This article describes the keys elements for preparing a HPHT procedure

An offshore Daily Meeting will be held between Company Drilling Supervisor, and service companies to review programme, procedure and safety aspects. The meeting will be conducted by the Company drilling supervisor.

Prior to starting specific operations other than routine jobs (i.e. well control, .etc) offshore pre job meeting will be held between Company Drilling supervisor and service companies.

1. DRILLS

A record of all drills will be kept on board by the OIM. The following drills will be performed with supervision and frequency recorded:

2. CRITERIA FOR THE TEMPORARY SUSPENSION OF OPERATIONS

The basic principle for suspension of operations or abandonment of the Well/Hole section is the protection of the following in order of priority:

• Personnel
• Environment
• Rig
• Well, within economic limits
• Equipment, within economic limits

Criteria to look for

Drilling operations will be suspended as soon as safely practical should any of the situations listed below arise. The situation will be investigated and remedied or deemed no longer hazardous prior to any drilling operations recommencing.

Well conditions subject well integrity dependant equipment to conditions within its operating window (pressure, CO2 .., H2S.etc)

• Vital safety equipment including its back up becomes inoperable. Monitoring equipment (gas, hydrocarbons, pressure…etc), Well control equipment (BOP.., Wellheads etc), Life saving appliances, Mixing equipment (if no kill mud in reserve).
• Stocks level of barites, whole mud, mud chemicals, cement, cement chemicals, base oil glycol fall below minimum stock (safety stock).
• Weather conditions.
• The difference between the LOT at the previous shoe and mud density falls below 0.06 SG
• Lost circulation (not seepage) occurs while drilling.
• Back ground gas (BGG) rises to an unacceptable level.
• Any kick indication: drilling breaks, increased returns, flow-rate, pit gain, hole not taking correct volume during trip, change in properties of mud
• Returned mud, increase in hook load, pump pressure decrease/pump stroke increase.

3. KEY INSTRUCTIONS FOR HP WELL

These specific instructions will come into force when drilling below the 9-5/8 and will be given to all relevant personnel as a guide for safety. It is essential that all information is regularly shared between Driller, Mud loggers and Derrick man in the mud pit room to develop a good understanding of the current well conditions.

Drill string

• A drilling stand with TIW valves at each connection will be used for drilling.
• Dart Sub for DICV and float valve must be systematically run.
• Circulating Sub (Ball type) should be installed above MWD tools.
• To minimize differential sticking, the length of the BHA must be reduced

Driller

• To avoid differential sticking and assist in breaking gels, rotation should always be established prior to starting the pumps. Pipe must be rotated whenever possible whilst in open hole. Torque reading should be recorded each time.
• Circulation should always be established prior to entering the open hole section (i.e. at TOL and casing shoe).
• Flow rate should always be increased gradually until full return of mud is observed.
• Pipe must never be reciprocated without circulation
• Prior to any flow check, pull back so the lower TIW valve on the drilling stand is easily accessible. Bleed of any drill pipe pressure, close the TIW valve and flow check for at least 30 min on the trip tank with the trip tank pump running. When the level on the trip tank is stable, stop the trip tank pump and carry on flow checking using the derrick man jug and a stop watch. Plot the flow rate on a graph, as a rule of thumb a flow. 
• If the flow rate obtained at the end of the period is in line with the previous flow checks (same trend), then the check is acceptable. 
• On encountering an unexpected drilling break, the driller will stop drilling immediately and flow check. Bottom up will then be circulated prior to resume drilling. The driller will inform Company supervisor as soon as possible.
• Addition of whole mud to the active mud system will not be done whilst drilling. The driller will stop drilling, make the addition and then carry on drilling once the active volume has stabilised

Derrick man

• Mixing of chemical and/or barite in the active mud system whilst drilling is permitted if the volume change rate is known and less than 1.5m³/hr (10 bbl/hr) Bleeding premix from one pit to another pit is permitted if pits are monitored in a closed system. Bleeding pure base oil in the active pit is prohibited. Driller, mud logger and Company Drilling supervisor & Drilling contractor  Tool-Pusher, must be informed before and after all mixing operations. 
• Mud weight will be recorded using a pressurized balance

Mud logger

•  Maximum ROP will be limited to 5-7 m/Hr (less if requested by the geologist) to ensure there will not be more than one connection gas in annulus
•  The temperature of the mud return will be monitored at all times. If mud return temperature increases at a rate higher than the previous observed trend then stop drilling and perform a flow check
•  If the ratio between connection gas and back ground gas levels in the mud increases, immediately notify Company drilling supervisor.

Tripping

Tripping of bottom is one of the most critical times regarding Well control and each trip must be individually assessed. Specific flow chart must be developped:

• Twhen well-bore stability is questionable.
• once into known reservoir intervals or once sufficient experience has been gained.

The difference between the two procedures is a short trip (additional security when unsure of stability).

In addition, the following should be adhered to:

• Company supervisor will be on the rig floor until the bit is inside the casing. The drilling contractor Tool-Pusher on duty will also be on the rig floor until he is satisfied that well is stable
• The volume of the Heavy slug should be limited to 3m3 (20 bbl).
• 2 independent calculations of swab/surge speeds will be made (i.e mud logger, mud engineer). It will be up to Company drilling supervisor to review these speeds, add a safety margin and then give the Tool-Pusher on duty clear tripping instructions detailing tripping speeds as a function of bit depth. The Tool-Pusher will ensure that the driller abides by these instructions
• Hole-fill will be monitored on the trip tank by both the driller and the mud loggers. Any discrepancies should be flow checked immediately. Due to temperature effect gels and weights the volumes may not be as calculated, these should be investigated and as the well progresses a trend of displacement should become apparent. It is important the previous trip sheet be kept as reference to aid the next trip.
• If the trip is interrupted for any reason, install a Kelly cock on the string and monitor the well
• When out of the hole keep the Blind rams open and continue monitoring the Well on trip tank (with pump running)

Coring

Coring trip out of the hole is also one of the most critical times regarding Well Control.

Specific TRIPPING OUT PROCEDURE should be developped

In addition, the following should be adhered to:

• DICV must be systematically run.
• Circulation Sub (Ball type) should be installed above core barrels (ensure core barrel and circulating sub balls are compatible)

Well stability Problems

• LOSSES/GAIN WHILE DRILLING HP SECTION
• LOSSES WHILE TRIPPING
• LOSSES WHILE DRILLING

Casing and Wellhead wear considerations

• The wear bushing will be pulled and inspected at least at each BOP test.
• A ditch magnet will be installed in the flow line the weight of metal recovered from the ditch magnet will be measured daily and recorded on IADC report. Increasing trend will be immediately reported.
• Should casing pipe protector be used they will be minimized as far as possible for ECD concerns (must be taken in to account for ECD calculations).

4. Well control procedure

4.1 Preparation

It is the joint responsibility of the Company supervisor and drilling Contractor Tool-Pusher to ensure that the points listed in this section are completed

Prior to drilling the Casing shoe

• BOP and choke manifold will be tested as per the drilling programme and lined up for hard shut in method. The MGS will be lined up as per the OIM work instructions
• All alarms and sensors will be tested
• A Gray valve, a full opening 15,000 psi drill string safety valve and a wire line retrievable drop in dart (DICV) of correct size will be kept on the floor with back up on the rig
• A kick assembly, comprising Kelly valves and side entry sub will be made up and pressure tested. It must be accessible at all times.
• Strippng and Killing drills must be performed by both crews:
• Trapped pressure drill will be conducted to establish if any pressure is trapped in the system following a hard shut-in.
• Dummy flow check drill will be conducted to determine thermal effect  flow rate
• Record the pit volume change when degasser, centrifuge, mix pump start up/shut down or when making a connection and post it on dog house and mud logging unit.
• SCR pressure will be recorded (using low range pressure gauge) for the high pressure system on the rig at 150, 200, 250, 300 & 400 l/min. These values can be compared to the equivalent pressures measured through top drive and difference should be recorded.
• Kick sheet will be established

When drilling

• Kick sheet must be kept up to date (change in BHA, mud weight ect)
• All normal kick detection systems will be regularly checked by mud loggers and drillers
•  All gas reading must be continuously monitored and analysed
• Trip tank will be kept full at all times and flushed at each shift

4.2 Action on detecting influx

The procedure will be adapted depending on the operation in progress (Drilling, tripping and out of hole)

4.3 Well Kill

If there is any doubt after the Well has been shut in, that an influx has been taken circulate well out through a choke (holding a slight back pressure) as precautionary measure.

 The recommended procedure for killing the well is the Driller’s method

Prior to well kill operations

• Kick size will be determined by measuring pit gain
• The kick will be considered to be gas until it has been circulated out
• Mud logger will calculate
• Stand pipe pressure schedule
• Estimated casing pressures from start to end of kill operations.
• Company drilling supervisor and Contractor Tool-Pusher will calculate independently
• Stand pipe pressure schedule
• Estimated kill mud weight
• Company drilling supervisor and Drilling Contractor
• Tool-Pusher will brief all involved personnel

During Kill Operation

• Only upper rams will be used to circulate out a kick. Blind/Shear rams will be used in emergency to cut pipe.
• The MGS will be circulated with hot mud of the same density as the mud being circulated. The floor man will be constantly checking returns of gas through the flow line and notified the driller immediately if gas is detected. If there is any doubt in the mud seal the circulation rate will be reduced and if further doubt exists the well be shut in.
• Be ready to start injection of Glycol when the influx is +/- 500m below surface.
• Casing pressure and temperature will be recorded at the choke by the mud loggers whilst circulating out the influx.  Casing annulus pressure must also be monitored any increase immediately reported to Company drilling supervisor.
• If the Well is in danger or becomes incontrollable The OIM will take the necessary actions to ensure the safety of all personnel on the Rig. 

5. Equipment Testing, Inspection and Repair

BOP Choke manifold and auxiliary pressure control equipment will be tested with water to the test pressure stated by Company in the drilling programme at the following time’s

• On nipple up or following repairs
• Prior to drilling a new phase or DST
• After repair
• Every 21 Days
• Blind/shear rams will only be tested prior to drilling last casing shoe
• All surface pressure control equipment will be function tested weekly
• All instrumentation for monitoring pressure, temperature and flow rate will be checked weekly for proper calibration.
• Gas and H₂S monitoring alarms will be tested weekly. A full test will be performed prior to drilling out the casing shoe.
• MGS choke and kill line will be flushed daily if displaced to mud
• After stripping operation, annular BOP will be inspected and or repaired prior to recommencing other operations.

6. Personnel

6.1 Meetings

• An offshore Morning Meeting will be held between Company drilling supervisor, OIM and all involved service companies to review programme, procedure and safety aspects. The meeting will be conducted by Company drilling supervisor.
• Prior to starting specific operations other than routine jobs (i.e. well control, .etc) offshore pre job meeting will be held between Company Drilling supervisor, OIM and service companies.

6.2 Drills

 A record of all drills will be kept on board by the OIM. The following drills will be performed with supervision and frequency indicated:

7. Type and level of Gas

 7.1 Type of gas

The gas readings are obtained by the mud loggers from gas analysis equipment and are classified according to the operation that releases the gas into the borehole.

• Drilled gas: Gas that is produced from the volume of cutting drilled. It is usual to record peak drilled gas level on the mud log
• Back ground gas: The gas that enters the bore hole during drilling or circulating (correspond to dynamic well bore conditions). It is the average gas level excluding peaks.
• Connection Gas: The gas that enters the borehole when circulation is stopped (static conditions) during the time taken for a typical connection.
• Flow check gas: The gas that enters the borehole when circulation is stopped (static conditions) during the time taken for a typical flow check (i.e. 15 min,  1/2 hr…etc)
• Trip gas: Gas that enters the bore hole when the drill string is tripped out of the hole, or partially trip out of the hole (i.e. short trips)
• Re circulated gas: Gas which is not removed by surface equipment and re circulated into the bore hole. May be detected when re circulated back to surface.
• Swab gas: Gas that is introduced into the Well bore when the hydrostatic bottom hole pressure is temporary less than the gas bearing formation pore pressure at the point of interest. The temporary reduction in pressure is caused by the swabbing effect of the drilling string moving upward.
• Kick gas: Gas that enters into the bore hole when the reservoir pore pressure exceeds the mud hydrostatic pressure, either while circulating or under static conditions. Reservoir pressure may include virgin reservoir pressure or pressure surcharged by mud losses.

 7.2 Acceptable gas level

The meaning acceptable gas level can be defined as:

A level (%) of gas in the drilling mud, as measured by gas analysis equipment, that does not require any modification on the on going operation, or adjustment to the mud weight.

In determining that the level is acceptable the following criteria will be assessed

• Gas cutting: The mud should not be heavily gas cut because the process of passing through the surface processing equipment shakers …etc should allow any entrained gas to be released from the mud, and the mud should return to its planned weight.
• Free combustible gas: the amount of free combustible gas in any area where the mud passes through should stay below the lower alarm setting for the combustible gas detectors.
• Get wetness ratio: ratio of heavier gas elements to lighter gas elements to indicate proximity of transition zone.

8. Well Kill Methods

• Stripping
• Bull heading
• Off bottom Kill
• Volumetric method
• Barite Plug

8.1 BULL HEADING

This procedure is recommended in very special cases and should only be used when normal circulation method for kick control is thought to be too dangerous (large influx, excessive surface pressures/gas volumes if influx circulated out, unable to strip to bottom It is to be noted that in certain cases bull heading could possibly create worst problems (i.e. severe lost circulation) than what it might solve.

 Conditions

One of the following hole conditions must exist for successfully accomplishing a kill operation by using a Bull heading Technique:

• Very small amount of open hole exists or the second weakest point in the open hole has a fracture/injection pressure higher than the reservoir where the kick originated.
•  Influx is above the weakest point in the open hole and hardly any open hole exists.
•  All of the other following conditions must exist:
•  Operations have been comprehensively planned and no problems are foreseen.
•  All equipment (surface and down hole) must have a higher pressure rating than the maximum anticipated Bullhead pressure (allowing for relevant fluid gradients).
•  Casing Burst must exceed surface bull heading pressure plus any hydrostatic difference between Mud Hydrostatic Inside casing and Mud Hydrostatic outside casing
•  Surface Mud Volumes must be at least equal to double the amount required to bullhead influx back into zone.  (Generally bull heading will not be started until surface mud volume is equal to twice the entire hole volume. If this is not possible due to Rig Mud System, additional volume will be built and placed on a liquid mud supply vessel).
•  In extremely critical cases, seawater may be used.  Seawater will not kill well but will probably reduce surface pressures.
•  Bull heading will not create severe lost circulation (i.e. Total loss of fluid column in the annulus).
•  Usually it will be necessary to pump more than the calculated volume due to poor displacement of influx.

 8.2 OFF BOTOM WELL KILL

 An off-bottom well kill (off-bottom well kill means circulating mud of the appropriate weight with the bit at the present depth) will ONLY be attempted if bull heading and stripping to bottom cannot be carried out in a safe or practicable manner.

Due to the fact that this procedure is abnormal in the extreme, every care must be considered independently and a rigid procedure should not be used.  However, written guidance is needed and this follows in the form of an outline procedure plus key points which must be considered prior to attempting an off-bottom kill.

 a. Outline Procedure

1. Record all relevant well control data.
2. Calculate kill mud weight required to kill well with bit at current depth.
3. Is formation strength (at the open hole weak point) capable of withstanding the equivalent mud weight (EMW) resulting from the circulation of the kill mud?  If not, then reduce kill mud weight to an acceptable level to prevent open hole fracture whilst at the same time reducing surface pressures enough to permit a stripping operation.
4. Circulate the kill mud (or partial kill mud) maintaining constant pressure (+ safety margin) at the bit using a drill pipe pressure schedule.
5. Once the well is killed (or partially killed), strip into the hole (possibly in stages conditioning the mud) to bottom.
6. Circulate the well to a stable condition with revised drilling mud weight.

 b. Key Points to be Considered

The following points should be considered and clearly covered in the detail programme put together prior to any off-bottom well killing operation:

Where is the influx?  (If influx is below the bit then SIDPP=SICP providing there is no slug in the pipe and no trapped pressure in the mud column).

• When calculating kill mud densities use sufficient safety margins (regarding P-pore and P-frac) to allow for surging, ECD and temperature effects on mud density.
• Ensure equipment being used is adequate for pressure and temperature ranges anticipated (this includes low pressure gauges when low pressures are expected).
• Allow pressures to stabilise
• Calculate expected gas volumes at surface after expansion and ensure surface equipment adequate.
• Make allowances for gas migration

               Migration rate (m/h) = pressure increase (bar/hr) / Mud gradient (bar/m)

• Ensure a clear record is kept of events (particular volumes of different density mud in the well and bleed off volumes.
• Drill pipe pressure is not a reliable guide to bottom hole pressure during killing operations if the bit is not on bottom.
• Crews cannot be certain how much mud and how much influx is below the bit.
• If sufficient drill pipe pressure is not applied inflow can occur under the bit with a reduction of hydrostatic gradient and an increase in drill pipe pressure.  The normal control action by the choke operator, to open the choke to restore the "pre-planned" drill pipe pressure, leads to further inflow.
• The actual response of the well to the kill should be monitored to allow corrective action to be taken.  An example is shutting down kill pumps at predetermined intervals during circulation to record static drill pipe and choke pressures.

 8.3 VOLUMETRIC KILL

This procedure is recommended when circulation cannot be established (i.e. string, choke lines plugged) and when the string is completely out of the hole and when stripping operation cannot be followed. The basic principle of this technique is to maintain the BHP constant with the well closed, this will be achieved by bleeding off a certain volume of mud in order to allow and control the gas expansion/migration.

Outline Procedure

1. After shutting the well in allow the shut in SICP to build to SICP2 where:

    SICP2= SICP + S + Pressure step

    Where:

• SICP= Initial Shut-in Casing Pressure
• S = Safety margin pressure increment
• Pressure step= Working pressure Increment

Convenient values of S and Pressure step are between 50 and 150psi (5 and 10 bars)

2. Calculate the Volume of mud V1 where:

 V1= allowance for loss of hydrostatic corresponding to Pressure step

Example: For 6.75” hole (capacity: 23.09 litre/m) Mud weight= 2.32 SG and Pressure step= 5 bars, Volume V1 will be:

V1= (5 x 10.2 / 2.32)23.09 = 507 litres

3. Bleed off Volume V1 to the trip tank keeping SICP2 constant

4. Allow the new shut in annulus pressure SICP2 to build to SICP3 where:

SICP3= SICP2 + Pressure step

5. Bleed off Volume V1 to the trip tank keeping SICP3 constant

6. Follow the same procedure for SICP4, SICP5….etc