weighted mud and attempt a dynamic kill as per the following steps and section 9.6.3 section 9.6.3 below.
Well Control Manual
Rev 1.01, June 2010
have kill mud of at least the pilot hole content premixed (at recommended 0.12 sg heavier than original mud) and stored in such a way that it can be pumped immediately at maximum rate The dynamic kill attempt is described below. At first sign of flow, the following action is required: (a)
pump mud immediately at maximum pump rate
(b)
open diverter valve(s) and close diverter element (accomplished on a single actuator)
(c)
if the well continues to flow, pump heavier mud at maximum pump rate.
(d)
if the well still continues to flow after the heavier mud has been pumped, carry on pumping mud at maximum rate. When running out of mud, change over to water. Do not reduce the pump speed.
At this stage, the drilling location may need to be abandoned, dep ending on the severity and type of flow and the condition of the diverter equipment. However should a risk assessment deem it practicable and safe, further dynamic kill attempts may be made as follows: (a)
prepare another batch of heavier mud whilst pumping mud or water at maximum rate (use mud which is 0,25 sg heavier than the original mud weight).
(b)
pump heavy mud at maximum rate.
(c)
repeat sequence if dynamic killing is still unsuccessful, but do not use excessive mud weight which could result in formation breakdown.
Note: The procedure for handling a shallow gas kick with a diverter system is also given in the form of decision trees in Figure in Figure 9-1 below. If a dynamic kill is unsuccessful (or not attempted) the well must continue to be diverted until it
Well Control Manual
Rev 1.01, June 2010
Text refe refers rs to : Life Life First, First, Blow-Ou Blow-Outt Secon Second d. Note Text When When runn running ing out of Mud , change change over over to W at at er er . D o n ot ot c ha ha ng ng e P um um p S pe pe ed ed
At first sign of flow , pump mud immediately immediately at maximum pump rate. Preferably Preferably the proposed proposed kill rate
Open Open diverte diverterr valve valve (s) and close diverter elements
NO Well Well continu continues es to flow flow excessi excessivel vely y ? Activate Blow -out Emergency Procedure Evacuate non -essential personnel Abandon location as soon as diverter system fails Pump Pump (0.12 (0.12 SG ) heavie heavierr mud at maximum maximum rate rate Circul Circulate ate bottom bottoms s up and and check mud returns
Well Well continu continues es to flow flow excessi excessivel vely y ?
NO Increase mud weight
Well Control Manual
Rev 1.01, June 2010
10 Appendix 3: Conversions Factors and Formulae 10.1
Conversion Factors DEPTH
Feet
x 0.3048 to give Metres (m)
Metres
x 3.2808 to give Feet (ft)
(U.S.) Gallon
x 0.003785 to give Cubic Metres (m3)
(U.S.) Barrel
x 0. 1590 to give Cubic Metres (m3)
Cubic Metre
x
PSI
x 6.895 to give Kilo Pascals (kPa)
kPA
x 0.14503 to give Pounds per Square Inch (psi)
Kg/cm
x 98.1 to give Kilo Pascals (kPa)
Bar
x 100 to give Kilo Pascals (kPa)
PPG
x 119.8 to give Kilogram per Cubic Metre(Kg/rn3)
Kg/m3
x 0.00835 to give (Pounds per Gallon)
ANNULAR
Feet/Minute
x 0.3048 to give Metres per Minute (m/min)
VELOCITY
Metres/Minute
x 3.2808 to give Feel per Minute (ft/min)
VOLUME
PRESSURE
MUD WEIGHT
6.2905 to give Barrel (U.S.)
Well Control Manual
10.2
Rev 1.01, June 2010
Formulae - SI
Drilling Fluid Density[kg/m 3 ]
1.
PRESSURE GRADIENT [kPa/m]
=
2.
DRILLING FLUID DENSITY [kg/m³] DENSITY [kg/m³]
=
3.
HYDROSTATIC PRESSURE [kPa]
=
4.
FORMATION PRESSURE [kPa]
=
5.
EQUIVALENT DRILLING FLUID DENSITY [kg/m³]
=
6.
PUMP OUTPUT [m³/min]
=
Pump Output [m³/stk] x Pump Speed [spm]
7.
ANNULAR VELOCITY [m/min]
=
3 Pump Output [m / min] min] 3 Annular Annular Volume Volume [m / m]
8.
INITIAL CIRCULATING PRESSURE [kPa]
=
SCR or PL [kPa] + SIDPP [kPa]
9.
FINAL CIRCULATING PRESSURE [kPa]
=
10.
KILL FLUID DENSITY [kg/m³]
=
11.
SHUT IN CASING PRESSURE [kPa] =
102 Pressure Gradient [kPa/m] x 102 3 Drilling Fluid Density Density [kg / m ] 102
x True Vertical Depth [m]
Hydrostatic Pressure In Drill String [kPa] + SIDPP [kPa] Pressure [kPa] x 102 True Vertical Depth [m]
3 SCR or PL [kPa] [kPa] x Kill Fluid Density Density [kg / m ] 3 Original Original Drilling Fluid Fluid Density Density [kg / m ] SIDPP [kPa] x 102 TVD [m]
+ Original Drilling Fluid Density [kg/m³]
{(Drilling Fluid Grad [kPa/m] - Influx Grad [kPa/m]) x Influx TVD Height [m]} + SIDPP [kPa]
Appendix 3 Conversion Factors and Formulae
Page 133 of 142
Well Control Manual
12.
EQUIVALENT CIRCULATION DENSITY [kg/m³]
=
13.
HEIGHT OF INFLUX ALONG HOLE [m]
=
14.
GRADIENT OF INFLUX [kPa/m]
=
15.
TRIP MARGIN/SAFETY FACTOR [kg/m³]
=
16.
NEW PUMP PRESSURE WITH NEW PUMP STROKES [kPa]
17.
MAX. ALLOWABLE DRILLING FLUID DENSITY [kg/m³]
=
Annular Annular Pressure Pressure Loss [kPa] [kPa] x 102 102 TVD [m]
3 Drilling Fluid Density Density [kg / m ] 102 Safety Margin [kPa] x 102 TVD [m]
=
=
19.
BARYTE TO RAISE DRILLING FLUID DENSITY [kg/m³]
=
20.
PERCOLATION RATE [m/hr]
=
-
SICP [kPa] - SIDPP [kPa] Influx TVD Height [m]
+ Drilling Fluid Density [kg/m³]
New SPM Old SPM
Current Pressure [kPa] x
Casing Shoe TVD [m]
NEW MAASP AFTER KILL [kPa]
+ Original Drilling Fluid Density [kg/m³]
3 Kick Size [m ] 3 Annular Annular Volume Volume [m / m]
Surface Surface leak leak - off [kPa] [kPa] x 102 102
18.
Rev 1.01, June 2010
2 (only approximate !)
+ Test Drilling Fluid Density [kg/m³]
3 3 Max. Allow. Drill Fluid Fluid Density Density [kg [kg / m ] - Kill Fluid Fluid Density Density [kg/ m ] 102
) x Shoe TVD [m]
3 3 (Kill Fluid Density Density [kg / m ] - Original Original Drill Drill Fluid Density Density [kg [kg / m ]) x 4200 3 4200 4200 - Kill Fluid Fluid Dens Density ity [kg [kg / m ] Increase Increase in Drill Pipe Pressure Pressure [kPa / hr] x 102 3 Drilling Drilling Fluid Density Density [kg / m ]
Appendix 3 Conversion Factors and Formulae
Page 134 of 142
Well Control Manual
=
P1 V1 = P2 V2
Rev 1.01, June 2010
P1 x V1 V2
V = 2
P x V 1 1
21.
BOYLE-GAY LUSAC LAW:
22.
PRESSURE DROP PER MT. TRIPPING DRY PIPE [kPa/m] =
3 3 Drilling Fluid Density Density [kg [kg / m ] x Metal Displ [m / m] 3 3 Casing Capacity [m / m] - Metal Metal Displ Displ [m / m] x 102
23.
PRESSURE DROP PER MT. TRIPPING WET PIPE [kPa/m] =
3 3 3 Drilling Fluid Density Density [kg / m ] x (Metal Displ [m / m] + Pipe Pipe Capa Capacity city [m / m]) m]) 3 Annular Annular Capacity Capacity [m / m] x 102
24.
LEVEL DROP FOR POOH DRILL COLLARS [m]
=
3 Length of Drill Collars [m] x Metal Displ [m / m] 3 Casing Capacity [m / m]
25.
PIPE TO PULL BEFORE WELL STARTS TO FLOW [m]
=
3 3 Overbalance [kPa] x (Casing Capacity [m / m] - Metal Metal Displ Displ [m / m]) x 102 3 3 Drilling Fluid Density Density [kg/ m ] x Pipe Displ [m / m]
26.
VOLUME TO BLEED TO MAINTAIN BHP [m³]
=
P2 =
P 2
Increase in Pressure [kPa] x OriginalKick Volume[m3 ] Formationincrease [kPa] - Increase in Pressure [kPa]
Appendix 3 Conversion Factors and Formulae
Page 135 of 142
Well Control Manual
10.3
Rev 1.01, June 2010
Formulae - Field Units
1.
PRESSURE GRADIENT [psi/ft]
=
2.
DRILLING FLUID DENSITY [ppg] DENSITY [ppg]
=
3.
HYDROSTATIC PRESSURE [psi]
=
Drilling Fluid Density [ppg] x 0.052 x True Vertical Depth [ft]
4.
FORMATION PRESSURE [psi]
=
Hydrostatic Pressure In Drill String [psi] + SIDPP [psi]
5.
EQUIVALENT DRILLING FLUID DENSITY [ppg]
=
6.
PUMP OUTPUT [bbl/min]
=
7.
ANNULAR VELOCITY [ft/min]
=
8.
INITIAL CIRCULATING PRESSURE [psi]
=
9.
FINAL CIRCULATING PRESSURE [psi]
=
10.
KILL FLUID DENSITY [ppg]
11.
SHUT IN CASING PRESSURE [psi]
12.
EQUIVALENT CIRCULATION DENSITY [ppg]
=
Drilling Fluid Density [ppg] x 0.052 Pressure Pressure Gradient Gradient [psi [psi / ft] 0.052
Pressure [psi] True Vertical Depth [ft] x 0.052 Pump Output [bbls/stk] x Pump Speed [spm] Pump Output [bbls / min] Annular Annular Volume Volume [bbls / ft] SCR or PL [psi] + SIDPP [psi] SCR or PL [psi] x Kill Fluid Density [ppg] Original Drilling Fluid Density [ppg] SIDPP [psi]
TVD [ft] x 0.052
+ Original Drilling Fluid Density [ppg]
= {(Drilling Fluid Grad [psi/ft] - Influx Grad [psi/ft]) x Influx TVD Height [ft]} + SIDPP [psi] =
Annular Annular Pressure Pressure Loss [psi] TVD [ft] x 0.052
Appendix 3 Conversion Factors and Formulae
+ Original Drilling Fluid Density [ppg]
Page 136 of 142
Well Control Manual
13.
HEIGHT OF INFLUX ALONG HOLE [ft]
=
14.
GRADIENT OF INFLUX [psi/ft]
=
15.
TRIP MARGIN/SAFETY FACTOR [ppg]
=
16.
NEW PUMP PRESSURE WITH NEW PUMP STROKES [psi] =
17.
MAX. ALLOWABLE DRILLING FLUID DENSITY [ppg]
=
18. [ft]
NEW MAASP AFTER KILL [psi]
=
19.
BARYTE TO RAISE DRILLING FLUID DENSITY [lbs/bbl]
=
20.
PERCOLATION RATE [ft/hr]
=
21.
BOYLE-GAY LUSAC LAW:
=
22.
PRESSURE DROP PER FT. TRIPPING DRY PIPE [psi/ft]
=
Rev 1.01, June 2010
Kick Size [bbls] Annular Annular Volume Volume [bbls / ft]
(Drilling Fluid Density [ppg] x 0.052) Safety Margin [psi] TVD [ft] x 0.052
SICP [psi] - SIDPP [psi] Influx TVD Height [ft]
+ Drilling Fluid Density [ppg]
New SPM Current Pressure [psi] x Old SPM Surface Surface Leak - off [psi] Shoe TVD [ft] x 0.052
2 (only approximate!)
+ Test Drilling Fluid Density [ppg]
(Max. Allow. Drill. Fluid Density [ppg] - Kill Fluid Density [ppg]) x 0.052 x Shoe TVD
(Kill Fluid Density Density [ppg] - Original Drill Fluid Density [ppg]) x 1500 35.8 - Kill Fluid Fluid Density Density [ppg] [ppg] Increase Increase in Drill Pipe Pressu Pressure re [psi / hr] Drilling Fluid Density [ppg] x 0.052
P1 V1 = P2 V2
P = 2
P x V 1 1 V 2
V2 =
P1 x V1 P 2
Drilling Fluid Fluid Density Density [ppg] x 0.052 x Metal Metal Displ [bbls [bbls / ft] Casing Casing Capaci Capacity ty [bbls [bbls / ft] - Metal Metal Disp Displl [bbls [bbls / ft]
Appendix 3 Conversion Factors and Formulae
Page 137 of 142
Well Control Manual
23.
PRESSURE DROP PER FT. TRIPPING WET PIPE [psi/ft]
=
24.
LEVEL DROP FOR POOH DRILL COLLARS (DRY) [ft]
=
25.
PIPE TO PULL BEFORE WELL STARTS TO FLOW [ft]
=
26.
VOLUME TO BLEED TO MAINTAIN BHP [bbls]
=
Rev 1.01, June 2010
Drilling Fluid Density Density [ppg] [ppg] x 0.052 0.052 x (Metal Displ [bbls [bbls / ft] + Pipe Capac Capacity ity [bbls [bbls / ft]) Annular Annular Capacity Capacity [bbls [bbls / ft] Length Length of Drill Collars Collars [ft] x Metal Metal Displ [bbls [bbls / ft] Casing Casing Capaci Capacity ty [bbls [bbls / ft] Overbalance Overbalance [psi] x (Casing (Casing Capacity Capacity [bbls [bbls / ft] - Metal Displ [bbls / ft]) Drilling Fluid Fluid Density Density [ppg] x 0.052 0.052 x Metal Displ Displ [bbls / ft] Increase in Pressure [psi] x OriginalKick Volume[bbls] FormationPressure [psi] - Increase in Pressure [psi]
Appendix 3 Conversion Factors and Formulae
Page 138 of 142
Well Control Manual
10.4
1.
Rev 1.01, June 2010
Formulae - Bar Litre
PRESSURE GRADIENT [bar/m]
=
Drilling Fluid Density [kg/l] x 0.0981
Or PRESSURE GRADIENT [bar/10m]
=
Drilling Fluid Density [kg/l] x 0.981
DRILLING FLUID DENSITY [kg/l] DENSITY [kg/l]
=
Or DRILLING FLUID DENSITY [kg/l] DENSITY [kg/l]
=
3.
HYDROSTATIC PRESSURE [bar]
=
Drilling Fluid Density [kg/l] x 0.0981 x True Vertical Depth [m]
4.
FORMATION PRESSURE [bar]
=
Hydrostatic Pressure In Drill String [bar] + SIDPP [bar]
5.
EQUIVALENT DRILLING FLUID DENSITY [kg/l]
6.
PUMP OUTPUT [liter/min]
=
7.
ANNULAR VELOCITY [m/min]
=
or ANNULAR VELOCITY [m/sec]
=
2.
=
8.
INITIAL CIRCULATING PRESSURE [bar]
=
9.
FINAL CIRCULATING PRESSURE [bar]
=
Pressure Pressure Gradien Gradientt [bar / 10m] 0.981 Pressure Pressure Gradient Gradient [bar [bar / m] 0.0981
Pressure [bar] True Vertical Depth [m] x 0.0981 Pump Output [litter/stk] x Pump Speed [spm]
Pump Output Output [litre/ min] Annular Annular Volume Volume [litre / m] Pump Pump Output Output [litre / min] Annular Annular Volume Volume [litre / m] x 60
SCR or PL [bar] + SIDPP [bar]
SCR or PL [bar] [bar] x Kill Fluid Density Density [kg / l] Original Original Drilling Fluid Fluid Density [kg [kg / l]
Appendix 3 Conversion Factors and Formulae
Page 139 of 142
Well Control Manual
SIDPP [bar]
Rev 1.01, June 2010
10.
KILL FLUID DENSITY [kg/l]
=
11.
SHUT IN CASING PRESSURE [bar]
=
SHUT IN CASING PRESSURE [bar] PRESSURE [bar]
=
12.
EQUIVALENT CIRCULATION DENSITY [kg/l]
=
13.
HEIGHT OF INFLUX ALONG HOLE [m]
=
14.
GRADIENT OF INFLUX [bar/m]
=
Drilling Fluid Density [kg/l] x 0.0981 - {
or
GRADIENT OF INFLUX [bar/10m]
=
Drilling Fluid Density [kg/l] x 0.981 - {
15.
TRIP MARGIN/SAFETY MARGIN/SAFETY FACTOR [kg/l]
=
16.
NEW PUMP PRESSURE WITH NEW PUMP STROKES [bar]
17.
MAX. ALLOWABLE DRILLING FLUID DENSITY [kg/l]
18.
NEW MAASP AFTER KILL [bar]
or
=
TVD [m] x 0.0981
+ Original Drilling Fluid Density [kg/l]
Drill Drill Fluid Fluid Grad Grad [bar [bar / 10m] 10m] - Influx Influx Grad Grad [bar [bar / 10m] 10m] 10
x Influx TVD Height [m] + SIDPP [bar]
Drill Fluid Grad [bar/m] - Influx Grad [bar/m] x Influx TVD Height [m] + SIDPP [bar]
Annular Annular Pressure Pressure Loss [bar] [bar] TVD [m] x 0.0981
+ Original Drilling Fluid Density [kg/l]
Kick Size [litre] Annular Annular Volume Volume [litre / m]
Safety Margin [bar] TVD [m] x 0.0981
=
Influx TVD Height [m]
SICP [bar] - SIDPP [bar] Influx TVD Height [m]
}
x 10 }
+ Drilling Fluid Density [kg/l]
Current Pressure [bar] x Surfac Surface e leak - off [bar] [bar]
Casing Shoe TVD [m] x 0.0981
=
SICP [bar] - SIDPP [bar]
New SPM Old SPM
2 (only approximate !)
+ Test Drilling Fluid Density [kg/l]
{Max. Allow. Drill Fluid Density [kg/l] - Kill Fluid Density [kg/l]} x 0.0981 x Shoe TVD [m]
Appendix 3 Conversion Factors and Formulae
Page 140 of 142
Well Control Manual
19.
BARYTE TO RAISE DRILLING FLUID DENSITY [kg/l]
=
3
Or BARYTE TO RAISE DRILLING FLUID DENSITY [kg/m DENSITY [kg/m ]
=
20.
PERCOLATION RATE [m/hr]
=
21.
BOYLE-GAY LUSAC LAW:
=
22.
PRESSURE DROP PER M. TRIPPING DRY PIPE [bar/m]
=
or PRESSURE DROP DROP PER M. TRIPPING DRY PIPE[bar/m] PIPE [bar/m]
=
23.
PRESSURE DROP PER M. TRIPPING WET PIPE [bar/m]
=
or PRESSURE DROP DROP PER M. TRIPPING WET PIPE [bar/m]
=
24.
LEVEL DROP FOR POOH DRILL COLLARS [m]
=
Rev 1.01, June 2010
(KillFluidDensity [kg/l] - OriginalDrillFluidDensity [kg/l] ) x 4.2 4.2 - KillFluidDensity [kg/l] (KillFluidDensity [kg/l] - OriginalDrillFluidDensity [kg/l] ) x 4200 4.2 - KillFluidDensity [kg/l]
Increase Increase in Drill Pipe Pressu Pressure re [bar / hr] Drilling Fluid Fluid Density Density [kg / l] x 0.0981 P1 V1 = P2 V2
P2 =
P x V 1 1 V2
Drilling Fluid Density Density [kg / l] x Metal Metal Displ Displ [l / m] Casing Casing Capaci Capacity ty [l[l / m] - Metal Metal Displ Displ [l / m]
V = 2
P x V 1 1 P 2
x 0.0981
Drilling Fluid Gradient Gradient [bar [bar / m] x Metal Displ [l / m] Casing Casing Capaci Capacity ty [l[l / m] - Metal Metal Disp Displl [l / m]
Drillin Drilling g Fluid Fluid Densi Density ty [kg/ l] x (Metal (Metal Displ Displ [l/ m] + Pipe Pipe Capaci Capacity ty [l / m]) x 0.0981 Annular Annular Capacity Capacity [l / m] Drillin Drilling g Fluid Fluid Gradi Gradient ent [bar [bar / m] x (Meta (Metall Displ Displ [l / m] + Pipe Pipe Capaci Capacity ty [l / m]) Annular Annular Capacity Capacity [l / m]
Length Length of Drill Collars Collars [m] x Metal Displ [l / m] Casing Casing Capacity Capacity [l / m]
Appendix 3 Conversion Factors and Formulae
Page 141 of 142
Well Control Manual
25.
PIPE TO PULL BEFORE WELL STARTS TO FLOW [m]
=
Or PIPE TO PULL BEFORE WELL STARTS TO FLOW [m] =
26.
VOLUME TO BLEED TO MAINTAIN BHP [liter]
=
Rev 1.01, June 2010
Overbalanc Overbalance e [bar] [bar] x (Casing (Casing Capacity Capacity [l / m] - Metal Displ [l / m]) Drilling Fluid Density Density [kg / l] x Pipe Displ [l / m] x 0.0981 0.0981 Overbalance Overbalance [bar] x (Casing (Casing Capacity Capacity [l / m] - Metal Displ [l / m]) Drilling Fluid Gradient Gradient [bar [bar / m] x Pipe Displ [l / m]
Increase in Pressure [bar] x OriginalKick Volume[litre] FormationPressure [bar] - Increase in Pressure [bar]
Appendix 3 Conversion Factors and Formulae
Page 142 of 142
