WELL CONTROL PROCEDURES 1.1 GENERAL

This document is the HPHT Well Control Supplement for well *** and should be used in conjunction with the contractor. Well Control Manual. It should be referred to during the HPHT section of the well which will be below 13,500 ft TVD RKB. As this document has been developed

specifically for the drilling of well *** it will form part of the well *** it will form part of the well-specific training which has been planned.

It is essential that in the event of an influx entering the wellbore the well is closed in as soon as possible. For this reason Pit and Trip drills need to be carried out on a regular basis (daily initially) to ensure the rig crews are fully trained. Stripping drills will be carried out while tripping in the hole before drilling out the 13 5/8" and 95/8" shoes.

The "FAST" shut in will be the method used in normal circumstances (choke closed, shut-in with annular). In special circumstances where the Kick Tolerance is deemed to be too low, about 40 bbls, then the "HARD"

shut in should be used (choke closed, shut-in with pipe rams). The actual method to be used will be determined by the Drilling Supervisor in

consultation with the Rig Superintendent.

The Driller has the authority and responsibility to shut the well in at any time that he suspects the well is flowing. It is better to shut the well in quickly and then bleed of any suspected trapped pressure that to flow check a kick indicator. The shut-in procedures are listed in the Contractor Well Control Manual.

The mud logging company will provide independent and continuous monitoring of the well. The Driller should react to their indications of flow as he would his own and act accordingly.

Once a kick is identified, and the initial well closure performed, a procedure to kill the well should be discussed and agreed by key personnel. No

changes to this procedure should be made by any individual without agreement from operator Drilling Management and the key offshore personnel.

If there is any doubt about the status of the well then it should be shut-in and the situation analysed. Note that the well design allows for shut-in at any stage in the operation without casing of other mechanical failure.

1.2 HPHT DRILLING POLICIES AND PROCEDURES

The following procedures should be adhered to while drilling below 13,500 ft TVD RKB in the HPHT section where the bottom hole pressure is

estimated to be at least 10,000 psi.

1) Always drill with a ported float in the string. This will allow the well to be shut-in in the event of a flow yet enables SIDPP to be read with some accuracy in heavy POBM. Due to the inaccuracy in monitoring the well while RIH regular flow checks should be carried out as well as a trip record kept.

2) Always drill with a drop-in dart sub in the string placed in the BHA above the HWDP. Check all ID's for restrictions and ensure that the drillpipe has been drifted to maximum required.

3) Drill in singles throughout the HPHT section. Use a range 3 joint of pipe as a kelly equivalent with two kelly cocks and a saver sub at the end.

4) Connection gas due to the reduction of ECD can be a good indicator of increasing pore pressure. Ensure that the trend of gas levels are

recorded by the mud loggers. Do not make more than one connection in the 8 1/2" hole until gas levels from the previous connection are checked at surface.

5) Flowcheck all significant drilling breaks for a minimum of 15 minutes, with a minimum ROP increase of 25% before checking. Continue to rotate pipe while flowchecking.

6) Ensure that the flowline drain down volume is known. The mud loggers should monitor drain down on every connection to check the well is not flowing.

7) Record trapped pressures remaining on the standpipe when pumps are turned off. This pressure can be used during a kick to evaluate the actual kill weight required. The Bariod XP07 POBM has a low rheology so this will not be a problem.

8) After drilling out the 9 5/8" shoe and prior to performing the LOT pull into the shoe. Close in the well for at least one hour and observe for a pressure build up as the mud heats up. Record this pressure and the

9) Do not change the active mud volume by adding, subtracting , or weighting up while the well is being drilled. This will mask any small kicks. Stop drilling while any essential mud volume changes are required. Ensure the Driller has given his permission and the Mud Loggers are aware of the operation.

10) It is proposed to maintain a minimum stock level of 200 MT of Barite, together with the required chemical additives, to retain acceptable mud properties throughout the 8 1/2" section.

11) It is proposed to maintain a minimum stock level of 60 MT of cement and associated chemicals throughout the 8 1/2" section.

12) A sufficient quantity of LCM materials should be maintained as outlined in the Drilling and Mud Programmes.

1.3 HPHT TRIPPING PROCEDURES

1) The Drilling Supervisor and Rig Superintendent should be on the rig floor at the start of any tip out the hole.

2) The following steps should be followed when POOH:

a) Circulated the hole clean.

b) Flowcheck for a minimum of 15 minutes. Rotate pipe throughout.

c) Do not pull out of the hole if the hole is not stable, i.e. no losses or flow.

d) Pull out (not pumped) of the hole 10 stands and run back in hole to bottom no faster than the calculated swab/surge rate.

e) Circulate bottoms up. Record gas levels. An option to circulate the last 3000 ft over the choke should be considered depending on hole conditions.

f) Flowcheck for a minimum of 15 minutes. Rotate pipe throughout.

g) Pump out of the hole in 8 1/2" hole to the previous shoe.

h) Pump a slug at the shoe, allow to settle before pulling out.

i) Flow check as a minimum on bottom, at the shoe, and before pulling the drill collars through the BOP. Monitor the well on the Trip Tank when out of the hole.

3) The following steps should be followed when running in the hole:

a) Flow check as a minimum half way to the shoe and at the shoe.

b) Break circulation slowly at the shoe and when back on bottom.

c) Circulate bottoms up. Record gas levels. An option to circulate the last 3000 ft over the choke should be considered depending on hole conditions.

1.4 HPHT CORING PROCEDURE

A core of the Fulmar Sand will be required on hydrocarbon shows. The following precautions and procedures should be followed when coring the HPHT section is required.

1) Drill at least 30 ft of reservoir prior to coring.

2) Use steel core barrels with pressure relief ports / plugs. Maximum length of barrel is 60 feet.

3) Run a Hydril Drop-in sub above the core barrel.

4) Follow the HPHT tripping procedures.

5) Drop the Hydril Drop-in dart at the shoe before pumping the slug. This will prevent any gas breaking out the core and expanding up the drillpipe.

6) POOH to 1000 ft. Circulate through the choke and record gas levels.

7) POOH

8) When handling the core on surface breathing apparatus should be worn until H2S levels are checked.

1.5 SUSPENSION OF OPERATIONS

The criteria for suspension or abandonment of the well, or of that section of the hole giving rise to continuing problems are as follows:

1) Well control and surface equipment have been exposed to

temperatures or pressures outside their recommended operating envelope.

2) Mechanical failure of any critical pressure containment equipment [wellhead, casing (including excessive wear), BOP, choke/kill manifold] unless redundancy exists.

3) If any vital safety equipment fails (mud or gas monitoring

equipment, mud mixing equipment if reserve mud stock low, life-saving equipment) unless redundancy exists.

4) If severe downhole loss of mud does not reduce after repeated treatments.

5) If the pore pressure while drilling increases to a value requiring a mud weight to balance which reduces the kick tolerance to an unacceptable level.

6) If the stock levels of Barite, Cement, Mud or Mud additives falls below a minimum level.

7) If the weather conditions are outwith the operating envelope of the rig or are considered unsafe by the OIM.

8) If TD is reached without encountering any significant hydrocarbons or after completion of testing any hydrocarbons encountered.

9) If there is a danger to the structure of the rig (seabed condition, collision).

10) If any other condition exists which the operator considers to create a hazard which is unacceptable.

1.6 CASING WEAR

The 10 3/4" * 9 5/8" casing has been designed to have sufficient strength, including a safety factor, to withstand reservoir pressure less a gas

gradient to surface.

During the Jurassic testing phase the 10.3/4" * 9.5/8" casing will act as the production casing and water is planned to be utilised as the packer fluid.

It is therefore imperative that this string of casing, plus the wellhead components, are as close to original specification as possible. Should significant wear take place then a contingency liner will be run but this is not the preferred option.

The total drilling time to TD, from the 10.3/4" * 9.5/8" casing point, is prognosed as 6 days. This short period of drilling should contribute significantly to minimal casing wear, as should the use of best practices including close control of mud properties, minimal wellbore inclination and non-rotating sleeves.

Ditch magnets and wear bushings must be utilised and monitored during the 8.1/2" hole section. Although these methods can identify whether or not any wear has taken place they cannot define the casing's residual

strength.

In order to accurately determine the status of the string of casing the following will be performed during the drilling of the 8.1/2" hole section.

(1) The casing will be calipered during the wait-on-cement time.

(2) Ditch magnets and a wearbushing will be utilised and monitored during drilling operations.

(3) Should drilling operations continue beyond 15 days, and there are definite indications from the ditch magnets that some casing wear has taken place, then the caliper will be re-run. The casing burst should be reviewed at this time and compared to the requirements of further drilling operations in terms of well control.

(4) Should, for any reason, drilling continue beyond 30 days, and where a caliper was not re-run at 15 days, then a caliper should be run and the casing re-evaluated.

(5) Irrespective of (3) or (4) above a final caliper survey will be performed and the casing's residual burst capacity determined prior to any testing