HPHT Drilling Procedures

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The information contained in this document is provided as guidelines and should be used in conjunction with the kick procedures flowcharts to deal with specific well control problems.

These procedures basically apply to the hp section of an hp well, generally following the setting of the deep intermediate casing, (9.5/8" - 10.3/4").

1. INTRODUCTION

The need to maintain good communications cannot be over emphasised. For situations not covered by these procedures a plan/flowchart should be drawn up. It is vital that such a plan is thoroughly discussed and agreed by at least the OIM, Toolpusher and OWE offshore, and the SWE (operations), Rig Manager, and Head of Well Operations onshore.

Uncommon types of operation should be approached in small steps so that there is always a way back if a decision turns out to be incorrect. This can be summarised as:                 

STOP - OBSERVE - CONFIRM.

1.1 Definition of a HTHP Well

The current definition of high pressure or high temperature or both (HP/HT) wells is as follows: when the wellhead shut-in pressure exceeds 690 bars; the bottom hole static temperature exceeds 150°C.

1.2 Kick Tolerances

Ideally, during the design of the well, the base line is to satisfy the following minimum kick tolerance criteria for a hole of 8 3/8 inches and smaller:

  • 40 bbl for drilling
  • 20 bbl for tripping

However, in exceptional cases a revised low level minimum kick tolerance criterion of 25 bbl for drilling may have to be adopted.

1.3  Remark

The following aspects of HPHT pressure control have not been included in this document

  • Thermal effects on mud density.
  • Standard use of extended leak-off tests and the results thereof.
  • Mud density variations.
  • Surge/swab pressures.
  • Tripping volumetrics.

2. RIG EQUIPMENT REQUIREMENTS

2.1 Circulating Subs

(1) When running a core barrel, mud motor, or turbine, a circulating sub should always be included in the bottom hole assembly.

(2) The circulating sub should be dimensionally checked and also drifted with the tools that are expected to pass through it: setting ball, survey barrel, survey barrel spear socket, etc.

Remark: It is important to ensure that the circulating sub sleeve doesn't cause the survey barrel spear socket to unlatch from the barrel when being pulled back through the circulating sub. A method of getting round this particular problem is to place the Totco ring in a stabiliser directly below the circulating sub so that the top of the barrel sits above the sub. However, should it not be possible to retrieve the barrel for whatever reason, the fact that the circulating sub is straddled renders it inoperable.

(3) The circulating sub should be fitted with seals rated for high temperature.

(4) The HDIS should be drifted with the ball that will be used to shift the sleeve of the circulating sub.

2.2 High Temperature Rated Elastomers

The temperature limitations of BOP rams and annular preventers are detailed in Appendix 10.

Elastomers rated to high temperatures are required for the following; (in some cases 'standard' elastomers may be sufficiently rated):-

(1) Fixed and shear ram preventer packings and seals.

(2) Fail safe valve packings and seals.

(3) The lining of kill and choke line flexible hoses.

In accordance with Coflexip's own recommendations only Coflon lined Coflexip has a satisfactory rating with respect to product (eg: methane) compatibility at high temperatures.

(4) Kill and choke line stab connector lip seals.

(5) Packings and seals on choke manifold 15k valves.

(6) Bladders on choke manifold pressure transducers.

2.3 Choke Manifold

(1) Choke manifold valves and chokes intended to be operated under high pressure to be fitted with hydraulic actuators.

(2) Glycol injection points upstream of the chokes.

(3) A 250 psi pressure relief valve fitted to the buffer chamber on the choke manifold and venting to the overboard lines. This relief device when activated manually can be used as the relief device which protects the liquid seal in the mud-gas separator.

Remark: In certain circumstances, well control may require that displacement of the kick continues regardless of the capacity of the mud-gas separator to handle wellbore fluids. Overboard lines are therefore required to divert flow from the choke manifold and isolate the mud-gas separator. The pressure rating of the overboard lines should not be less than the rating of the buffer chamber of the choke manifold to which they are connected. Overboard lines are also used in the event that the pipe system downstream of the buffer chamber becomes inadvertently blocked; for instance plugged with hydrates.

The 250 psi setting is high enough to allow sufficient pressure drop between the buffer chamber and mud-gas separator to avoid premature actuation of the valve. Conversely, the 250 psi setting is low enough to protect the mud-gas separator itself from over-pressurisation in the event of blockage in the vent line and dip tube.

Furthermore, while controlling a gas kick, a considerable volume of gas is vented via the choke. The resulting near adiabatic expansion can yield severe low temperatures downstream of the choke. Consequently on some (non-Arctic) rigs, pipework downstream of the high pressure side of the choke manifold would have to be downgraded by a factor of 2.5, hence necessitating the need for a relief device.

2.4 Mud-Gas Separator

In accordance with HSE Safety Notice, there must be a means by which the mud-gas separator can be bypassed and isolated when approaching overload conditions or blockage(see 2.3 above).

An aspect of the mud-gas separator capacity is the rate at which gas can be vented when the seal is operating at its maximum pressure differential when the liquid seal contains only associated liquids from the hydrocarbon influx. "A gradient of 0.3 psi/ft should be assumed to determine the maximum pressure differential".

As such, a device is required to protect the liquid seal, (and thereby also prevent wellbore fluids being transmitted back to the mud system). The pressure setting of this device shall be based on the height of the liquid seal (ie:- 18 ft.) multiplied by 0.3 psi/ft., (ie:- 5.4 psi).It is acceptable to design for a higher mud seal gradient provided that fresh mud is continuously circulated either into the tank (in the case of a dip tube seal), or into the separator itself (in the case of a U-tube seal)

This bypass can be a fully automated device or simply a pressure induced alarm that triggers a procedure whereby the bypassing and isolation of the mud-gas separator is performed manually.

2.5 Instrumentation

  • Temperature upstream and downstream of choke.
  • Pressure upstream and downstream of choke.
  • Kill manifold pressure gauge.
  • Poor-boy mud-gas separator temperature.
  • Poor-boy mud-gas separator pressure.

2.6 High Pressure Well Killing Facilities

(1) 15K kill pump, (usually the cement unit).

The kill pump shall incorporate two triplex pumps, both with 15k fluid ends. At least one fluid end shall be fitted with liners and pistons rated to 15k, with additional sets held onboard as back-up. Because of the low volume rates required when cementing in the HPHT section it may be possible to dress both fluid ends with 15k liners and pistons. It need only be a consideration to install a remote control unit for the kill pump on the drillfloor.

The BOP kill line shall be permanently hooked up to the kill pump (cement unit). At least two valves shall separate the kill line from the cement unit, (in order to prevent any cement contamination of the kill line). Procedures shall be in place to flush the surface section of the kill line after every cement job.

(2) Dedicated high pressure (15K) kill manifold and high pressure (15K) kill (Coflexip) hose.

(3) High pressure kick single assembly to link the kill pump (cement unit) to the drillstring through the high pressure kill manifold and (Coflexip) hose.

2.7 Miscellaneous Equipment

  • Glycol injection pump.
  • Glycol feed storage tank.
  • Calibrated stripping tank.
  • Sufficient 15k IBOP's for the drilling stand, kick single assembly, and for stabbing etc.

3. PREPARATION

The following is a checklist of items to be actioned prior to entering the high pressure section.quipment & Materials

  • Personnel
  • Training

3.1 Equipment & Materials

Well/operation/rig specifics such as test pressures and mud volumes etc. are not detailed in this list. Refer also to Secondary Pressure Control/BOP Systems/Subsea Stacks.

  1. Fixed ram high temperature elastomers shall be installed in the BOP.
  2. High temperature seals shall be installed in the kill and choke lines.
  3. The BOP and associated well control equipment shall be pressure tested and accepted by the rig's certifying authority. The frequency of such certification shall be in accordance with the rig's certifying authority's requirements.
  4. The kill (cement) pump and manifold shall be pressure tested.
  5. The 15k kick single assembly shall be made up to the appropriate size/ weight/grade of drillpipe and pressure tested.
  6. The drilling stand complete with tested kelly cocks and saver-sub to be made up.
  7. The automatic MAASP control system shall be disconnected.
  8. All instruments and recorders shall be checked for calibration and cross checked for consistency between locations.
  9. Check calibration of returns flow indicator: (indicator to be upstream of outlet to trip-tank).
  10. Check calibration of all gas detectors.
  11. Check calibration of all H2S detectors.
  12. The hydrate suppressant (glycol) system shall be function tested.
  13. The kill (cement) pump remote control on the rig floor shall be function tested.
  14. Sufficient barite stocks to be onboard.
  15. Sufficient cement stocks to be onboard.
  16. Sufficient cement additives to be onboard.
  17. Sufficient LCM stocks to be onboard.
  18. Sufficient glycol stocks to be onboard.
  19. Volume of mud equivalent to hole volume to be prepared.
  20. Reserve mud to be prepared.
  21. Weighting-up rate (ie: psi/ft per 'x' bbls per hour) to be established
  22. Additional 15k IBOP's to be on board (for drilling stand and kick single assembly). Provision for the rapid installation of the stab-in IBOP should be provided.
  23. Additional H2S equipment as required to be onboard.
  24. High temperature magnetic single shot equipment to be onboard.
  25. Service company tools (especially the elastomeric content) such as jars, retrievable packers, and electric wireline logging instruments (including pipe-conveyed) should all be rated for high temperatures.
  26. Ensure that all downhole tools have been checked with respect to casing ID's (including allowance for tolerances).
  27. Check that the dart for use with the Hydril drop-in sub will pass through all ID's of the drillstring (including the IBOP's) and BHA components.
  28. Check that in the event of a power failure, the emergency generator has the capacity to allow well killing operations to continue.
  29. Check/test procedure/system for isolating mud-gas separator and venting wellbore fluids overboard.
  30. Check/test pressure relief valve system fitted to choke/kill manifold buffer tank for venting wellbore fluids overboard.
  31. Check/test system that changes direction of wellbore fluids being vented over-board.

Note: If prolonged top-drive problems necessitate drilling ahead with the kelly, a circulating elevator should be acquired for tripping operations.

3.2 Personnel

  1. Well Engineers should be assigned to the rig for the duration of the high pressure section.
  2. Two mud engineers should be assigned to the rig for the duration of the high pressure section.
  3. Mud logging crew should not contain any trainees, additional or otherwise.
  4. Personnel on board should be kept to a minimum.

3.3 Training

  1. All appropriate personnel to be proficient at well control drills (drilling and tripping) utilising the 'fast shut-in' method, strip drills, and H2S drills.
  2. All personnel to have received onsite H2S/BA refresher training.
  3. Company Well Engineers, Contractor Toolpushers, Night Toolpushers, Drillers, and Assistant Drillers should have attended an approved Volumetric Stripping Course and also a HPHT Course (e.g. Aberdeen Drilling School HPHT Course).

4 HPHT DRILLING PROCEDURESS

4.1 General

  1. The automatic MAASP control system shall not be used, and should be disconnected.
  2. The minimum barytes stock shall be 100 MT and the minimum cement stock shall be 80 MT. If stocks fall below this level operations will stop, therefore it is usual to maintain stocks far in excess of these minimum levels. Cement additive stocks shall also be maintained and if applicable shall include the appropriate level of weighting material (haematite).
  3. The mud mixing (weighing up rate) capability of the rig should be established. This information will assist in the planning of certain well control operations and may even impact on the choice of well control method.
  4. Pressures at slow circulating rates shall be established for the kill pump/kick single/choke line system.
  5. Circulation shall be broken through the kill and choke lines every twelve hours.

4.2 Drilling

Refer also to Section 4.9, 'Directional Control and Borehole Surveying'.

4.2.1 When drilling with a top drive, the composition of the drilling stand, (ie:-number of drillpipe joints and quantity/position of string IBOP's), varies between Operators and Drilling Contractors. Certain minimum requirements shall apply in all situations, and these will determine the configuration of the drilling stand on any particular rig.

These minimum requirements shall also apply when drilling with a kelly and therefore may necessitate the use of a 'mini' drilling stand below the kelly.

The minimum requirements are as follows:-

  • It should always be possible to disconnect the top drive yet leave the drillstring closed-in on one accessible string IBOP.

Similarly, it should always be possible to disconnect the kelly yet leave the drillstring closed-in on one accessible string IBOP.

A second IBOP can be installed once the top drive/kelly has been removed.

  • It should always be possible to remove the drilling stand or part thereof yet leave one accessible string IBOP in place in the drillstring.
  • It should always be possible to install the kick single assembly on a drillstring that is closed-in on at least one accessible string IBOP.
  • It should always be possible to land off.
  • It should not be possible for the drillstring to heave into 'bottom'.

4.2.2 No special equipment that restricts the drillstring ID shall be run in the bottom hole assembly, with the exceptions of the Totco ring, drilling jar, Hydril drop-in sub, and nozzles in the bit.

This is to limit the restrictions in the drillstring that would increase the chances of blockage occurring in the case that the pumping of LCM and/or cement is required to cure severe losses when entering the reservoir.

Note however that:-

  • The Hydril drop-in sub shall be placed above the heavy-weight drillpipe.
  • All nozzles shall be the maximum size possible for the particular bit in use. If the largest nozzles available are less than 18/32", contact Base. No nozzle holes shall be blanked off. (The use of nozzles is primarily to protect the nozzle orifices).
  • Teledrift is not classed as having a restrictive bore because of its large flow-by areas.

Refer also to Section 4.10, "Exemptions from HPHT Procedures", item 4.10.2, "Use of Thrusters / Motors / MWD's etc. in the HPHT Section".

4.2.3 The drilling rate should be restricted whereby the ROP does not exceed:

                                                               Lag Time (hrs) x ROP (ft/hr)     =     30 (ft)

Once drilling in a continuous reservoir where no further pressure seals are anticipated. this restriction can be lifted.

Remark: The reasoning behind the 30 ft. value is as follows:

When first drilling into the high pressure reservoir, it is possible that the formation pressure is only dynamically overbalanced. A flow check may not show the well to be flowing. Any influx entering the well during static conditions, (eg: with the pumps off during a connection), will show however once circulated to surface.

In order to prevent taking more than one influx in the case where the static overbalance is not present, bottoms-up has to reach surface and be checked for the presence of influx before stopping the pumps to add another joint of drillpipe, ie:- before starting to drill a further 30 ft. However, if the pumps have to be stopped, (to flowcheck for instance), prior to bottoms ups reaching surface, then the possibility exists to take a second influx. Therefore drilling shall not continue until bottoms up from the latter moment of stoppage has reached surface. This ensures that the annulus is influx free and also prevents the possibility of a third influx if the pumps have to be stopped yet again before the original connection bottoms up has reached surface.

Once drilling in a continuous reservoir and having established that a static overbalance exists at top reservoir, (together with the fact that the overbalance increases proportionally over the length of the reservoir), the reason for the restriction no longer exists and can therefore be lifted.

4.2.4. Where small kick tolerances are involved, gas coming out of cuttings can have a significant impact. For example:

- assuming 30% porosity in 1 cu.ft. of cuttings (2.6 ft. of 8.3/8" hole)

- mud weight of 0.945 psi/ft

- hole depth of 16,000 ft

- temperature regime of 40 deg. F at seabed and 350 deg. F at 16,000 ft

                will give approximately 20 bbls of gas at surface.

4.2.5 Drilling shall not continue if dynamic losses of greater than 10 bbls/hr persist.

4.3 Tripping

(1) Under no circumstances shall any string be pulled out of the hole if the hole is not in a stable condition, ie:- no losses and/or no flow.

However, this does not preclude pulling back a short distance, (eg:- to the shoe), in order to (for instance), set a cement/LCM plug.

(2) Prior to any trip out of the hole a ten stand wet check trip shall be made (pulled not pumped) in order to check for overbalance prior to finally coming out of the hole.

It is not allowable to pull less than ten stands even if the bottom of the drillstring has already reached the casing shoe.

If circulation is necessary to overcome hole problems encountered during this check trip, then the requirement still remains to check for overbalance by ensuring that the bottom of the drillstring has been pulled through the whole of the check trip interval.

Note:    On occasions it may be necessary to pull out after performing a leak-off test having drilled the shoetrack and 15 ft. of new formation. Provided that during the 15 ft. drilled there is no change in cutting lithology, drilling parameters (eg: torque) and gas readings, then it is not necessary to perform the ten stand check trip.

Refer also to Section 4.10, "Exemptions from HPHT Procedures", item 4.10.1, "Omission of Ten Stand Check Trip".

(3) During the actual trip out of the hole, the drillstring shall be pumped out at least until the bottom of the drillstring has reached the casing shoe. If a drilling liner has been installed, then the drillstring shall be pumped out at least until the bottom of the drillstring has reached the top of the drilling liner. (This is because in general, annular clearances are smaller).

In circumstances where only a marginal overbalance exists it may be necessary to pump all of the way out of the hole, ie: to the BOP.

(4) On check trips, no heavy pills (slugs) shall be pumped. No heavy pills should be pumped on any trip until the bottom of the drillstring has reached the casing shoe.

(5) If a survey is required using a MSS, drop the survey barrel after the flow check (negative) that follows circulating bottoms up after the check trip. The survey barrel shall not be recovered until the bottom of the drillstring has reached the casing shoe.

On round trips it is usual to recover the survey barrel when the BHA is at surface.

(6) On all trips out of the hole, a Hydril drop-in dart shall be pumped down. Where applicable, the dart will have to be dropped after retrieving the survey barrel at the shoe. It shall be checked to be in place by hopefully noting a slight pressure increase but at least ensuring that sufficient theoretical string contents have been pumped. Seating can be checked when retrieving the dart at surface.

(7) On all trips in and out of the hole, excessive trip speeds should be avoided in order to minimise surge and swab pressures to an acceptable level. The reduction in bottom hole pressure for the drillstring and mud properties in use shall be calculated.

(8) On all check trips and all trips out of the hole, the Contractor Toolpusher (Night Toolpusher) and Company OWE (or AOWE) shall both be present for at least the first 10 stands pumped/pulled. Furthermore, the Contractor Toolpusher (or Night Toolpusher) shall remain present for tripping out through the whole open hole section.

Under no circumstances shall a trip commence prior to the above personnel being present.

(9) If the hole indicates that swabbing is taking place but the well is not flowing, then the drillstring shall be run back to bottom and bottoms up circulated. Note however that when 75% of the annular contents have been circulated or as soon as signs of a reduction in mud weight or hydrocarbons are observed, then circulation shall continue over the choke manifold.

If any doubt exists at any time, bottoms up should be circulated out over the choke manifold. The riser should then be circulated to clean mud prior to opening the BOP's.

(10) All assemblies shall be checked carefully for wellbore contact (wellbore offset programme), because an undesirable effect of stuck pipe is that swabbing can occur while jarring.

Notwithstanding the items above, if indications are that the well will swab, the following options should be considered:-

  • Increasing the mud weight.
  • Pumping (not pulling) out the ten stands during the ten stand check trip.
  • Pumping out all of the way; (see item 3 above).
  • Using a heavier mud for tripping purposes.

4.4 Flow Checking During Drilling/Coring and Tripping

The duration of flow checks shall be 15 minutes and shall be taken:-

(1) Whenever a drilling break is observed, a flow check shall be carried out. If any doubt exists, circulate bottoms up with additional flowchecks at 50% and 75% of bottoms up.

(2) When check tripping and/or tripping out of the hole, regular flow checks shall be conducted as follows:-

(a) On bottom prior to pulling out.

(b) On a check trip after pulling 10 stands. If the bit will be inside the shoe when 10 stands have been pulled, flow check both at the shoe and after pulling the 10th stand.

(c) At reaching the casing shoe.

(d) At reaching the top of a drilling liner (if applicable).

(e) At a point halfway between the casing shoe and the BOP stack.

(f) At a point just before the top of the BHA (ie:- HWDP) reaches the BOP stack Rotating the drillstring during flowchecks should prevent gels developing and is a valuable anti-stick precaution.

4.5 Coring

When coring:-

  1. Only perforated core-barrels (ie: fitted with check-valve venting) should be used.
  2. The restricted drilling rate as detailed in Section 4.2.3 shall also apply, but can also be lifted in accordance with the same procedure.
  3. For all sizes, the length of core-barrel run on any one trip shall not exceed 90 ft.
  4. The tripping and flow checking procedures as detailed in Sections 4.3 and 4.4 respectively shall also apply during coring operations.
  5. The first core taken in the reservoir shall be in rotary mode. Thereafter, motor coring can be used but only in accordance with Section 4.10.2, "Use of Thrusters / Motors / MWD's etc. in the HPHT Section".

4.6 Running Casing/Liner

  1. The shoetrack of the casing set just above the HPHT section (usually the 9.5/8" - 10.3/4") and the shoetracks of all other casings/liners set in the HPHT section shall be magnetised.
  2. It is important to emphasise that overbalance must always be maintained at all stages whenever cementing a casing/liner especially under static conditions.

4.7 Pressure Testing of the BOP and Production Casing content

4.7.1 BOP Test Pressuress

In order to address some commonly asked questions, the following is a brief methodology for testing the BOP:-

(1) On the stump, test the BOP to its rated working pressures, typically 15k for the rams and failsafes, and 10k for the annular preventers.

(2) Whenever running the BOP, test the wellhead connector to its rated working pressure, usually 15k, and test the kill and choke lines to their rated working pressure, typically 15k. In cases of a 'split' BOP, test the LMRP connection to 10k.

(3) Whenever subsequently testing the BOP, test the rams and kill and choke lines to 1000 psi above the maximum anticipated closed-in surface pressure for the appropriate hole section. This pressure will be detailed in the drilling programme, (because in some cases it may not be possible to cater for the full 1000 psi margin). Test the annular preventers to 70% of their rated working pressure.

As a minimum requirement, subsequent pressure testing of the shear rams shall be carried out at after setting the casing just above the reservoir.

(4) Because the kick-single is an integral part of the well control equipment (in the HPHT section), it shall be included in the subsequent (14-day) pressure testing of the BOP from the start of the HPHT section.

4.7.2 Testing Frequency of the Production Casing

There is always scope to test the production casing more frequently than the 30 days drilling, especially if casing wear has been experienced, (section 3.6.1.3). The decision when to perform subsequent casing tests shall be advised by the Senior Well Engineer (operations) following consultation with the Head of Well Operations. Subsequent testing of the seal assembly will be based on the same frequency as the casing.

4.7.3 Use of Retrievable Test Packers

Pressure testing of the production casing involves the use of a retrievable packer in order to isolate/protect:-

  1. The shoetrack.
  2. The cement bond (usually to theoretical top of cement).
  3. first core as per standard HPHT procedures detailed herein. If there is no coring point as such, drill sufficiently into the reservoir to allow the formation pressure to be measured using electric wireline logging tools. Continue as per steps 3, 4, and 5 below.
  4. (2) Cut the first core in the reservoir section as per standard HPHT procedures detailed herein. Sufficient core must be cut to allow the formation pressure to be measured using electric wireline logging tools.
  5. (3) Establish the formation pressure using electric wireline logging tools and adjust the mudweight as necessary to give sufficient trip margin.
  6. (4) Offset well data must indicate that stacked reservoirs (varying pore pressure regimes) are no more than a remote possibility in the lithology column in question.
  7. (5) The well is stable, (ie:- no losses and/o
  8. A weaker casing in a combination string.

It may be necessary to make a scraper run, (for instance across a production packer interval). However, casing scrapers shall not be ran in the same string as a retrievable packer.

Severe loading forces are transmitted to the casing via the packer slips during testing, and so in order to test the integrity of the slip area in the all important upper section of the casing, it is necessary to perform the shallow test first so that the deeper test incorporates coverage of the shallow test slip area.

Taking into account casing specifications of a combination string and also the temperature considerations, it may be possible to use the same packer components for both the shallow and deep tests. However, the severity of the shallow test may make it prudent to pull the packer to surface in order to check its condition prior to running all the way in hole only to find it is unable to perform the deeper test.

4.8 Casing Wear

Casing wear should be minimised at the design stage by the use of smooth tooljoint hardfacing, optimum well path trajectory, and film forming muds.

At the design stage the estimated amount of casing wear should be evaluated using a wear model. The burst, collapse, axial and triaxial capacities of worn casing are calculated and compared to the anticipated loads. If worn casing will only have just sufficient strength to withstand the design loads, casing wear will have to be monitored during drilling.

It is essential that only smooth hardfacing is used and that it is flush with the body of the tooljoint. Also of prime importance is the need to minimalise drillstring rotary speed. In addition, tong marks need to be removed from tooljoints. (Reducing the drillstring rotary speed can have the added benefit of also reducing the ECD).

As mentioned in Section 4.9, a North Seeking Gyro is run in the casing prior to entering the reservoir. This is an opportune moment in the operation to consider running a Multi-Fingered Caliper Tool (MFCT). It is important to run the log immediately after the casing is cemented, ie: before the drillstring is ran/rotated in the casing. Such a log then forms the baseline to gauge any casing wear that may subsequently occur. Results from subsequent MFCT logs can also be used to verify design stage predictions.

When the casing is inspected onboard it is important to have the OD as well as the ID measured in order to aid wall thickness calculations.

One of, or a combination of the following criteria should be used as guidelines for when to run a baseline MFCT:-

  1. If in accordance with the Casing Design Guide casing wear needs to be monitored.
  2. If the well is deviated and casing wear areas have been predicted/verified (Software). Contact force should not exceed 2,200 lbs.
  3. If the angle of the BOP stack is greater than 1 deg.

Results of the casing wear log can be extrapolated and plotted against the casing burst line in order to determine on critical sections where any points of crisis occur.

There is a complicated geometrical interface between casing, wellhead, BOP/wellhead test tools, and wearbushings, and as a consequence wearbusing ID's were in some cases greater than the ID of the uppermost casing. Extended neck wearbushings with a smaller ID than the uppermost casing have now been developed and test tools have been re-designed accordingly.

Drillpipe protectors have been fitted retro-actively in response to metal particles in the returns. In order to establish a consistent approach to monitoring the quantity of metal returned, the parameter of grams per 1000 revolutions should be used by dividing the total weight of metal returned by the total number of revolutions of the drillstring and recorded (say) every two hours. A software can be used as a monitoring tool using actual details of metal recovered. The use of drillpipe protectors can be planned at the design stage; their use can also reduce torque and drag.

If returned cuttings do contain metal then the wearbushing should be periodically inspected to check (for instance) that its not the rig's position over the wellhead that may be giving rise to metal returns.

'Cansco' (or similar) non-rotating drillpipe protectors should be fitted in areas of casing wear derived from analysis (software), known areas of comparitive drillpipe wear, and the comparison of subsequent and baseline MFCT logs. The non-rotating type drillpipe protector overcomes the 'grinding wheel syndrome' associated with the traditional type of drillpipe protector. The protectors are usually fitted just above the tooljoint.

Remark: One of the reasons why drillpipe protectors are fitted just above the tooljoint is so that as the tooljoint just passes below the wearbushing, the protector, (which will still be in the wearbushing), will centralise the tooljoint, thereby keeping it off the casing wall.

It is important that a log is kept of where each drillpipe protector is fitted.

4.9 Directional Control and Borehole Surveying in Vertical Holes

In the Well Planning section of the Deviation document it states that no more than 500 ft. of unsurveyed open hole is permitted. This is especially important if above top reservoir. However, to be flexible, the (ideal) figure of 500 ft. can be extended at the discretion of the Rig Superintendent; for instance, in order to coincide with a bit trip after 600 ft. or thereabouts As per the instruction from UEOW/35 dated 09 Dec 92; future HPHT well programmes shall include a North Seeking Gyro in the casing prior to entering the reservoir.

Note that it is not within the scope of these procedures to discuss the cost/time implications of the various methods of borehole surveying.

4.9.1 Teledrift Tools

The use of the Teledrift tool as detailed by the flowchart carries two important qualifications, namely:-

(1) Because Teledrift only measures inclination, the horizontal displacement should be determined using a single azimuth heading and the Teledrift inclination readings. This will give the worst case scenario. The single azimuth heading can be taken from the last measured value.The tool uncertainty, (11 ft.per 1000 ft. for the range 0-10 deg.; 13 ft. per 1000 ft. for the range 10-20 deg.), for the particular depth should then be added to the horizontal displacement. This final displacement figure becomes the radius of the circle anywhere in which the position of the bottom of the hole could be located.

Remark: The tool uncertainties quoted above are the current levels of uncertainty for unknown tool codes for the associated inclinations.

If this estimated 'circle of uncertainty' indicates that the target could be missed, then the situation will have to be assessed in order to decide the most appropriate safe course of action by which the target can be penetrated; see 4.9.2.

(2) Another important aspect of the Teledrift tool is its limited range to a maximum inclination of 20 deg. Therefore in cases of higher inclinations an alternative method of measurement is required; see 4.9.2.

4.9.2 SDC Magnetic Single/Multi Shot

Scientific Drilling Control (SDC) can provide the following magnetic survey probe to measure inclination and azimuth:-

(1) The magnetic survey probe is ran through a side entry sub using a dedicated (conductor) wireline unit. Reduced circulation and string reciprocation is still possible.

(2) The magnetic survey probe diameter is 1.375/1.750" and maximum operating temperature is 260/600 deg.F respectively.

(3) The probe can be ran in tandem or ran singly in order to provide a surface readout option.The procedure for running the probe would be as follows:-

(a) Circulate bottoms up then flowcheck.

(b) Rig up to run probe, installing a kelly cock below the side entry sub.

(c) Run probe, take survey, then retrieve probe (circulating to avoid swabbing).

(d) Rig down.

4.10 Exemptions from HPHT Drilling Procedures

There are particular situations where it is acceptable to deviate from the standard HPHT procedures and details of these are given below. Other circumstances may arise necessitating other deviations and these should be agreed by the Head of Well Operations and/or the SWE (support), and be documented as (sequentially numbered) amendments to the drilling programme, endorsed by the SWE (operations), DOE, and Rig Manager.

4.10.1 Omission of the Ten Stand Check Trip

It is possible to omit the ten stand check trip, (ref: item 4.3.2) provided that:-

(1) The bottom of the well's position in the lithology column has been confirmed, (eg: by core/cuttings samples etc.).

(2) Pore pressure measurements at the top of all exposed reservoirs in the well indicate that an overbalance exists over the highest pore pressure value with the riser in place.

(3) The first trip out through the exposed reservoir was preceded by a ten stand check trip. (This proviso will have been satisfied because the first trip out would have been to run the formation testing tool, ie:- RFT/FMT).

(4) Offset well data must indicate that stacked reservoirs (varying pore pressure regimes) are no more than a remote possibility in the lithology column in question.

(5) The drillstring is pumped out of all open hole sections.

4.10.2 Use of Thrusters / Motors / MWD's etc. in the HPHT Section

It is acceptable to use thrusters/motors/MWD's and turbines etc., or have other similar string restrictions in the HPHT section but only in accordance with the following procedures.

  1. Drill to the coring point and take the first core as per standard HPHT procedures detailed herein. If there is no coring point as such, drill sufficiently into the reservoir to allow the formation pressure to be measured using electric wireline logging tools. Continue as per steps 3, 4, and 5 below.
  2. Cut the first core in the reservoir section as per standard HPHT procedures detailed herein. Sufficient core must be cut to allow the formation pressure to be measured using electric wireline logging tools.
  3. Establish the formation pressure using electric wireline logging tools and adjust the mudweight as necessary to give sufficient trip margin.
  4. Offset well data must indicate that stacked reservoirs (varying pore pressure regimes) are no more than a remote possibility in the lithology column in question.
  5. The well is stable, (ie:- no losses and/or gains).

4.11 Lessons Learnt

The items in this section are included because they are considered to be valuable learning points.

4.11.1 Drilling Ahead Without a Riser Margin

It is not always possible to achieve and/or maintain the levels of overbalance widely regarded as being minimal (ie:- 300 psi). In a loss situation it may not be possible to even cater for a riser margin.

However, closing the BOP when the riser is attached will entrap the pressure of the hydrostatic head of mud in the riser provided that the BOP does not subsequently leak.

The decision to drill ahead without a riser margin must be sanctioned by the Head of Well Operations. Similarly, the Head of Well Operations should be informed whenever errosion of the overbalance (ie:- change of programmed mudweight) occurs.

4.11.2 Measurement of Mud Weight

There may be instances when narrow well control margins exist, such as minimal overbalance, and that during such circumstances certain items take on greater significance. An error of mud weight measurement of 0.005 psi/ft at 18000 ft equates to 90 psi on bottom. As such, when determining mud weights:-

'Tru-Wate' mud balances should be used. A 'master' balance, accurately calibrated in town, should be kept onboard for the sole purpose of providing a comparator for the balances in daily use. The 'master' balance could also be used for particularly critical mud weight checks. Any calibration adjustments to the balances in daily use should be logged.

Adopt a standard method of measurement to eliminate any 'inconsistencies', human or otherwise.

4.11.3 MDT Log (Flushing RFT)

Where narrow well control margins exist, the gradient and volume of formation fluids being flushed into the well bore take on greater significance. The implications therefore of excessive continuous flushing should not be under estimated. As such, the decision to run the MDT tool must be authorised by the SWE (operations).

4.11.4 Heavy Weather

Heavy weather is not within the scope of these procedures. However, mention is made of a particular philosophy whereby a situation can start to escalate out of hand if one problem (eg: well control) is exacerbated by a further two, as it should be recognised that the second problem, namely the weather may be about to happen or is happening already. Therefore, decisions should always take into consideration potential interference from adverse weather.

5 HPHT WELL CONTROL PROCEDURESS

5.1 General

Certain items in this section have been included because they are considered to be valuable learning points:

(1) It should not be assumed that a well control problem will always fall into a particular text book category. Bullheading or an issue like exceeding MAASP have traditionally been seen as last resorts, but options such as these should be taken in context and not dismissed as a matter of course. The key issue is to recognise when the text book does not apply and act accordingly.(Similar sentiments are expressed in the introduction to EP89-1500).Refer also to section 5.3, "Bullheading".

(2) It should also not be assumed that there will always be sufficient warning (such as background gas) when in a transition zone. Offset wells prove this not always to be the case.

(3) When background gas reaches an arbitrary pre-agreed level (for instance 5%), all work permits shall be withdrawn and the standby boat notified accordingly. It is also usual to notify all on-shift personnel via the P.A. system of the situation.

(4) The 'fast shut in' method will be used throughout the high pressure section. As such, the valve immediately upstream of each choke shall be kept closed during all operations after cementing the 9.5/8" casing.

(5) Once a well is closed in following a kick:-

  • All work permits shall be withdrawn.
  • The following parties shall be informed:

- Standby boat

- Senior Well Engineer (operations)

- Rig Manager

- Emergency Co-ordinator (EC) as per the 'Emergency Response Procedures'.

The OIM will also have responsibilities about whom to inform (eg:-coastguard) in accordance with his own emergency procedures.

  • Crews should be mustered and all personnel to be informed of the status 

(6) During well killing operations, in order to prevent valves washing out when closing them, the choke should be closed first followed by the valve immediately upstream of the choke.

Should this valve fail, the next upstream valve should be closed. In all cases, the last valve to be closed will be the one furthest upstream, nearest to the BOP.

Wherever possible, in order to avoid washouts, valves should be equalised rather than opened/closed under a high differential pressure.

5.2 BOP Ram Configuration.

BOP ram configurations are specified in the document entitled "Subsea BOP Ram Configuration Instruction; Exploration & Appraisal Wells", which was prepared by UEOW/555, approved by the Head of Well Operations, and issued in March 1993. The document is included in these procedures as Appendix 10.1 and 10.2 and includes details of:-

(1) Temperature limitations of ram and annular preventers.

(2) Hang-off capacities of pipe and variable bore rams.

(3) Configuration of ram type preventers in the BOP primarily with respect to:-

  • Size, (tubular dependent).
  • Ram cavity position, (ie:- top, upper/lower middle, bottom).
  • Bottom hole static temperature (BHST).
  • Wellhead pressure.
  • Phase of the operation, (ie: drilling, testing).

Although not specified in the note, the position of the kill and choke lines is important, resulting in an overall configuration as follows:-

  • Upper annular
  • Lower annular
  • Upper pipe rams
  • Upper choke line
  • Shear rams
  • Upper kill line
  • Middle pipe rams
  • Lower choke line
  • Lower pipe rams
  • Lower kill line

5.3 Bullheading.

Bullheading has been used on wells because when starting to kill the well conventionally, the pressure response at surface was abnormal and therefore the control over the bottom hole pressure (to prevent further influx) was unreliable, and consequently, the contents of the annulus (ie: volume of gas) could not be ascertained.

Bullheading proved to be a viable method of well control because:-

  1. Due to an extended leak-off test having already established that the mud gradient used was lower than the fracture propagation gradient, it was known that the operation would not result in static losses.
  2. The open hole section was very short making it almost certain that the influx would be squeezed back into the same formation from where it had come.

Therefore, bullheading may be the preferred option for one or more of the following reasons:-

  1. As long as it is known that the 'bottom won't drop out of the hole'.
  2. To avoid getting hydrocarbons to surface, especially in cases where doubts exist about the contents/volumes in the annulus.
  3. If erratic surface pressures are experienced whereby it may not be possible to proceed with killing the well conventionally.
  4. If it has not been possible to strip-in all the way to bottom.
  5. If rapid pressure increases call for swift action.
  6. If the open hole section is short. However, much depends on the length and characteristics of the open hole section, if a situation is to be avoided whereby fluid is being bullheaded higher up the hole above the point where flow may still be occurring.

If it is decided to control the well by bullheading, it is usual to displace the drillstring contentsfirst followed by the annular contents. It is a good idea not to fully displace the drillstring contents so that some positive drillpipe pressure (Pdp) is retained. This will allow the downhole situation to be monitored while bullheading the annulus, thereby enabling losses/crossflow to be detected. Furthermore, when bullheading the annulus, it is advisable to over-displace the contents in order to ensure that any migrated influx is also returned to the formation.

6 HPHT KILL PROCEDURESS

During killing operations when landed off on the upper pipe rams, be aware of the temperature limitation of variable bore rams as detailed in Appendix 10.1.1 This factor may necessitate having to also close the middle pipe rams - and utilise the lower choke line.

6.1 Kick With Bit On Bottom - Drilling With a Top Drive.

When drilling the high pressure section, the requirements ofr a drilling stand are detailed in Section 4.2, item 1

When a kick is first detected, close in the well as soon as possible in the following way:-

(1) Pick up off bottom until the string IBOP is above the rotary table and the upper pipe rams can be closed below a tool joint. (This position should be determined before drilling commences and updated as required).

(2) Stop rotating, then stop the pumps.

(3) Close the upper annular preventer.

(4) Open the failsafe valves in the upper chokeline.

(5) Record time and initial closed-in drillpipe and annulus pressures.

(6) Close the upper (remote controlled IBOP).

Remark: This isolates the system downstream of the drillstring against the risk that the closed-in drillpipe pressure exceeds the setting of the mud pump relief valve, thereby allowing uncontrolled flow through the drillstring.

(7) Inform the Company Well Engineer and Contractor Toolpusher onboard.

(8) Install and test the kick single assembly as detailed in steps 'a' to 'e' below.

Remark: Even though the pressure integrity of the top drive system, (ie: the standpipe pressure while currently drilling just before the kick), suggests that the influx may be circulated out with the top drive still in place, it is nevertheless considered necessary to install the kick single assembly. This is because possibility exists that failure of the pressure integrity of the drillstring, (eg: H2S related stress corrosion cracking), could result in very high annular pressures being communicated to the top drive system. Installing the kick single after such an even and in difficult circumstances is deemed highly undesirable.

  • (a) Set the string in the slips and close the string IBOP.
  • (b) Open the upper (remote controlled) IBOP and check the pressure integrity of the closed string IBOP.
  • (c) Break the connection above the closed string IBOP.
  • (d) Make-up the kick single assembly and pressure test the system against the closed string IBOP to the initial closed-in drillpipe pressure plus 3000 psi.

If the flexible hose to the kick single assembly has been disconnected (eg:- for racking back purposes), pressure test the connection against the plug valve to 15k.

  • (e) Equalise the pressures and open the string IBOP.

(9) Check the space out and close the upper pipe rams (using reduced operating pressure).

(10) Land the drillstring on the upper pipe rams, (if necessary using reduced operating pressure on the upper annular preventer), and close the ram-locks.

Note: Remember to increase the operating pressures back to normal again after landing.

(11) Determine the influx volume and prepare to kill the well in accordance with Section 6.3, "Circulating Out the Influx".

Remember that once a well is closed in following a kick:-

(a) All work permits shall be withdrawn.

(b) The following parties shall be informed:-

- Standby boat

- Senior Well Engineer (operations)

- Rig Manager

- Emergency Co-ordinator (EC) as per the 'Emergency Response Procedures'

The OIM will also have responsibilities about whom to inform (eg:- coastguard) in accordance with his own emergency procedures.

(c) Crews should be mustered and all personnel to be informed of the status.

6.2 Kick With Bit On Bottom - Drilling With a Kelly

When drilling the high pressure section, the requirements for kelly configuration are detailed in Section 4.2, item 1

When a kick is first detected, close in the well as soon as possible in the following way:-

(1) Stop rotating and raise the kelly until the lower kelly cock is above the rotary table and the upper pipe rams can be closed below a tool joint. (This position should be determined before drilling commences and updated as required).

(2) Stop the pumps.

(3) Close the upper annular preventer.

(4) Open the failsafe valves in the upper chokeline.

(5) Record time and initial closed-in drillpipe and annulus pressures.

(6) Close the lower kelly cock.

Remark: This isolates the system downstream of the drillstring against the risk that the closed-in drillpipe pressure exceeds the setting of the mud pump relief valve, thereby allowing uncontrolled flow through the drillstring.

(7) Inform the Company Well Engineer and Contractor Toolpusher onboard.

  • (8) Install and test the kick single assembly as detailed in steps 'a' - 'e' below:-
  • (a) Set the string in the slips.
  • (b) Bleed off the pressure downstream of the closed lower kelly cock and check the pressure integrity of the closed lower kelly cock.
  • (c) Break the connection above the closed lower kelly cock.
  • (d) Make-up the kick single assembly and pressure test the system against the closed lower kelly cock to the initial closed-in drillpipe pressure plus 3000 psi.

If the flexible hose to the kick single assembly has been disconnected (eg:- for racking back purposes), pressure test the connection against the plug valve to 15k.

  • (e) Equalise the pressures and open the lower kelly cock.

(9) Check the space out and close the upper pipe rams (using reduced operating pressure).

(10) Land the drillstring on the upper pipe rams, (if necessary using reduced operating pressure on the upper annular preventer), and close the ram-locks.

Note: Remember to increase the operating pressures back to normal again after landing.

(11) Determine the influx volume and prepare to kill the well as per Section 6.3, "Circulating Out the Influx".

Remember that once a well is closed in following a kick:-

  • (a) All work permits shall be withdrawn.
  • (b) The following parties shall be informed:-

- Standby boat

- Senior Well Engineer (operations)

- Rig Manager

- Emergency Co-ordinator (EC) as per the 'Emergency Response Procedures'

The OIM will also have responsibilities about whom to inform (eg:- coastguard) in accordance with his own emergency procedures.

(c) Crews should be mustered and all personnel to be informed of the status.

6.3 Circulating Out The Influx

To ensure that the limitations of the surface equipment are not exceeded, especially when any gas reaches surface, the normal killing procedure must be modified as follows:-

(1) On the well killing graph mark the point at which theoretical top gas reaches the wellhead. Apply a safety factor to this point by reducing the time (strokes) by (say) 25%. Stop the pump and close in at this point then restart the killing operation at a suitable displacement rate which will ensure that the mud-gas separator is operated within its capacity.

Remark: For some rigs, the recommended kill rate detailed on the kill curve may be acceptable to use for the complete circulation in that it is not too slow and that it also complies with operating within the capacity of the mud-gas separator.However, for other rigs, although time is not an issue, to use the recommended kill rate for the complete circulation may be undesirable, and hence the pre-requisite above, to ensure that at least the recommended kill rate is not exceeded from when the gas reaches the wellhead.

At the point when theoretical top of gas (including safety factor) reaches the wellhead, the injection of glycol should commence. Once it has been determined that the situation is outwith the range of hydrates forming, then glycol injection can cease. Thereafter, the situation should be monitored in case as a result of changes in pressure and/or temperature, injection becomes necessary again.

Remark: The formation of hydrates depends primarily on two parameters, namely pressure and temperature, for any given gas gravity.

(2) Equipment limitations are as follows:-

  • (a) The maximum temperature at the choke manifold should not exceed 230 deg.F. To reflect the maximum temperature at the BOP, which for continuous operations is 250 deg.F., a value of 230 deg.F. at the choke manifold is used.
  • (b) The pressure in the choke manifold buffer chamber should not be allowed to exceed 250 psi otherwise a relief valve on the buffer chamber will lift and vent fluids to the overboard lines. (See section 2.3).
  • (c) The pressure in the mud-gas separator should not be allowed to exceed circa 5 psi, in order to protect the liquid seal, (and thereby also prevent wellbore fluids being transmitted back to the mud system). (See section 2.4)
  • (d) If there are indications of hydrates forming or if the temperature/ pressure range that will support the formation of hydrates is being approached, then inject glycol.

If any of these limitations are reached, the well should be closed in and corrective action taken. Having resolved any problems, the killing operation should be restarted in accordance with standard procedures.

(3) Once the influx has been circulated out and kill mud circulated around, close in and check that the pressures are zero.

(4) Depending on the reason why the influx entered the wellbore, an increase in mud weight is likely to be required. The amount of increase will be governed by several factors including pore pressure, overbalance including riser and trip margins, maximum allowable mud weight, and ECD.

Refer also to Section 7.1.1, "Mudweight Reduction in a Loss/Gain Situation".

(5) Flowcheck the well via the choke line.

(6) Circulate the riser and BOP to the new mud weight in a controlled manner to address the possibility of trapped gas.

(7) Open up the well, then observe the well dead.

6.4 Kick With Bit Off Bottom - Tripping: Rig With Top Drive

When a kick is first detected, close-in the well as soon as possible in the following way:-

(1)Install the open stab-in IBOP (standby kelly cock).

If unable to do so due to heavy backflow, clear the vicinity of all personnel then make-up the top drive. Continue as below but adjust for the fact that the stab-in IBOP is not installed. If unable to even make-up the top drive, close the shear rams.

(2) Close the stab-in IBOP.

(3) Close the upper annular preventer.

(4) Open the failsafe valves in the upper chokeline.

(5) Record time and initial closed-in annulus pressure.

(6) Inform the Company Well Engineer and Contractor Toolpusher onboard.

(7) Make-up the top drive and pressure test the system against the closed stab-in IBOP to the initial closed-in annulus pressure plus 3000 psi.

Remark: It may seem anomalous to install the top drive at this point rather than the kick single - much however will depend on the closed-in annulus pressure. The main difference between the situation off bottom compared to that on bottom is that the plan is to land-off then strip-in rather than land-off and circulate out the influx; the latter case requiring the kick single as explained in section 6.1, item 8, Remark.

(8) Equalise the pressures (using the closed-in annulus pressure as a guide) and open the stab-in IBOP.

(9) Check the space out and close the upper pipe rams (using reduced operating pressure).

(10) Land the drillstring on the upper pipe rams, (if necessary using reduced operating pressure on the upper annular preventer), and close the ram-locks.

Note: Remember to increase the operating pressures back to normal again after landing.

(11) If the HDIS dart is in place, record time and 'initial' drillpipe pressure by slowly pumping down the drillstring while observing the closed-in annulus pressure. The 'initial' drillpipe pressure should be recorded as the HDIS valve opens, ie: just as the annulus pressure begins to rise.

(12) Determine the influx volume and prepare to strip-in. Note however that the difference between the buoyant string weight in the hole and the upward force exerted on it by the closed-in pressure will determine the way in which to kill the well. Refer to Flowchart 8.4, "Section Red (Well Kill Flowchart - Bit Off Bottom)", and the two explanatory notes detailed in Section 6.6. Remember that once a well is closed in following a kick:-

(a) All work permits shall be withdrawn.

(b) The following parties shall be informed:-

  • Standby boat
  • Senior Well Engineer (operations)
  • Rig Manager
  • Emergency Co-ordinator (EC) as per the 'Emergency Response Procedures'

The OIM will also have responsibilities about whom to inform (eg:- coastguard) in accordance with his own emergency procedures.

(c) Crews should be mustered and all personnel to be informed of the status.

6.5 Kick With Bit Off Bottom - Tripping: Rig With Kelly

When a kick is first detected, close-in the well as soon as possible in the following way:-

(1)Install the open stab-in IBOP (standby kelly cock).

If unable to do so due to heavy backflow, attempt to stab the kelly and make the connection. Continue as below but adjust for the fact that the stab-in IBOP is not installed. If unable to even make-up the kelly, close the shear rams.

(2) Close the stab-in IBOP.

(3) Close the upper annular preventer.

(4) Open the failsafe valves in the upper chokeline.

(5) Record time and initial closed-in annulus pressure.

(6) Inform the Company Well Engineer and Contractor Toolpusher onboard.

(7) Install and test the kick single assembly as detailed in steps 'a' - 'c' below:-

(a) Set the string in the slips.

(b) Make-up the kick single assembly and pressure test the system against the closed lower kelly cock to the initial closed-in annulus pressure plus 3000 psi.

(c) Equalise the pressures (using the closed-in annulus pressure as a guide) and open the stab-in IBOP.

(8) Check the space out and close the upper pipe rams (using reduced operating pressure).

(9) Land the drillstring on the upper pipe rams, (if necessary using reduced operating pressure on the upper annular preventer), and close the ram-locks.

Note: Remember to increase the operating pressures back to normal again after landing.

(10) If the HDIS dart is in place, record time and 'initial' drillpipe pressure by slowly pumping down the drillstring while observing the closed-in annulus pressure. The 'initial' drillpipe pressure should be recorded as the HDIS valve opens, ie: just as the annulus pressure begins to rise.

(11) Determine the influx volume and prepare to strip-in. Note however that the difference between the buoyant string weight in the hole and the upward force exerted on it by the closed-in pressure will determine the way in which to kill the well. Refer to the two explanatory notes detailed in Section 6.6. Remember that once a well is closed in following a kick:-

(a)All work permits shall be withdrawn.

(b) The following parties shall be informed:-

  • Standby boat
  • Senior Well Engineer (operations)
  • Rig Manager
  • Emergency Co-ordinator (EC) as per the 'Emergency Response Procedures'

The OIM will also have responsibilities about whom to inform (eg: coastguard) in accordance with his own emergency procedures.

(c) Crews should be mustered and all personnel to be informed of the status.

6.6 Explanatory Notes

Methods by which to proceed to kill the well when the bit is off bottom are determined by whether or not the drillstring can be stripped in. This aspect is expanded in the two explanatory notes below:-

(1) If the upward force (closed-in pressure multiplied by the cross-sectional area of the closed-end drillpipe) exceeds the buoyant weight of the drillstring it will not be possible to strip in. Further action will depend on the gas migration rate. Refer to Flowchart 8.5, "Section Blue (Well Kill Flowchart - Pipe Out of Hole)".

(2) If the buoyant weight of the drillstring exceeds the upward force (closed-in pressure multiplied by the cross-sectional area of the closed-end drillpipe) exerted on it by the closed-in drillpipe pressure, the drillstring should be stripped back to bottom. Furthermore, it should be noted that:

(a) Once the bit is on bottom, install the kick single assembly and land-off as detailed in steps i. to v. below:-

(i) Set the string in the slips.

(ii) Make-up the kick single assembly and pressure test the system against the closed kelly cock on the bottom of the kick single to the initial closed-in drillpipe/annulus pressure plus 3000 psi.

If the flexible hose to the kick single assembly has been disconnected (eg:- for racking back purposes), pressure test the connection against the plug valve to 15k.

(iii) Open the kelly cock.

(iv) Check the space out and close the upper pipe rams (using reduced operating pressure).

(v) Land the drillstring on the upper pipe rams and close the ram-locks.

Note: Remember to increase the operating pressures back to normal again after landing.

Circulate the influx out (using the original mud weight) with reference to Flowchart 8.3, "Section Yellow (Well Kill Flowchart - Bit On Bottom)".

(b) If gas reaches surface before the bit is on bottom, stop stripping in then install the kick single assembly and land off as detailed above in Section 6.6.2a, steps i. to v.

Circulate out the gas (using the original mud weight) from where the bit is positioned, maintaining constant standpipe pressure. Thereafter, continue stripping in until gas reaches surface again or the bit reaches bottom.

Once the bit is on bottom, install the kick single assembly and land off as detailed above in Section 6.6.2a, steps i. to v.

6.7 Kick with Pipe Out of Hole

If the well starts to flow without any pipe in the hole:-

(1) Close the shear rams, and close the (shear) ram-locks.

(2) Open the failsafe valves in the upper kill-line.

(3) Record time and initial closed-in pressure.

(4) Inform the Company Well Engineer and Contractor Toolpusher onboard.

Remember that once a well is closed in following a kick:-

(a) All work permits shall be withdrawn.

(b) The following parties shall be informed:-

- Standby boat

- Senior Well Engineer (operations)

- Rig Manager

- Emergency Co-ordinator (EC) as per the 'Emergency Response Procedures'

The OIM will also have responsibilities about whom to inform (eg:- coastguard) in accordance with his own emergency procedures.

(c) Crews should be mustered and all personnel to be informed of the status.

There are several options now, namely:-

  • Stripping in (see note about re-entering on a floater in EP 89-1500, page 75), taking into account heave, pressure, buoyant weight of BHA in riser, etc.
  • Volumetric method
  • Bullheading

From the closed-in pressure readings measured against time, the migration rate can be estimated as follows:-

Migration Rate (ft/hr) = Pressure Increase (psi/hr) / Mud Gradient (psi/ft)

If the estimated migration rate is less than 1000 ft/hr, then the well may be bullheaded dead after confirmation with Base. If the estimated migration rate is more than 1000 ft/hr, the gas will be allowed to migrate to surface.

The closed-in pressure should be allowed to build up by a safety margin of say 100 psi. This margin is recommended to reduce the chance of the well becoming underbalanced. Where a low MAASP prevents excess pressures being applied to the wellbore, this margin may have to be reduced. Thereafter, mud has to be bled off in order to allow the gas to expand. Subsequently, to compensate for the loss in hydrostatic head, additional closed-in pressure, (Pw as in the stripping case), has to be applied.Conversely, when gas reaches surface, the situation is reversed. As gas leaves the well it has to be replaced by mud. To compensate for the gain in BHP, pressure has to be bled off.

For example, using 0.92 psi/ft mud in 9.5/8" x 72 lbs/ft casing:-

Pw (psi/bbl) = Mud Gradient (psi/ft) = 0.92      

Casing Capacity (bbl/ft) = 0.0641

= 15psi

For each barrel of mud bled off, an additional 15 psi should be applied and maintained on top of the closed-in pressure.

Once the gas reaches surface the reverse applies. For every 15 psi pressure bled off, 1 bbl of mud should be pumped into the well to compensate for the reduction in pressure.

6.8 Stripping-In Procedures

Rig specific stripping procedures should be in place as part of the Drilling Contractor's own standard operating procedures. Check that there are agreed:-

- strip drill procedures

- stripping checklists

- stripping calculation sheets

- stripping sheets for recording parameters such as pressures, tank levels, time, stand number, etc.

7 HPHT CONTINGENCY PROCEDURES

7.1 Drilling Fluid Losses in the Central North Sea

This section also apply to combined losses and gains situations.

Even given a formation strength at the deep intermediate casing shoe that is capable of containing the expected overpressures, it is still possible that fluid losses occur.

Losses could start while drilling through a weak zone between the formation at the casing shoe and the objective.

Once drilling through the objective, the overbalance over the formation pressure will increase with depth, due to the large difference between the mud and formation fluid gradients. This increasing overbalance could subsequently be the cause of losses deeper in the well.

Losses can also be induced by surge pressures; mainly when running in and especially when using highly viscous, heavy muds. If losses occur in this situation, it is difficult to establish where the loss zone is, and, depending on the position of the drillstring in the hole, it may be difficult to place curing material across the loss zone.

Guidelines on how to control the loss of drilling fluids in the aforementioned circumstances are given using a flowchart approach as detailed in Flowchart 8.7 "Losses while Drilling", and Flowchart 8.8 (plus notes), "Losses while Tripping In".

Drilling ahead shall not continue if dynamic losses of greater than 10 bbl/hr persist.

Other points regarding losses should be noted:-

(1) Where the ECD is a contributing factor to a loss situation, experience has shown that drillstring rotation can cause the ECD to increase, thereby exacerbating the situation.

(2) On a round trip it is advisable during running in (say half-way) to circulate in order to establish whether a (theoretical) ECD can be achieved.

For the same reason, this exercise should be repeated at the shoe. Being at the shoe is seen as the best compromise in case losses are actually induced; the drillstring is not in open hole, and the bit should be close enough to bottom for the placement of cement.

While mudweights are designed to overbalance expected (virgin) formation, if losses have occurred the formation may be supercharged and as such could give back fluid. If, in the process of giving back fluid, hydrocarbons are also flushed out of the formation, the wellbore will have taken an influx without it being recognisably induced.

7.1.1 Mudweight reduction in a loss/gain situation

Planned reductions of mud weight shall be carried out in stages in a controlled manner, and shall include a short trip for each stage to confirm that sufficient overbalance exists. For each stage, the (static) bottom hole pressure that existed with the mud weight being circulated out shall be maintained when circulating in the new (lower) mud weight by taking returns through the choke. While maintaining bottom hole pressure, dynamic losses should be avoided and much will depend on the circulating rate (ECD) and pressure drop across a fully open choke when determining appropriate back pressure (if any).

It may be necessary at the end of each stage prior to commencing the short trip to observe the well closed-in in order to check for any pressure build-up. If pressure is registered it could be due to supercharging. To ascertain if his is so, the pressure should be bled back (possibly to zero) but ensuring that an equivalent safe (manageable) influx volume of say 5 bbls. is not exceeded. This volume should then be circulated out again maintaining bottom hole pressure yet avoiding dynamic losses. The influx can be checked at surface for the presence of hydrocarbons.This process of bleeding back and circulating out the volume may have to be repeated several times to reduce to zero any pressure due to supercharging. If it becomes apparent that the pressure is caused by being underbalanced, the well shall be killed.

7.2 Emergency Cement Plugs

A situation involving losses may necessitate the performing of a cement squeeze through the bit. A combination of fluids to spot may comprise:-

- spacer (if required)

- pre-flush

- slurry (including tracer if required)

- post-flush

- spacer (if required)

- mud

As an option an LCM pill can be included after the mud, but this has to be taken into account when spotting the fluids.

An outline of the method (for a short open hole section) would be as follows. Appropriate variations may be required dependent on the rate of losses incurred before and during execution:-

(1) With the bit inside the shoe, spot the fluids in such a way that the pipe is pulled back further while the cement is filling the void below the bit.

(2) Pull back an additional stand (say) to ensure that the bit is above the top of the cement.

(3) Make sure the drillstring bore is clean by circulating partial or even full string contents at a high rate. The resultant ECD during this circulation will provide some squeeze pressure and therefore the rate of circulation may have to be adjusted to suit.

Remark: It is important to remove all the cement from the drillstring before closing in and applying squeeze pressure in case the string becomes plugged as a result.

(4) Close-in on the upper annular preventer: (ideally the annulus below the BOP should be full).

Note: Any cement that has strayed above the bit needs to be circulated out conventionally while keeping the string moving. Again, the resultant ECD during this circulation will provide some squeeze pressure and therefore the rate of circulation may have to be adjusted to suit. Additional squeeze pressure can be achieved by circulating over the choke.

(5) Apply squeeze pressure. The annulus pressure can be monitored via the kill or choke line in order to monitor the squeezing process.

(6) Check for losses and/or imbalance, then open up well. Ensure that the drillstring is kept free and clear by movement/circulation.

In a long open hole section or in a situation of sudden severe losses it may not be possible to pull the bit back to the shoe. Again though, cement should be spotted in such a way that as the pipe is pulled back cement fills the void below the bit.

7.3 Operating the BOP and Loss of Control

In all cases where a well control situation is deteriorating, the Emergency Response Procedures (which recognise the OIM as being the ultimate level of responsibility on the rig) must be adhered to.

(1) A well should always be closed-in initially using the upper annular preventer. The lower kill line should not be used to take returns and the inner and outer failsafe valves on the lower kill line should be kept closed. This will allow the bottom (pipe) rams to be a last line of defence, whereby if they are closed, any leak that may have developed in the choke line will be isolated. (See overall stack configuration in section 5.2.3).

In the event that this occurs, a decision will be made in conjunction with Base regarding the options, including:-

(a) Bullheading the well.

(b) Continuing well killing operations utilising the lower kill line. (Although not recommended, the well kill could be very near to completion of phase 3 or 4).

(c) Pump cement down the drillpipe with returns via the lower kill line.

(2) At some point it may become necessary due to loss of control to abandon the situation and move the rig off the well. The exact method of how the situation is abandoned will depend upon the circumstances whereby loss of control occurred, but well containment should obviously take precedence. In b terms:-

(a) The shear rams should be closed.

(b) The riser disconnected from the well.

(c) The rig pulled in an optimal direction (ie: upwind/up-current) off location using the anchors.

(d) In consultation with the OIM consider further/total evacuation of the rig.

Note: In order to give the shear rams the best possible chance of shearing the pipe, regulated pressure to the shear rams should be increased to the full 3000 psi accumulator pressure (by opening the bypass valve). On some systems the act of closing the shear rams may automatically apply the full unregulated accumulator pressure. The remote panels at the evacuation points should be checked to determine whether they are able to operate the shear rams on full unregulated accumulator pressure.

Consider for example the following situation:- if the lower pipe rams are closed to protect a failed choke line and then the pipe is sheared, the drillstring will slip through the lower pipe rams and the well will blow out through the failed choke line. In such an instance it may be better to land off on the lower pipe rams, close the middle pipe rams, pull string tension with the tooljoint against the bottom of the closed middle pipe rams, then close the shear rams.

The message being conveyed is that there may be preferable ways of abandoning the situation. Remember, closing the shear rams does not automatically secure the well.

7.4 Repairs to Surface Equipment

Situations may arise where it is necessary to effect repairs to vital surface equipment with pipe in the hole. If these repairs prevent the hoisting equipment or circulation system being used then the situation is exacerbated.

Bear in mind that with the drillstring set in the slips on a heaving rig, the mechanism (especially if not circulating) for swabbing exists. Developing procedures to cover every possible scenario is virtually impossible. As such, the following precautions are listed and can be applied wherever necessary:-

(1) Ensure an accessible string IBOP is installed.

(2) If possible maintain circulation and monitor pit volumes.

(3) If unable to circulate, continuously monitor the fluid level in the drillstring and annulus.

(4) Consider closing-in the well with the drillstring hung off in the BOP, and monitor closed-in pressures.

(5) The Company OWE should ensure that all relevant personnel are briefed on the potential for well control problems, and that the drillfloor is manned constantly by personnel capable of taking the appropriate action.

(6) Especially after completing an extended period of repairs, circulate the drillstring plus annulus volume to check for hydrocarbons.

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