Rig up checklist

• Rig down the rig elevator and bails, make sure the iron roughneck has been laid out
• Remove the saver sub using the pipe handler of the top drive (rig procedure). Check the make-up torque setting of the pipe handler prior to removing the saver sub. Verify that the pipe handler stays inline with the top drive main shaft.
• Ensure that the top drive shaft is aligned with the rotary table centre. Ensure that the pipe handler is dressed correctly to grip the top connection of the OverDrive.
• Lift the JAM equipment to the rig floor. Rig up the JAM equipment simultaneously with the OverDrive tool.
• Bring the service loop container including the control panel and all of the additional service equipment to the rig floor. Install horseshoe bracket onto the service loop and lift into the derrick approx. 15m with a safety sling between the horseshoe bracket and the derrick.
• Prepare lifting equipment for OverDrive tool. Use 2 soft slings or cables with 9 ton capacity each sling (6 – 8m length).
• Install lifting cap into top connection of OverDrive. Tighten one sling around the top of OverDrive tool. Secure the slings against sliding and lift the OverDrive tool to the rig floor
• Connect lifting slings from top drive to lifting cap or connect drill pipe elevator to lifting sub. Transfer OverDrive tool from horizontal to Vertical using top drive and crane.
• Remove rotary cover and bottom sling and lower OverDrive into rotary. Disconnect lifting slings/drill pipe elevator, remove lifting cap/lifting sub. Check the alignment of the pipe handler to the top drive shaft.
• Lowering top drive, slowly spin in connection while making up to OverDrive actuator. For safety, use paint marker to place a vertical line across all connections in the load path for visual reference.
• Install the link tilt bail arm extension and the single joint elevator. Made up fill up tool 1000ft*lbs and install mud saver valve to the fill up tool.
• Install FMS into the rotary and check all equipment
• Pick-up a joint of casing and set into the slips, pick-up second joint and set into the first joint
• Calibrate the JAM system connected to the top drive against JAM system connected to a manual back up tong and TorqSub.
• Casing tongs keep as a back-up.

Running checklist

• Check casing hanger made up to full length casing joint to facilitate easier handling.
• Check correct length dedicated landing joint (buttress box top conn.) to screw directly into cement head.
• Check cement head set up for buttress thread.
• Casing pup joints need to be a minimum of 3m in length for the Overdrive system.
• Check spares for pick up/lay down machine. Hydraulic hoses, crimping machine etc.
• Check auxiliary equipment for pick up/lay down machine e.g. correct hooks for casing size and extensions for short tubulars.
• No need to have the back up casing tong on the rig floor (free space).
• Mobile telephone signals can cause interference with the JAM unit – ensure mobile telephones are not present on the rig floor.
• The OverDrive system must be laid down and 500T elevators installed prior to making up cement head. This will allow casing to be landed whilst maintaining pressure if floats fail.

• Ensure a circulating swedge is available for washing down the hole.

• Ensure the casing tongue HT100 are on the floor together with the correct size jaws.
• The stab-in shoe should have been installed on 20” casing joint.
• Casing will be cemented using an inner string. Check that the centraliser, stinger string and correct back up seals are available.
• Confirm the stinger threads are compatible for the drill pipe and a crossover is available if required.
• Check condition of the stinger ‘o’ ring seals and replace if necessary.
• Fit stinger centralizer 2 meters up on first joint of stinger string.
  • Ensure the inner string is drifted to the required the specifications for the wiper latch down plug.

• Starter head should be sent out installed on full joint (or 3m pup) to avoid problems with tong bridle.

• Programmed make up torque on Antares ER connections is 13,000 ft-lbs, with a maximum of 13,980 ft-lbs allowable.
• Casing tally will be entered into OpenWells daily reporting software by the Drilling Supervisor
• Total depth will be adjusted for the casing tally (allow 10 m rat hole).
• Use one centraliser per casing joint on joint #1 (shoe) and joint #2 and one centraliser every two joints up from #3 to surface. Stop collars will be pre-installed on the pipe rack.
• Use only spring bow type centralisers. Do not install any centraliser on the pup joint below the wellhead housing, and do not use any solid centraliser.
• Use thread locking compound on the first two connections.
• Visually inspect the bore of all joints on the rack to ensure they are debris free.
• Accurately measure, the distance from the rig floor to the land off point. 
• Obtain wellhead orientation drawings from Superintendent.
• 20” casing circulating head must be on the rig floor prior to running the string. Hose or chicksans should be already connected to the standpipe.
• Ensure that the cellar jet is rigged to route returns to the shaker header tank, with a bypass valve to allow cement returns to be dumped in the cuttings/waste tank. OR ensure that there is a vacuum truck available to suck fluid directly out of the cellar.
• Ensure sugar is available on the rig site. Sugar is to be added to the cement returns in the cuttings/waste tank to avoid cement setting.
• Ensure final cement slurry recipes have been received from Operations Engineer.
• Prepare the mix water for the next cement job while running the casing. Ensure that all tanks and lines are clean. Transfer the required Technical Water volumes to the batch mixers.
• Ensure water is supplied from drilling camp technical water tank. Prepare the lead mix fluid first to let it hydrate whilst preparing the tail mix fluid. Add chemicals to the Technical water per confirmed recipe.
• Hold a pre-job technical and safety meeting with all personnel involved in running and cementing the casing string.
• Make up shoe track and confirm float function (DSV will check inside for debris).
• Run 20” casing.  Fill each joint as it is run.  DO NOT PICK UP AND MOVE THE CASING STRING UNECCESSARILY to avoid surging the formation.
• Limit running speed to 45-60 sec / joint (slip to slip).
• Pick up 20 ¾” wellhead head housing and make up to 20” casing.
• Connect top drive and circulate last joint to TD.
• Land the 20 ¾” wellhead head on the 30” Conductor pipe. Reciprocate a few times before landing to centre well.
• Orientate 20 ¾” casing head. Confirm orientation with Superintendent.
  • Check that the orientation and bolts position on the top flange will be compatible with the position of the diverter lines when the diverter is installed. If welding on the diverter has to be done, ensure it is done off-line.

• Secure the base flange onto the 30” conductor to ensure no movement possible during cementation.

• It is essential that the 20” conductor is aligned vertically with the ROTARY TABLE When aligned, the 20” starter head should be tack welded in position on the 30”

• Remove the running tool and RIH with inner string DP/HWDP stab-in assembly.

• Should hole conditions prevent the landing of the wellhead on the 30" conductor, pull back wellhead above rig floor and space out (Csg pup jt) to enable landing the CHH.
• If casing is stuck, it will be cemented in place and the backup emergency Sliplock 20 ¾” casing head housing will be installed afterwards.

• Pre-job planning meeting with all key personnel.
• Discuss with LWD coordinator during pre-phase meeting regarding download memory data from LWD on last run to lay down tool instead of leaving tools hanging.
• Use pipe (XT-54) when running 7” BAKER liner hanger RT, in case it is not able to pull the string then the pipe can be backed off.
• Check if modified thread compound in compliance with API 5A3 (e.g. Lube Seal API Modified) is available as it is recommended to be used during winter season, it is required the use of a power tong equipped with load cell and hydraulic fluid suitable for extreme cold weather conditions.
• Liner weight and displacement graphs to be prepared.
• Aluminium spiralizers will be used.
• Pip tags to be available prior to running liner.
• Use short bails when running 7” casing to help casing centred and not swing when stabbing into box.
• Ensure after setting liner hanger the running tool should be picked up twice to confirm the tool is released prior to cementing.
• Back up shoe, float and landing collars should be available on location.
• Gauge the OD of the liner drift provided by Weatherford and confirm with the Operations Engineer that the dimension is acceptable. OD certification should not be older than 12 months.
• Randomly selected ten joints of liner should be internally callipered to accurately determine internal volumes. Use the average ID to calculate displacement volumes. Obtain an accurate measurement of mud pump efficiency for pumping cement.
• Complete tally of 7” liner and space out the liner to be set ~0.50 m from well TD. Refer to 9-5/8” casing tally or CCL to confirm that setting depth of hanger does not place hanger slips or packer element across a casing coupling.
• Shoe jt , float collar jt, single joint and landing collar joint to be laid out on top row of liner.
• Confirm reamer shoe design with Operations Engineer.
• Check if fabricated pup joint that connects straight from the Top Drive to the cement assembly is available. This would reduce the need for excess handling of equipment, minimise man riding operations and save time.
• The displacement will be made with the cementing pumps, using a dedicated tank. Ensure pump is fully charged prior to displacement and total volume recorded.
• Mud loggers to calibrate pit volume indicators and ensure accurate records of pit volumes are maintained throughout liner running and cementation.
• The liner string will be rotated while cementing to ensure good cement bond in the liner annulus. Note liner make up torques below.
• On the rack attach each solid Aluminium spiralizers with 2 x stop collars as follows:
  • One aluminum spiralizer per joint over shoetrack.
  • 1 Aluminum spiralizer per joint from ~5106m to ~5050m. Ensure alternate flow direction on alternate joints.
  • 1 Aluminum spiralizer per 2 joints from ~5050m to top of liner. Ensure alternate flow direction on alternate joints.
• Liner cementing head on location. Confirm with Operations Engineer the following:
  • Correct size of pump down plug has been loaded into the Plug Dropping Head Assembly
  • The phenolic setting ball has already been inserted in the ball dropping sub.
• Calculate space out and make up cementing system ensuring there is adequate space for string manipulation. Lay out on catwalk.
• Three DP pup joints of different lengths to be laid out on catwalk.
• Ensure that no need to hold 500psi for un-stinging the running tool from packer when we do 7” liner job.

• Wear Bushing retrieved
• Pre-job safety brief held with all parties
• Back up float and shoe equipment in store or easily available
• All float equipment is PDC drillable and written on the tools
• Tailing device available if required
• Casing crew checked out tongs/power pack
• Bakerlock/wire brush/barite available on rig floor
• Float equipment checked out  Floats to be run in self-fill mode or not  Tabs/wedges removed if not to be run in self-fill mode
• Float shoe and collar pre-installed and Bakerlocked
• Centralisers and other consumables fixed as per program
• Drilling Supv/Toolpusher checked out handling equipment
• Crossover/s to DP + TIW valve on floor
• Circ head/lo-torq on floor
• Landing joint calipered and in spec (If applicable)
• Sample of joints calipered to determine average ID
• Pipe drifted, threads cleaned, tally checked, number of joints on rack confirmed and numbered
• Pick-up/laydown equipment in position and serviceable, clear understanding between its crew and rig crew of procedure
• Stabbing board functioning

• Before running the 13-3/8” casing, make sure that the rig is correctly aligned with the rotary table centred over the wellhead (note: the DP will now be racked back so the weight distribution from when drilling will have changed). This is to prevent damaging the wellhead at seal area. This can be done when jetting wellhead.
• Check all equipment is on-site and in good condition.
• Gauge the OD of the casing drift provided by Weatherford and confirm with the Operations Engineer that the dimension is acceptable. OD certification should not be older than 12 months.
• Check Weatherford Torque graphs if they are correct.  Ensure no debris is inside casing joints.
• Ensure that backup’s of shoe, float collar, couplings and plus are available on location.
• Ensure the 13-3/8” float equipment is a PDC drillable.
• Check if the casing shoe has been supplied in auto-fill mode and ensure test procedure is applied.
• Ensure that the spiral type casing centralizers are used in order to not causing any damage to wellhead.
• Ensure that the mandrel casing hanger and running tool are assembled prior to sending out to the rig.
• If Overdrive system not utilised then the fill up circulating tool will be used to fill up the casing while RIH and in the event it becomes necessary to circulate the string down.
• Ensure that the service history of the circulating packer is sent with the tool and it has been serviced and checked to be in good condition and of correct size.  Back up circulating tool element is to be available on location and should be in good working condition.
• Check the Klepo’s and Stabbing guides fit the pin & box ends.
• Make sure the snub line is the correct size and length and certified.
• Re-check all safety features are functioning on power tong.
• Prepare, clean, drift and dope on the pipe rack all the joints which are to be run.
• Remove casing thread protectors and clean pin and box ends thoroughly. This can be done with a light concentration of Baraklean and water using a pressure washer.
• Use API modified thread compound compliant with API 5A3.
• Centralizers will be pre-installed with stop collars on the pipe racks as per tally.
• Ensure that the centralisers have the necessary clearance from the Flush Mounted Slip’s.
• Check to see if we have the correct nails (ordinary & spiral) for the centralizers.
• Ensure that various length casing pup joints are available for space out.
• Ensure maximum pull information is available at the rig floor.
• When slinging the single joint elevators position them through the pad eyes on the Varco elevators
• Ensure that the casing tally is prepared well in advance and all joints crosschecked and confirmed on pipe racks before casing running job is started. 2 independent measurements must be made.
• Ensure the correct Pup joints for positioning the Fill up tool to be as close as practicable as possible to the elevators in order to allow circulating down any potential tight spots.
• When rigging up the Casing equipment make sure the Hawk jaw tong has been laid out, and then bring the Casing tong up first (before the bails), this way the tong & computer can be set up and calibrated while the Fill up tool & the auto handling equipment is installed.
• Make sure that a conventional circulating swage will be available on the rig floor at all times.
• Ensure a cementing manifold is prepared and made up to the wellhead. This will allow returns to be taken to shakers or straight to the waste pit from the wellhead.
• Rabbit/drift all casing and strap.  Ensure that sufficient casing has been delivered to allow for 10% excess.  Calliper the ID of 10% of randomly chosen joints and use the average for displacement purposes.  Ensure to calliper each joint in both NS and EW directions. Obtain an accurate measure of mud pump efficiency for pumping cement. Pump efficiency recorded on previous 13-3/8” cement jobs should be referenced for comparison.
• Once the casing has been tallied, a spreadsheet of displacement values against running number and hook weights should be prepared and available on the drill floor.
• Before running the casing, calculate the swab and surge pressures (ensure that the mud logger is competent to run the casing swab and surge pressure calculations).
• Select the most suitable running speed for the hole conditions.
• If possible have the FMS control panel and any other equipment on the rig floor before the start of the rig up (Rig floor space a factor)
• Make sure the air hose for the Varco’s are long enough. Tie/Tape off the air supply hose for the Varco’s along the bail arms. Coil the hose is necessary.
• When slinging the single joint elevators position them through the pad eyes on the Varco elevators.
• JamPro unit to be checked before job as well as confirming pipe details.
• Mobile telephone signals cause interference with the JAM unit – ensure mobile telephones are not present on the rig floor as per Company policy.
• Make sure the snub line is the correct size and length and certified.
• Lift all joints of casing to the floor using the Rig Floor tugger and rest in the V-door.
• Check there is a C-Plate for the Fill up Tool.
• Connect Varco type elevators to the bail arms positioning the air operating switch to the side of the stabbing board.
• Have a work stand prepared for operating the tong as well as when making up the Float Collar (13-3/8”).
• When running the job every half hour pour some oil in between the slips and the Varco body. On the fly grease the FMS & Varco elevators (preferably every 25-30 joints).
• A casing drag chart will be provided by the Operations engineer.
• After making up the Shoe track, fill up every joint as we lower it down, ensure that the joint never overflows. Stop pumping once the OBM is at the same level as the previous coupling.
• Discuss with mud engineer and mud logging engineer how losses while running will be monitored.
• 22 ft long bail arms will be sent to rig site to allow / facilitate the utilisation of the circulating packer.
• Ensure that back-up is available at the rig site for all shoe track components - including spare joints with couplings backed-off and pre-thread locked plus a spare shoe joint and float collar joint pre-assembled, plus spare loose couplings.
• The first 4 connections must be thread locked.
• The Drilling Supervisor must specify in his Instructions to the Drilling Contractor the slip to slip running speed which is to be used.
• The Drilling Supervisor must ensure that as the casing is being run the actual string weight is plotted against the theoretical profile at the rig floor and cross checked by the mud logger. Any deviation should be reported immediately to the Drilling Supervisor.
• The mud engineer is to monitor displacement for losses.
• Wash down last joint. Leave 3m rat hole. Note down final landing weight in Daily Drilling Report.
• Check casing left on rack against tally when planned casing setting depth has been reached. Accountable persons will be the DSV and the Toolpusher who will independently verify the correct casing setting depth.
• Ensure mud pump suction strainers are checked and cleaned prior to cementing, to achieve maximum pump efficiency during displacement.
• The casing string will be supported in the elevators during the cement job.
• Circulate at least 150% of the casing volume.  Ensure to calculate the equivalent flow rate to achieve drilling ECD.  Stage up the pump rates in increments until the ECD when drilling is reached.
• Rig down casing running equipment.

Loadout lists for 30", 20", 13 3/8", 9 5/8", 7" casing operations

Read more …

Example - Set up to run casing, with mud loggers monitoring pit gains.

• Run csg: 
  • Float Shoe
  • jt #1
  • Float Collar
  • By-pass Baffle
  • jt #2
  • shut-off baffle
  • jt #3 . . .Jt #83
  • DV tool
  • Jt # 84. . . Jt #177
  • leave jt. #178 out
  • run jt #179 (last joint)
• Expected stickup: 2.45 mtr.
• Centralizers on ·Mid jt #1, ·jts #1, 2, 3, 4.
• Casing shoe at 407 will be passed while running jt #30.
• Switch to 350-Ton elevators after 40 joints.  Senonian Salt will be entered while running jt #45.
• Cmt Basket on Jt #82, ·centralizer on jt #83, ·DV tool in box of jt #83, ·Centralizers on #84 - #97, 99, 101, 149, 177.
• Record string weight ________ mt as compared to 142 mt theoretical.
• Circulate 1 ½ times annular volume: 690 bbls, 5850 strokes, at 70 stk/min, 85 min.
• Install plug dropping head and load 1st Stage shutoff plug if not already done.
• Close valves and test lines to 3500 psi.
• Open valve and pump:
• See chart for tracking volumes**
• Bump plug to 1400 psi over circulating pressure.
• Check floats.
• Open DV tool by dropping bomb, wait 15 min, and pressuring up to 1000 with cementer.
• Circulate 4 hours at 50-70 stk/min.
• Load 2nd Stage sealing plug.
• Open valve and pump:
• See chart for tracking volumes**
• Bump plug to 1000 psi over final circulating pressure for 2 minutes.
• Check floats.

4.5" Liner Running Checklist

• Pre-job planning meeting with all key personnel.
• Refer to Tubular supplier Guidelines.
• Liner weight and displacement graphs to be prepared.
• Pip tags to be available prior to running liner.
• Back up shoe, float and landing collars should be available on location.
• Make sure to drift DP in the derrick during the running of the liner in order to eliminate the possibility of having any debris as well as plugging the pipe.
• Ensure Gauge the OD of the liner drift provided by Weatherford and confirm with the Operations Engineer that the dimension is acceptable. OD certification should not be older than 12 months.
• Randomly selected ten joints of liner should be internally callipered to accurately determine internal volumes. Use the average ID to calculate displacement volumes. Obtain an accurate measurement of mud pump efficiency for pumping cement.
• Shoe jt, float collar jt, single joint and landing collar joint to be laid out on top row of liner.
• Confirm reamer shoe design with Operations Engineer.
• The displacement will be made with the cementing pumps, using a dedicated tank. Ensure pump is fully charged prior to displacement and total volume recorded.
• Mud loggers to calibrate pit volume indicators and ensure accurate records of pit volumes are maintained throughout liner running and cementation.
• Liner cementing head on location. Confirm with Operations Engineer the following:
  • Correct size of pump down plug has been loaded into the Plug Dropping Head Assembly
  • The phenolic setting ball has already been inserted in the ball dropping sub.
• Calculate space out and make up cementing system ensuring there is adequate space for string manipulation. Lay out on catwalk.

Read more …

• Check casing hanger made up to full length casing joint to facilitate easier handling.
• Check correct length dedicated landing joint (buttress box top conn.) to screw directly into cement head.
• Check cement head set up for buttress thread.
• Casing pup joints need to be a minimum of 3m in length for the Overdrive system.
• Check spares for pick up/lay down machine. Hydraulic hoses, crimping machine etc.
• Check auxiliary equipment for pick up/lay down machine e.g. correct hooks for casing size and extensions for short tubulars.
• No need to have the back up casing tong on the rig floor (free space).
• Mobile telephone signals can cause interference with the JAM unit – ensure mobile telephones are not present on the rig floor as per Company policy.
• The OverDrive system must be laid down and 500T elevators installed prior to making up BJ/Halliburton cement head. This will allow casing to be landed whilst maintaining pressure if floats fail.

Rig up checklist

• Rig down the rig elevator and bails, make sure the Hawk jaw tong has been laid out
• Remove the saver sub using the pipe handler of the top drive (rig procedure). Check the make-up torque setting of the pipe handler prior to removing the saver sub. Verify that the pipe handler stays inline with the top drive main shaft.
• Ensure that the top drive shaft is aligned with the rotary table centre. Ensure that the pipe handler is dressed correctly to grip the top connection of the OverDrive.
• Lift the JAM equipment to the rig floor. Rig up the JAM equipment simultaneously with the OverDrive tool.
• Bring the service loop container including the control panel and all of the additional service equipment to the rig floor. Install horseshoe bracket onto the service loop and lift into the derrick approx. 15m with a safety sling between the horseshoe bracket and the derrick.
• Prepare lifting equipment for OverDrive tool. Use 2 soft slings or cables with 9 ton capacity each sling (6 – 8m length).
• Install lifting cap into top connection of OverDrive. Tighten one sling around the top of OverDrive tool. Secure the slings against sliding and lift the OverDrive tool to the rig floor
• Connect lifting slings from top drive to lifting cap or connect drill pipe elevator to lifting sub. Transfer OverDrive tool from horizontal to Vertical using top drive and crane.
• Remove rotary cover and bottom sling and lower OverDrive into rotary. Disconnect lifting slings/drill pipe elevator, remove lifting cap/lifting sub. Check the alignment of the pipe handler to the top drive shaft.
• Lowering top drive, slowly spin in connection while making up to OverDrive actuator. For safety, use paint marker to place a vertical line across all connections in the load path for visual reference.
• Install the link tilt bail arm extension and the single joint elevator. Made up fill up tool 1000ft*lbs and install mud saver valve to the fill up tool.
• Install FMS into the rotary and check all equipment
• Pick-up a joint of casing and set into the slips, pick-up second joint and set into the first joint
• Calibrate the JAM system connected to the top drive against JAM system connected to a manual back up tong and TorqSub.
• Casing tongs keep as a back-up.

• Is the T/A consistent with the hanger nipple and with the P-seals?
• Do you know the hanger nipple serial number?
• Do you know the tubing M/U torque?
• How many turns to close the SRT rams? (Check the number of turns required to close the SRT rams while the crew is testing the line to 600 bars).
• Measure the distance RT / Hanger nipple while the tubing is pulled at the beginning of the workover.
• Have you measured all the parts required to run the completion (landing joint, X-Over, Running tool, ...).
• Has everything been drifted?
• What are the distances NRT / SRT and SRT / TBF?
• Are the following equipment on site?

•  
  • Cntrol line
  • Metal band
  • Control line protectors (how many?)
  • P-seals
  • Test ring for control line

• During the job:

•  
  • Record weight up/down
  • Record how many protectors and metal bands are used

• Hold Toolbox talk on rig floor, to advise all rig-personnel involved of the objectives, summary of the running procedure, and to discuss any particular care or safety concerns.
• Company Man and Mud Logger to prepare Liner Weight + Metal Displacement Diagrams.
• Pick up shoe-track sub assemblies and perform floating equipment test.
• Install pip tags in liner joints, as per programme. The pip tags should be wrapped with Teflon tape prior to DOPE and M/U.
• Pick up the Liner Hanger assembly very carefully to avoid right hand torque.and make up to the 7” liner. Leaving rotary slips set on liner joint pick up approximately 1m to check setting tool and all connections are properly made-up.
• Fill PBR with clean brine or fresh water before running in hole.
• Pull slips and lower assembly through rotary and set DP slips on the setting tool extension at the top of the running tool.
• Pick-up Liner and circulate 120% of the liner content, check for leaks on the Liner Hanger assembly with the assembly above the rotary table. Do not exceed maximum circulating pressure 900psi (62 bar).
• Record pick-up and slack-off weight of liner. Report in DDR.
• R.I.H. with liner on drill pipe, release the lock of the block and fill up.
  • Running speed should be 2 - 3 min/stand.
  • NO Left Hand Rotation. This can release the running tool from the liner hanger.
  • Circulation will only be carried out if difficulty is encountered whilst running in hole. *Absolute maximum of 5 bbls/min or 900psi, whichever is least.
  • Do not “bump” against the back-up tong.
  • Pipe dope to be applied sparingly using a paintbrush – to DP pin end connections only.
• With the liner assembly shoe at the 9-7/8” casing shoe:
  • Break circulation and check free circulation through the liner assembly. Circulate minimum volume of Liner + Drill Pipe contents. Do not exceed 900psi (62 bar) Maximum circulation is based on the Liner Hanger shear setting value with absolute maximum of 5 bbls/min or 900psi, whichever is least.
  • Closely monitor for static and dynamic losses and record (Fluid Engineer).
  • Record the weight-up and weight down.
  • Start rotating the string at 20 and 30 RPM and note torque readings.
  • Maximum allowable torque 15 Kft.lbs at surface. (If higher inform Drilling Engineer before proceeding).
• The liner must be set about +/- 0.50m from bottom. Wash down last stand. Tag bottom with no more than 10 tonnes.
  • Record the up and down weight.
  • Pick up to neutral rotating weight, mark the pipe and pick up a further 2m.
  • Rotate the string at 20 and 30 RPM and note torque readings.
  • During rotation circulate bottoms up as a minimum (ensure that the circulating *pressure does not exceed 900psi (62 bar).We can exceed pressure to 1200 psi.
  • *Stop rotation.
  • *Spaceout and rig up cement head. Make sure swivel is used on the end of the cement hose to the cement head and hose weight is correctly supported.

LINER hanger setting procedure

• Pressure test the surface lines to 5,000 psi (350 bar). This is based on value of 2,600psi (183 bar) ± 15% to shear out ball seat (3100 – 3800 psi)
• Place indicator on Flag Sub to ‘Down’ position to minimise possibility of ball being held up on indicator lever.
• Release ball and pump ball to seat in Landing Collar. Confirm release. Return indicator on Flag Sub to ‘Up’ position. If setting ball fails to seat, surge pump in attempt to remove debris from ball seat.
• When the ball seats, pressure up to 1800 psi. Pre-set setting pressure of liner hanger is 1,400 psi ± 15% (± 100 bar). To confirm the liner hanger has set, bleed off pressure to 1,000 psi (± 70 bar) and slack off liner weight and a minimum of 50 Klbs (25 tonnes) of drillpipe.
  • Pipe should be carefully marked and measured at all points in these operations.
• If the hanger fails to set:
  • Increase setting pressure in increments of 10 bar.
  • In case of debris around slip area, bleed back pressure to 500psi & rotate string at 30-40rpm for 1 – 2 minutes.
  • When the setting pressure gets to close to 80 % of the shear value of the running tool, bleed off to zero and repeat the setting sequence.
  • Confirm liner hanger has set .
  • If the hanger still has not set, pick up 0.5 m above previous setting depth and repeat.
  • If not set at this point, place Hanger at setting point (Ensure running tool is in Tension), and increase pressure to 2600psi. Bleed back to 1000psi and check for set

LINER hanger release procedure

• Shear out ball seat, with a minimum of 50 Klbs (25 tonnes) of drillpipe weight onto the liner. Expected shear 2,650psi ± 15% = 2,990 psi maximum.
  • Pre-set shear value of the running tool is 2,030 psi ±15%
• Pick up tool string to 1 m to check if setting tool has released. If yes, slack off weight 50,000 Ibs
• If the running tool cannot be released hydraulically, the backup mechanical release mechanism can be used as follows:
  • Ensure tool is in compression.
  • Apply left hand (counter clockwise) torque to the tool. This torque acts to shear two brass screws which shear at 4,650 ft.lbs. ±15%.
  • NOTE: Hole conditions may require movement of the Drill pipe to "work" the torque down to setting tool.

• Pick up string and observe loss of liner weight to confirm tool release.
• Note the running string weight when released.

• Pre-job planning meeting with all key personnel.
• Reference Manufacturer Operations Guidelines.
• Discuss with LWD coordinator during pre-phase meeting regarding download memory data from LWD on last run to lay down tool instead of leaving tools hanging.
• Check if modified thread compound in compliance with API 5A3 (e.g. Lube Seal API Modified) is available as it is recommended to be used during winter season, it is required the use of a power tong equipped with load cell and hydraulic fluid suitable for extreme cold weather conditions.
• Apply 70% of recommended thread compound quantity on pin and 30% on box covering full thread area, seal surface and torque shoulder.
  • * Note: for 3SB-ST connections to avoid over doping in cold weather apply dope as normal to pin but only to seal area of coupling.
• Liner weight and displacement graphs to be prepared.
• Torque and drag graphs to be prepared.
  • * Confirm required overpull capability
  • * Pick up 5 ½” S-135 DP (typically 400-500m) as required.
• Aluminium spiralizers will be used.
• Pip tags to be available prior to running liner.
• Use short bails when running 7” casing to help casing centred and not swing when stabbing into box.
• Back up shoe, float and landing collars should be available on location.
• Gauge the OD of the liner drift provided by Weatherford and confirm with the Operations Engineer that the dimension is acceptable. OD certification should not be older than 12 months.
• Randomly selected ten joints of liner should be internally callipered to accurately determine internal volumes. Use the average ID to calculate displacement volumes. Obtain an accurate measurement of mud pump efficiency for pumping cement.
• Complete tally of 7” liner and space out the liner to be set ~0.50 m from well TD.  Refer to 9-5/8” casing tally or CCL to confirm that setting depth of hanger does not place hanger slips or packer element across a casing coupling.
• Confirm reamer shoe design with Operations Engineer.
• Confirm pup joint x/o to connect straight from the Top Drive to the cement assembly is available.
• The displacement will be made with the cementing pumps, using a dedicated tank. Ensure pump is fully charged prior to displacement and total volume recorded.
• Mud loggers to calibrate pit volume indicators and ensure accurate records of pit volumes are maintained throughout liner running and cementation.
• The liner string will be rotated while cementing to ensure good cement bond in the liner annulus. Note liner make up torques below.
• On the rack attach each solid Aluminium spiralizers with 2 x stop collars as follows:
  • * One aluminum spiralizer per joint over shoetrack.
  • * 1 Aluminum spiralizer per joint from ~5106m to ~5050m. Ensure alternate flow direction on alternate joints.
  • * 1 Aluminum spiralizer per 2 joints from ~5050m to top of liner. Ensure alternate flow direction on alternate joints.
• Liner cementing head on location. Confirm with Operations Engineer the following:
  • * Correct size of pump down plug has been loaded into the Plug Dropping Head Assembly
  • * The phenolic setting ball has already been inserted in the ball dropping sub.
• Calculate space out and make up cementing system ensuring there is adequate space for string manipulation. Lay out on catwalk.
• Three DP pup joints of different lengths to be laid out on catwalk.

Unable to reach setting depth with liner

The liner hanger starts to set at approximately 1,400psi / (100 bar) differential pressure. Take care that circulation pressure does not exceed 900psi / (62 bar).

If it takes more than 900psi / (62 bar) pressure to circulate. Make sure that the Liner hanger is in tension before increasing the pump pressure above this value.

To wash liner through a tight spot the following steps are to be taken:

1. Pick up string.
2. Start circulation and check weight of string up and down. Watch pressure closely (keep somebody regulating the pump).
3. Slowly start rotation. When circulation is established slowly lower string through the tight spot, making sure that circulation pressure stays below 900psi / (62 bar) pressure. Watch pressure and torque readings carefully.
4. Do not slack off more than 40 Klbs (20 Tonnes) onto liner weight while rotating. If slack off weight is reached, work string up and down through tight spot and continue.

Liner setting Ball doesn’t seat

1. Drop the Bronze ball
2. Rapidly fluctuate the pump pressure to generate pressure surges at the ball seat.
3. Set mechanically on bottom.

Liner setting Ball seat doesn’t shear

1. Go to 80% of casing burst pressure = 8,500 psi / (600 bar)

2. Pressure up and bleed off over 10 cycles

3. Prepare a Contingency plan that should consider these main operations:

• POOH and drill out shoe track.

• Cement through the shoe with cement retainer or retrievable packer with a packer setting dogs sub higher in the string.

• Consider setting ‘ZXP’ Liner Top Packer on a second trip using modified Packer Setting if scan liner is not run .

Liner running tool doesn’t release

1. Ensure tool is in compression of 20 klbs (10 tonnes) minimum when putting in turns and repeat left hand rotation cycles.

2. Maintain left hand torque and work pipe between maximum string up weight (before hanger was set) and set down weight (after hanger was set)

3. Continue working pipe while reciprocating.

4. Leave workstring in tension and circulate.

5. If nothing is solved, prepare a contingency plan that should consider these main operations:

• Chemical Cut on DP

• Fishing

Liner Plug does not bump

1. It is important to ensure cement is not left within the latch couplings.
2. Stop pumps at agreed displacement (e.g. 75% of total shoe track volume) and release setting tool.
3. Pick up workstring and set ‘ZXP’ Liner Top Packer as per procedure.

Losses are observed during liner cement job

• Reduce flow rate (considering Thickening time).

• Set ZXP Liner Packer anyway and continue as per programme.

Liner Packer setting dogs do not engage top of tieback extension

• Pick up workstring to point where dog subs are exposed above the tieback extension.

• Set down again.

• Pick up workstring and rotate drill string to free any cement from around dogs.

• Set down again.

• If engagement is still not possible, circulate to clean dogs.

• Re attempt to set.

• Still no success. POOH, Set ZXP Liner Top Packer on second trip with modified Packer Setting Sub or tie back packer if scab liner is not run.

ZXP Liner top packer fails positive pressure test

• Attempt to fully set packer on second trip with modified Packer Setting Sub.

• If pressure test is negative and leak at liner top is suspected, a contingency liner top isolation packer will be installed if scab liner is not run. Separate detailed procedure for this contingency operation will be prepared in due time.

ZXP liner packer setting procedure

1. Pick up +/- 3m to locate mechanical setting dogs on top of Tieback Extension.

2. Slack-off minimum 10 Klbs (5 tonnes) and mark the pipe. Continue to slack off weight for a minimum of 50Klbs. Monitor weight indicator for shear indication (two shears may be observed). Hold for 5 minutes to ensure complete setting of packer.

3. Pick up to up weight and set down 10Klbs. Observe mark on pipe. If mark has moved down approx 9”, this is an indication of the packer functioning.

4. Do not perform any annular pressure test at this stage.

5. Pressure up drill pipe to 500 psi (35 bar) and pull running tool inside PBR and Long Way circulation whilst inside the PBR.

NOTE:  String to be pulled slowly due to observe the pressure loss to indicate the RPB pack off bushing has been retrieved from ‘RS’ seal bore.

Lay down plug dropping head and POOH.

Preparation Checklist

• Ensure the Cement Program has been received. Calculations of cement quantities and volumes should be checked by both the Drilling Supervisor and the cementing operator. Compare job duration with thickening and compressive strength development times. Check design temperature.

• Discuss with rig team the contingency plans for failure of float equipment, losses and packing off during the cementation.
• Check that casing is secured before starting the cement job.
• The slurries have thixotropic properties (high YPs) so it is important to keep pumping, even if only at a low rate. Once pumping has stopped it will be difficult to get the slurries to move again.
• Cement stinger will need to be tied-down to prevent pump-out during the cement job.
• The cement mix fluids for the lead and tail slurries will be prepared in two separate batch mixers.
  • This must be done before the casing has reached bottom. It is better to dump the mix water than to have the rig waiting for mix water to be prepared.

• The annular excess volumes will be 100% for the lead cement slurry and 25% for the tail cement slurry based on experience of the previous cemented surface casings.

• The spacer is to be prepared in the rig slug pit and final surfactant added while circulating at TD.
• Both cement slurries will be mixed on the fly and pumped at 3 bpm (plug flow displacement). This rate is sufficient to allow the cellar pump to transfer the returns and prevent the cellar form overflowing.
• If the lead cement does not reach surface (losses), or the top of the cement drops in the annulus, a top up job will be performed using a fast setting 1.9 sg slurry, accessing the annulus with a spaghetti pipe. This job should be done off the critical path.
  • Ensure spaghetti pipe is readily available for performing a cement top up job.
  • Ensure a cement program for a top up job is available on the rig.

• The job is designed so that the maximum ECD will not exceed 1.64 sg at the 20" casing shoe and 1.52 sg at the 30" casing shoe. The effective casing weight will be positive under static and dynamic conditions with 1.05 sg mud in the 20" Casing x Drill Pipe annulus.

• If losses are seen during the drilling the section, thixotropic cement can be considered.
• Check the hook up of the transfer pump from the cellar to the waste disposal tank to take returns during cementing.  Run a clean-up line to the rig floor in the event pumping is stopped and the slurry needs to be cleaned out of the surface lines.

Sequence of Operations

• Pump string volume to ensure it is not plugged up.
• Stab-in.
• Fill 30" X 5" annulus, if necessary, and monitor fluid level to ensure inner string is not leaking.
• Circulate at least 1.5 x annular volume while monitoring returns to ensure hole is clean and is not packing off.
• Hold a Pre-Job Safety Meeting whilst circulating.  Personnel must be made aware of their responsibilities, understand the job sequence, pressure limits, communication signals for opening/closing valves, etc.
• Prepare 6 m3 of spacer while filling the cement unit displacement tanks with Technical Water.
• Fill the cement lines with Technical Water (1 m3) and pressure test lines to 3000 psi for 10 min.
  • During winter months use saturated brine instead of technical water

• Bleed off pressure and pump the spacer at 3 bpm

• Mix and pump 1.5 sg lead slurry at 3 bpm.  Take representative cement slurry samples, label and place in oven or waterbath set at bottom hole temperature.
• Once the lead cement slurry returns reach 1.45 sg, switch over to the tail slurry. This will ensure that by the time the tail slurry has been displaced, the returning cement slurry will have a density of 1.50 sg, without pumping excessive volume of lead cement slurry.
• Mix and pump the 2.0 sg tail slurry at 2 bpm. Take representative cement slurry samples, label and place in oven or waterbath set at bottom hole temperature.
• Add sugar in cellar on noticing cement. Use vacuum truck to remove returns from cellar.
• There should be minimal pressure throughout the displacement of the cement, if pressure starts to rise suddenly, shut down pumping and investigate. If the problem is due to a restriction in the annulus, attempt to pump the tail at reduced rate. If the job can’t be completed, a top job will be performed later.
  
  • Note: Max pump pressure should not exceed 300 psi throughout the job. The casing collapse pressure is 520 psi.
  • Mud Engineer should be near cellar area during the cement job to record return slurry weight and also monitor 20” casing for stinger seal leak. Make sure sugar bags are near cellar (require at least 6 large bags of sugar).

• Displace cement in the inner string with technical water or saturated brine (winter months), using cementing unit. Leave +/- 15 m inside DP.

• Purge the cement line to the cement unit displacement tank and monitor returns. If the float does not hold pump back the returned volume and shut in the cement line and monitor pressure. When the cement start to set the pressure should drop off.
• If no returns, sting out and observe for 10 min the level in the casing to confirm float is holding. If the float doesn’t hold, sting back in, with cement line closed at surface and wait for another +/-10 minutes.
• Flush 1.5x DP volume and POOH cement stinger.
• Install the Wear Bushing.

Notes:  If losses during cementing

• If losses occur after cement has reached surface, complete the job and a top job will be done later on.

• If total losses occur during the cement job, reduce the mixing and flow rate of cement and check for improvement.
• If the situation improves, complete the cement job as planned.
• If cement has not reached surface, a top job to fill up the annulus will be performed later.

• Perform tool box talk.
• Ensure the information below is known before starting the 13 3/8” cement job:
  • The expected stand pipe pressure and ECD at different stages of the cement job.
  • The predicated fracture gradient at the 13 3/8” shoe.

    Read more …

PRE-JOB Checklist

• Water sample sent to town for analysis
• Pre-job safety brief held with all parties
• Bottom hole temperature from logs consistent with norm and relayed to cementing Company
• Caliper run.  Is hole under/in/overgauge
• Casing drifted, threads clean, consumables in place as per program
• Strokes to bump
• Plan to monitor returns/ losses
• Contingency for losses - minimum turbulent flow, maximum laminar flow
• Open-hole excess volume determined
• Cement and additive stocks sufficient
• Chemical inventory before slurry and spacer preparation.
• Has the Cementer been told how much excess mixfluid should be available?  i.e. calculated volume + tank dead volume + contingency
• Cement truck checked out and run recently
• Cement calculations done by at least 2 people and cross checked
• Spare chicksans available on floor or catwalk
• Plug dropping head and plugs inspected.  Operation of tattle-tail last time, serviced, working
• Loading of PDH witnessed by Drilling Supervisor. Valves secured
• Strokes to bump plug and strokes to fill pipe calculated
• What is the plan for handling fluids at surface.  Can pits be isolated – suction & return.  Mud Engineer and Mud Loggers clearly briefed
• Radios checked
• Stroke counter functioning OK
• If displacing with rig pump, use one pump only.
• Double the chemical requirements calculated available.
• Check water to be used (salt content is too high/ Mg level to avoid 'flash setting').
• Set the oven to the test temp. before the job starts.
• Discuss the complete job when contractor arrives on site.
• Be present when the cement chemicals are being added to the water. Take two samples of the mixwater (usefull if a problem occurs).
• Calculate:
  • 1. the volume and strokes to cement equalised and bump.
  • 2. the expected differential pressure at bump.
  • 3. based on the planned height of cement in the annulus estimate the pressure just before bump.
• Litecrete: re-blend and test the dry blend cement at the rig.
• Litecrete: “more” mix water must be prepared.
• Preprare several copies of the cement program Make a list of people who should have one.
• Cement samples sent to town
• Have cementers check stock for next casing job

JOB PLANNING Checklist

• BHST and BHCT consistent with recipe
• Spacer’s compatibility been checked
• Is fluid loss additive required? It is cheaper to use standard LCM in the spacers rather than in the slurry.
• If a new system is introduced, has a sensitivity test been done?
• Are the spacers recommended cost effective
• Is free water acceptable  (high angle cementation only)

DURING JOB Checklist

• Note times of arrival of contractor and other significant times during the job (floor handed over to contractors, pressure testing of lines, plug dropped, bumped etc.).
• Have with you the program and the pre-calculation, a calculator is also advised.
• Set up non-oral method of to advise cementer of slurry densities whilst mixing
• Use rig personnel to assist with monitoring job
• Sampling: - take two samples of final slurry, one to be placed in the oven and one outside. For 'on the fly' take four samples, two in and two out of the oven.
• If a tail slurry is planned take 2 samples also.

AFTER JOB Checklist

• Prepare a cement job report and send to Drilling Superintendent
• Have cementers rig down equipment as soon as possible
• Insure that personnel do not remain on the wellsite if not required.
• Confirm chemicals used and returned.

• Completion Engineer to organise pre-job planning meeting at the rig site, with rig and office personnel to discuss the job objective and hazards.
• Prior to displacing well to a completion fluid, ensure that catch cans and trip tank are clean. Flush choke and kill lines from any loose debris. Wash BOP and pull wear bushing then wash BOP again; this operation should be witnessed by DSV.
• If possible when performing clean out for 7” liner, the drill pipe string can be laid down in single while pulling out of hole to minimize Invisible Lost Time.
• Confirm that all completion sub-assemblies, tubings and tubing hanger equipment with a back-up assembly is on site and suitable for use and has appropriate certification. (All downhole completion equipment shall be made up as sub-assemblies and pressure tested as per Company pre-assembly procedure before sending to Rig site).
• Ensure steamer is used to make ensure the side valves not frozen when running in the NBP pulling tool as the side valves on the well head could be frozen and the fluid could not be drained from the stack.
• Ensure suitable pipe dope is utilized.
• Ensure a back up control line is on the rig site.
• Ensure that the socket of clamp for control line not loose. Covered hole when torque up clamps of control line.
• When picking up the block make sure to pick up slowly so the control line not to slip off the Schlumberger reel.
• Ensure that sub-assembly records also have been delivered with the sub-assemblies and are correct.
• Drift and measure all tubings and sub assemblies with appropriate drift and tally tape.
• Function test the safety valve assembly at the well site. Company representative should witness.
• Ensure that all well control x-over subs for each type of tubing connection are available at the rig floor.
• Ensure that all tubing handling and running equipment (slips, elevators etc.) and the circulating head are available.
• Ensure that the BOP ram configuration is correct for the tubular to be run.
• Ensure that enough quantity of brine or water is available into the mud pits (150% of hole volume)
• Ensure that enough quantity of Glycol is available at rig site. Consider excess volume according to the amount of losses.
• Discuss during pre-job planning meeting the method of pumping anti-freezing mixture before or after performing PCE test.
• Prepare tubing running tally for running the completion string. A copy of the tally should be available on the rig floor during running. The tally shall be cross checked by the Rig supervisor and Toolpusher.
• Make sure that the correct torque data is entered in the software and scale of the graph is agreed with Company representative onsite.
• Tubular manufacturer representative will be at rig site to supervise the running of tubing, inspect, accept and sign off the graphs.
• Check if Expro pumping Tee is made up with crossover (Flange), if not this can be made up off line.
• Slickline service should be called and equipment required should be prepared as per completion program. The lubricator and X-over assembly should have been prepared in advance at the location before the slickline operations.
• Ensure that 1m 5 ½”, 23#, TN-MS pup joint is available at rig site, this will be used for making up with Expro pumping-T in order to allow the tong to grab the 5 ½” pup joint body. Also, make sure that there is enough space out so that Manual Gate Valve handle of pumping-T can be reached.
• Make sure that all the required slickline equipment including all x-overs is available at the rig site.
• Always monitor composition and weight of completion fluid at regular intervals and maintain the required levels in the tubing and annulus.
• Ensure that the tubing hanger seat is clean prior to running in hole and pre-test to energizing the hanger to confirm things are in working order.

This article describes the following checklist for completion equipments:

1. Completion Equipment Preparation Checklist

2. Well Site Preparation Checklist

3. Make up/ Running Check Procedure

Read more …

1 Objectives

• No harm to people or damage to the environment or equipment.
• Make up and run production tubing along with all down hole equipment first time and with full pressure integrity.
• Correctly space out of the completion and ensure the tubing hanger can be run, landed, locked and tested on first attempt.
• Ensure that safety valve lines are terminated successfully at tubing hanger at first attempt.
• Production packer to be set and tested on first attempt.
• Suspend the completion in a safe manner meeting barrier policy.

Ensure Company two barriers policy is always in place during the entire completion running operations.

All depth measurements to be referenced to RKB through the first flange of the well head.

Make sure that COMPANY procedures on storage, handling, running and pulling for low alloy steel premium connection for both tubing and casing are followed.

Note: X-Tree to be installed after the rig move

2 Completion Preparation Checklist

• Confirm that all completion sub-assemblies, tubings and tubing hanger equipment with a back-up assembly is on site and suitable for use and has appropriate certification. (All downhole completion equipment shall be made up as sub-assemblies and pressure tested as per COMPANY pre-assembly procedure before sending to Rig site).
• Ensure a back up control line is on the rig site.
• Ensure that sub-assembly records also have been delivered with the sub-assemblies and are correct.
• Drift and measure all tubings and sub assemblies with appropriate drift and tally tape.
• Function test the safety valve assembly at the well site. COMPAY representative should witness.
• Ensure that all well control x-over subs for each type of tubing connection are available at the rig floor.
• Ensure that all tubing handling and running equipment (slips, elevators etc.) and the circulating head are available.
• Ensure that the BOP ram configuration is correct for the tubular to be run.
• Ensure that enough quantity of brine or water is available into the mud pits (150% of hole volume)
• Ensure that enough quantity of Glycol is available at rig site. Consider excess volume according to the amount of losses.
• Tubing preparation and running will be performed as per COMPANY procedure.
• Prepare tubing running tally for running the completion string. A copy of the tally should be available on the rig floor during running. The tally shall be cross checked by the Rig supervisor and Toolpusher.
• Make sure that the correct torque data is entered in the software and scale of the graph is agreed with COMPANY representative onsite.
• Tubular manufacturer representative will be at rig site to supervise the running of tubing, inspect, accept and sign off the graphs.
• Slickline service should be called and equipment required should be prepared as per completion program. The lubricator and X-over assembly should have been prepared in advance at the location before the slickline operations.
• Make sure that all the required slickline equipment including all x-overs is available at the rig site.
• Always monitor composition and weight of completion fluid at regular intervals and maintain the required levels in the tubing and annulus.

3 Sequence of Operations

1. Hold rig site pre-job meeting prior to starting completion operations.

2. Pick up clean up BHA and RIH to bottom; scrape packer setting depth. Ref appendices.

3. Clean out wellbore. POOH.

4. RIH completion as per tally to the packer setting depth.

a. Run Tail Pipe & Packer assembly

• Detailed Running list of completion string should have been prepared and all attached to the specific well completion program before running. It shall contain the cumulative depth as running in hole for “slick line tubing drift runs”.
• Ensure crossovers for well control are available during running completion.
• During the “tool-box” talk highlight that Driller needs to check if the sub-assy top Pup Joint is free to rotate from the elevator, before making up any sub-assembly.
• During RIH of sub-assemblies, get confirmation from the Driller that the sub-assembly is free to rotate from Elevator.
• The running speed of the completion string shall be one minute per joint (once in 7” liner reduce the speed to 1.5 minutes per joint).
• Use collar clamps for the first 10 joints until enough string weight is obtained.

b. Slickline Drift Run

c. Run Tubing & Downhole Equipment

• Make sure that prior to making up the x-over assembly all left over tubing has been counted and cross checked against the running tally.

d. Run 5 ½” Tubing

• Extra care is required when entering the liner hanger since it might hang up during passing.
• Reduce the speed to 1.5 minutes per joint.
• The driller has to pick up out of slips and RIH smoothly and gently to avoiding shocking wall cake.

e. Run & Function Test Safety Valve

• Ensure that a hole cover is used all the time while working over the rotary table.
• Flush line with supplied Hydraulic Fluid and test the connection to 10000psi for 10 minutes
• Two cycles of Opening & Closing shall be performed in order to have a reference test. The same thing will be repeated immediately the tubing hanger lands and after cutting the control line. The final test will be reported on the proper “Installation Report for TR-SCSSSV” and added to EOWR.
• Care shall be taken while setting the slips as possibility exists to damage the control line.
• Whilst fitting and securing the cross coupling clamp ensure the control line is in the correct groove and is not crushed between the clamp and the tubing.
• ake sure that prior to making up the tubing hanger sub assembly all left over tubing has been counted and cross checked against the running tally.
• Before continuing with the program, COMPANY Well Completion Engineer or Halliburton Completion Engineer with Tenaris representative, must verify that the final recording graphs for the entire tubing string make-up torque are within the manufacturers tolerance.
• Flush and clean the hanger seal area.

5. Land the tubing hanger assembly.

• Confirm rig alignment.
• Ensure tubing spool side outlets are open.
• Keep the TR-SSSCV in open position and to avoid contaminating the control line fluid install at the extremity of the control line the proper needle valve, retaining 4000 psi.
• All the test charts will be signed by COMPANY representative and copies will be sent to Completion Engineer.
• Keep in consideration that the packer has not yet been set. When the tubing hanger has been landed there is no longer any hydraulic continuity through the BOP kill/choke lines and the bell nipple, for this reason need to make sure that the annulus is always topped up through the annulus valves.
• Prepare 2400 l. of 50% glycol mixture.

6. RIH and set RPT plug and prong in the 3.562” RPT nipple below the packer

• The following relation shall be considered in order to keep the Safety Valve open especially when the slickline cable is in the well.
  Pressure control line = Opening Press + Tubing Pressure + 500 psi (safety margin)
  For Halliburton SP, the Opening pressure @ zero Tubing Pressure is 2000 psi.

7. Pressure up tubing to 4000psi and set the packer as per manufacturer’s recommended procedures.

8. Increase tubing pressure to 7500psi for 30 minutes to test string

9. Pressure test annulus with 3000psi for 30 minutes in order to test packer

• In tight formations (if in static condition we have 0 m3/h fluid losses), always pull prong before to pressurize the annulus to 3000 psi and check for any return from the tubing. Then reset prong and pressure test tubing to 5000psi.

10. Remove Landing Joint

• Particular attention is required in order not to damage the Control Line at this stage. KIOS must witness this.

11. Install TWCV.

Two independent barriers (policy) must be in place.

The first "mechanical" barrier is the plug used to pressure test the completion.

The second barrier can be either "mechanical" (a second plug in the tubing hanger) or "hydraulic". For a "hydraulic" barrier to be considered an acceptable independent barrier, it must meet the following criteria:

• The fluid density is sufficient to kill the well if the 1st barrier fails,
• A pumping system and sufficient amount of kill fluid is available to maintain the hydraulic barrier for the duration of the operation in case of losses.
• This is a temporary barrier used during the BOP/ Tree operation only (i.e. this is not a long term solution).

On the annular side the 2 barriers are provided by the packer and the tubing hanger.

12. Nipple down BOP’s.

• Particular attention is required in order not to damage the Control Line at this stage. KIOS must witness this.

13. Install and test tubing head adapter as per KIOS instructions.

• If the TRSV is not open at the first attempt (pressurizing the control line), bleed off annulus pressure from 300 psi to zero and repeat the function test.
• Being the 3.562” RPT plug still set in the nipple, particular attention is required to open TRSV since there should be pressure trapped below the flapper. Pressure-up CL as for manufacture’s instruction, then pressure up tubing till there would be an indication that TRSV is open.

14. Nipple-up the Integral Lower Master Valve. The X-tree to be installed after rig move.

• Be sure that the gearbox of the lower master valve is rotated 180 degrees with respect to all the other WH and X-tree valves.

15. Clear rig floor and cellar area and release rig.

4 Appendices

Casing Scraper Run

1. M/U BHA (see table above)

2. Put Bakerlok on top dress mill face to act as indicator when mill is retrieved

3. RIH and space out mill with 7” tie back and top dress mill

4. Take up/down/rotating weights prior to entering 7” liner

5. Across 7” scab liner tie-back work with taper mill and string mill with 20 rpm in order to clean the tie back area

6. RIH and Work 7” scraper three times across packer setting depth +/-50m

7. Continue RIH to position Top Dress Mill at PBR and Taper Mill ~90 m above 7” liner shoe.

8. Polish top of PBR with 15 rpm and 1-2 klb WOB

9. Pull back 10m

10. Pump high viscous clean-up pill and displace OBM to inhibited brine

11. Circulate until wellbore is clean as for mud engineer instruction

12. POOH

Note: Environment and safety requires toolbox talk and HS&E meeting with the crew.
Ensure all tanks are line up with to take returns and catch pills, spacers,etc.
Detailed program is as per dedicated Mud Program.

13. Retrieve wear bushing.

14. Pick up well head jetting tool assembly, RIH and jet all BOP area in particular all cavities and also function rams while jetting. POOH, inspect junk basket if full repeat jetting run till clear of junk from BOP area.

15. Confirm rig alignment.

The following checks should be performed before running Downhole gauges:

• Review compatibility of SEM Interface Board with other DHG systems.
• Ability to test Digital Gauges during completion work. . 
• Monitoring of Gauges when running of completion. WGPT to utilise electrical downline with slip rings to allow continual monitoring.
• Raise drill crews awareness of the requirement for operational DHG system.
• Arrange presentation to rig crews.

• Riser centered, secure and flow line leak free
• 26” bit, nozzles & tool on location
• Stabilizers, x/o’s, drill collars strapped, ready
• Totco ring inserted
• Shock sub made ready
• Ultra seal on location, +/- 60bbl pill mixed @ 30-40 ppb
• Mud engineer aware of property requirements
• Sufficient 8¼” drill collars, HWP on rack, strapped.
• Cmt, gel & baryte . Stock on site
• 18 5/8” csg to be drifted, threads cleaned, tally checked, number of joints on rack confirmed and numbered
• Casing OD checked and insert correct size “FS” seals in casing head
• 20 ¾” section “A” casing head and accessories on location.
• Get all casing consumables to location and dress casing as per program
• Float equipment for inner string running tool
• 5” to 18 5/8” centralisers x 2 in stock
• Trip tank pump functioning
• 21¼” BOPE prepared and tested, spacer spool nippled up
• Casing crew  and equipment on notice
• Pick up and lay down service on notice
• Provision for OBM supply in place

This article presents examples of loadout/ equipment list for the following hole section: 36", 26", 17.5", 12.25", 8.5" and 6"

Read more …

Example of loadout lists for 30", 20", 13 3/8", 9 5/8" and 7" Casing,  7" and 4 1/2" Liner                                                                              

30in Conductor Loadout Check List

20” Casing Loadout Check List

Note:  Items 6, 7 and 8 are only required if Mudline Suspension is used

13 3/8” Casing Loadout Check List

Notes: Items 23, 24, 25, 26, 27 and 28 are only required if Mudline Suspension is used.

9 5/8” Casing Loadout Check List

Note:  Items 23, 24, 25, 26 and 27 are only required if Mudline Suspension is used

7” Casing Loadout Check List

7” Liner Loadout Check List

4 ½” Liner Loadout Check List

• Hold a pre-job safety meeting on BHA make up.

• Make up 16” BHA as detailed in well specific programme.
• Ensure a ported float is included in the string.
• Circulate through the BHA and report weight in DDR.
  • Note: If a conventional motor steering assembly is to be used, ensure that the Directional Driller witnesses the correct toolface offset being entered into the MWD computer and a sign off form completed.

  • RIH with 16” BHA and tag stab-in shoe or cement.

• Check pulse from MWD tool and commence displacing the mud whilst drilling out the shoe. Clean up the rat hole and condition mud throughout. Maintain flow rates below 2850 LPM to avoid excessive washout at the 20” shoe.
• Utilise required mud weight from start of section (e.g. 1.5 sg) unless shallow salt well with expected loss zone.
• Drill ahead.  The minimum flow rate to keep the hole clean is 2650 LPM.
• Perform drill off tests to establish optimal RPM/WOB combination.
• Increase flow rate to 3000 – 3400 LPM once the BHA is 15m below the 20” shoe provided losses are not observed.
• On connections wipe the full stand once by pumping out and reaming back down. Wipe the bottom single once by pumping out and reaming back down. The driller must nominate a responsible person to control the mud pumps (e.g DD, Toolpusher, KPO Drilling Supervisor). This person will be responsible for shutting down the pumps quickly in the event of a pack-off.
• Drill ahead to 13 3/8” casing point taking directional surveys approx. every three stands.
  • Directional Driller to monitor dynamic inclination readings and report to Drilling Supervisor if inclination trend will exceed 1.5 deg

• Optimise flow rate (3500-4000lpm) and drilling parameters to maximise ROP and maintain inclination below 2 deg.

• Monitor hole cleaning (SPP, PWD, drag, torque trends)
  • Driller to record up and down and rotating weights for each stand and report divergence from normal.

• Monitor shakers for signs of cavings and pit levels for mud loss/gain. Mud logger to inform DSV immediately.

• Don’t wait for survey after connection - if survey is corrupted continue drilling take survey after next connection.
• Do not make wiper trips unless hole conditions - such as unmanageable increase in torque or drag - dictate. 
• Drill to TD allow 5m rat hole.
• Circulate bottoms up with full circulation (4000 LPM & 90-100 rpm until the shakers are clean.
• Sweep hole with 5 m3 of Baralift pill if required.
• Spot 10m3 of viscosified mud on bottom. This is to ensure that any fill is maintained in suspension, thus making it easier to wash the casing to bottom.
• POOH, perform wiper trip if hole condition dictates.
• The KPO Drilling Supervisor will be on the rig floor from start of the trip out of hole until the string is in cased hole.
• Prior to starting the trip (during circulating bottoms up) check the following:
  • Record up-weight, down-weight, rotating weight and off bottom torque.
  •  Have a single of drill pipe available in the V door.
  • List of tight spots/intervals encountered during connections and previous trips.
  • BHA schematic with measurements between stabilisers and bit.

• Upon encountering tight hole:

  • Go down and re-establish up-weight, down-weight, rotating weight and off bottom torque.
  • Apply overpull - starting with 20klbs - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
  • Apply 30klbs overpull - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
  • Apply 40klbs overpull - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
  • Continue applying the above technique using 10klb increments up to a maximum of the weight of the BHA.
  • If on any overpull attempt, the down drag indicates that the pipe is becoming jammed, then make several attempts with less overpull.
  • If after several attempts there is no further progress (as seen from marks on the pipe) then go down, circulate clean - then try again.
  • If still no success to pass, then go down again and commence back-reaming procedures. Do not attempt to pump out of the hole as this may cause hydraulic compaction whereas rotation may disperse the blockage.  

• If during a trip, the crew have to change tour, ensure that the Tool Pusher on tour is on the brake until a full handover is done between the drillers.
• Back-reaming should be used as the last resort and with the same flow rate that was used during drilling.
• Back-ream for 5m maximum, circulate cuttings clear of the BHA, then try to pull through the obstruction again using the above procedure - without pumps or rotation.
• During back-reaming the driller must nominate a responsible person to control the mud pumps (e.g DD, Toolpusher, KPO Drilling Supervisor). This person will be responsible for shutting down the pumps quickly in the event of a pack-off.
• In the event of a pack-off:- stop the pumps - go down with the pipe (maintaining rotation) - re-establish circulation - circulate clean.
• Attempt to pull through obstruction again without pumps or rotation.
• Repeat the above process - with patience. The objective is to POOH with the absolute minimum of back-reaming.
• On the trip out of the hole, in casing, or during the running of the 13 3/8” casing, the mud pumps should be checked to ensure their reliability during the cement displacement.

8 ½” Section Preparation checklist

• Drilling Engineer is to organise pre-section meetings at the rig site, with rig and office personnel to discuss section objectives and hazards.
• Confirm primary and contingency bits (including milled tooth and insert tri-cone) are available on location.
• Confirm hydraulics and bit nozzle requirements with Operations Engineer and dress bit accordingly.
• Gauge all stabilizers and check connections of all BHA components. Prior to RIH, the Drilling contractor will provide an accurate BHA report including serial numbers and dimensions of all the components.
• Confirm that any activation balls/darts (e.g. for PBL circulating subs and drop-in dart subs) are the correct size and will pass through all BHA components and DP crossovers.
• Activation balls/darts should be kept in an obvious place in the dog house.
• Non ported float valves to be used.
• The Directional Driller and LWD Engineer will discuss with Tool pusher how best to pick up BHA to minimise excessive handling and time. The BHA components should be laid out on the catwalk and numbered in order of pick up.
• The bend on the steerable motor and the tool face offset must be verified by the DD, MWD Engineers and the Drilling Supervisor.  The tool face offset must correctly entered into the MWD computer and a hard copy passed to the drilling supervisor.
• If using a steerable motor ensure a Turboback stabiliser is also run.
• Ensure all the technical specifications and dimensions (i.e. checklists) of the drilling tools are presented to DSV.
• Ensure the following information is available in the doghouse: Jar settings, weights (in air and mud) of the BHA and maximum pull.  Note that the pull to activate the jars will be higher once the BHA is in the kick-off and tangent section.
• Liners size must be optimized for flow rates and pressures.
• Wash pipe seals should be changed.
• The instructions describing the well shut-in procedures will be posted in the dog house, drilling supervisor and tool pusher’s offices.
• The following information is available in the doghouse, drilling supervisor and tool pusher’s offices: FIT, LOT, MAASP, casing burst pressures, Well Control datasheet.
• Mud Loggers to ensure that all ditch magnets are cleaned and re-installed in the header box. Metal recovered should be reported daily, as ‘metal recovered (grams) per total revs and reported in the DDR.
• Mud Loggers to check and calibrate all sensors (gas, pit volume, pump stroke, torque, WOB, rpm etc).

8 ½” Section - Sequence of Operations

• Perform 9 7/8” x 9 5/8” casing pressure test to 5000 psi (345 bar) if this was not done after cementation.
• Pick up the directional drilling tools and make up the BHA.

Note: There is NO requirement to function test the circulating sub. Visually inspect bypass ports for evidence of washing.

• Surface test the steerable motor drilling system and MWD and RIH with 8 ½” BHA.
  • - Ensure that the Directional Driller witnesses the correct toolface offset being entered into the MWD computer and a sign off form completed.
  • - Confirm no leakage from the circulating sub. Note there is no requirement to function test on surface.
• Perform a full test of the M/LWD tools at approx 500m. Thereafter it is not necessary to test the tools however pulses may be seen during filling the DP.
• Circulate through BHA and record weight in DDR.
• Before drilling out the shoe track a strip drill and a kick drill must be performed. The operation of remote (automatic) and manual choke valves, gauges must be tested by circulating mud through the choke manifold keeping +/- 200psi back pressure on choke.

Note: blow out all lines after drill

• Wash down the last stand(s) and tag top of cement inside 9 7/8” casing.
• Drill out cement and 9 7/8” float equipment using mud from the previous section. While drilling out the shoe track, displace to recover the previous mud such that the displacement is complete by the time the shoe has been drilled.
  • - Mud Engineer to be on tanks during displacement
  • - At least 3 vacuum trucks to be on location
• Clean out the casing rat hole and drill 3 m of new formation.
• Pull the BHA back inside the 9 5/8” casing shoe and perform a shoe integrity test at 1.6 s.g. EMW. If leak off occurs below 1.6 s.g. consult with the Drilling Superintendent.
  • - Report in DDR maximum pressure, volume pumped and bled off.
• Commence drilling 8 ½” section.
• If losses are experienced inform Drilling Supervisor and adhere to these guidelines:
  • - Ensure LCM is thoroughly mixed before pumping
  • - Follow the LCM decision tree for severity of losses
  • - If not in producing zone more aggressive LCM can be utilised – confirm with Fluid Engineer.
• Borehole conditions will be closely monitored as drilling progresses. The following guidelines should be adhered to:
  • - Closely monitor for losses/gains – inform Drilling Supervisor immediately and report on DDR.
  • - Flow check all drilling breaks and report same on the DDR.
  • - Monitor connection gas and report in the DDR.
  • - Maintain mud rheology within specification.  Discuss changes with Drilling S- perintendent.
  • - Prior to a connection, circulate and rotate to ensure the cuttings are lifted well above the BHA. 
  • - Wipe the hole at connection in order to detect changes in the hole condition. The driller will keep a log of the string weight (up, down and rotating), in order to monitor trends.
  • - Acquire LWD log reaming down – do not back ream.
• Prior to trip, pump a hi-vis pill and circulate clean. Up to 3 times bottoms up shall be considered for hole cleaning before tripping. Perform wiper trip if required.
• If changing BHA to run back in with full LWD suite remove RA sources, perform the BHA change. Then read and initialise the LWD tools at the same time.
• Prior to logging the build-up section, check with Schlumberger if logs can be recorded by wire line when the inclinations ranging (20 - 30 degrees).
• At section TD prior to final trip out of hole to run liner perform the following:
  • - Increase mud density to equivalent ECD.
  • - Perform swab test.
  • - Pump out of hole to kick off point at full drilling flow rate.
• Ensure the trip sheet is correctly filled in by the Tool pusher. The theoretical volumes should be validated by the Drilling Supervisor and Mud Logger
• Drift all drill pipe, drill collars and crossovers to API specification to ensure pump down plug (2.250”) and setting ball (1.50”), will pass freely (minimum drift size 2-3/8”).
• Record up and down weights and torque values at 20 and 30 rpm at TD, KOP and at the proposed hanger setting depth.  Record on the daily drilling report. This will give an approximate guide for releasing the liner running tool. 
• Record accurately the hole condition during the trip, i.e. tight spots (bit depth and amount of o/pull), back reaming, circulating, etc. Compare with the mud log / wire line log to determine if hole condition can correlate with formation type.
• Break off the bit and rack back the drilling BHA. 
• Gauge all stabilisers and report in DDR.
• If logging is performed, the following information will be reported in the DDR for each run:
  • - Time to rig up, assemble and calibrate tool
  • - Time spent in hole
  • - Tool failures and lost time
  • - Depth tool reached
  • - Maximum recorded temperature and time since last circulation.
  • - Logger shoe depth
  • - Rig down logging equipment. 
• Perform wiper trip if required. 
• Rig up to run 7” liner.

• 8 ½” bit, nozzles, tool and breaker
• Bit hand on location
• Test plug ready
• Install wear bushing
• Float valve installed
• BHA on racks and strapped
• Stabilizers, jars strapped and ready to RIH
• Mud man to ensure OBM dilution is as per programme
• Make space and clean tanks. Mix brine, spacers to program specs
• Schlumberger logging required prior to liner job
• Request liner delivery (ex HMD), strap, clean and rabbit same
• Install liner consumables as per program
• Have additional bakerlock on hand
• Drill pipe plug launcher head
• Call out Baker hand for running liner whilst logging
• Check all dimensions with Baker hand
• Call out pickup/laydown machine
• Call out casing crew +/- 2 days prior to running liner. Check csg tongs, pwr packs
• Batch mixer required for liners (1day prior), check cmt on location
• Core heads for 8½” section
• Pup jts for coring
• Core barrels and inner barrels (fibre glass or not?)
• Core boxes
• Call out core hand +/- 2 days prior to running
• Mud man to be ready for displacement to brine
• Check if a 5”x3½” string or all 3½” is to be used
• Clean out string for liner
• Clean-out jewellery and bit
• Tubing adapter flange, X-mas tree/suspension tree prepared
• Schlumberger & vibro truck
• Run flare lines
• Break kelly prior to laying out
• Have transport baskets etc for SH-OO equipment ready

Making connection

• Wipe the full stand once by pumping out and reaming back down
• Wipe the bottom single once by pumping out and reaming back down
• The driller must nominate a responsible person to control the mud pumps (e.g DD, Toolpusher, AD). This person will be responsible for shutting down the pumps quickly in the event of a pack-off.

Tripping

• The Drilling Supervisor will be on the rig floor from start of the trip out of hole until the string is in cased hole.
• Prior to starting the trip (during circulating bottoms up) check the following:
  • Record up-weight, down-weight, rotating weight and off bottom torque.
  • Have a single of drill pipe available in the V door.
  • List of tight spots/intervals encountered during connections and previous trips
  • BHA schematic with measurements between stabilizers and bit
• Upon encountering tight hole:
  • Go down and re-establish up-weight, down-weight, rotating weight and off bottom torque.
  • Apply overpull - starting with 20klbs - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
  • Apply 30klbs overpull - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
  • Apply 40klbs overpull - mark the pipe - go down - check the down drag - if negligible increase in down-drag then proceed by trying greater overpull.
  • Continue applying the above technique using 10klb increments up to a maximum of the weight of the BHA.
  • If on any overpull attempt, the down drag indicates that the pipe is becoming jammed, then make several attempts with less overpull.
  • If after several attempts there is no further progress (as seen from marks on the pipe) then go down, circulate clean - then try again.
  • If still no success to pass, then go down again and commence back-reaming procedures. Do not attempt to pump out of the hole as this may cause hydraulic compaction whereas rotation may disperse the blockage.
• Do not make wiper trips unless hole conditions - such as unmanageable increase in torque or drag - dictate.
• If during a trip, the crew have to change tour, ensure that the Tool Pusher on tour is at the brakes until a full handover is done between the drillers.

Back-reaming

• Back-reaming should be used as the last resort and with the same flow rate that was used during drilling.
• Back-ream for 5m maximum, circulate cuttings clear of the BHA, then try to pull through the obstruction again using the above procedure - without pumps or rotation.
• During back-reaming the driller must nominate a responsible person to control the mud pumps (e.g DD, Toolpusher, KPO Drilling Supervisor). This person will be responsible for shutting down the pumps quickly in the event of a pack-off.
• In the event of a pack-off:- stop the pumps - go down with the pipe (maintaining rotation) - re-establish circulation - circulate clean.
• Attempt to pull through obstruction again without pumps or rotation.
• Repeat the above process - with patience. The objective is to POOH with the absolute minimum of back-reaming.

• Conduct Pre-section planning meeting between rig and office personnel to discuss section objectives and hazards.

• Conduct a tool-box talk covering the expected problems outlined above and objectives of the hole section.
• Prepare 1900m of 5 1/2” DP on racks to P/U and rack back in derrick.
  • Note: 5” HWDP is NOT required for this section
• Ensure all tools and materials are on site and in good working order for drilling the 16" hole section.
• Make sure planned 16” bit is dressed with correct size nozzles and the back up bit is on location.
• Bit breaker and 16” gauge ring should be available on location

• Make sure all BHA components are on location with backup set (check stabilizer gauge and connection).

• Ensure all the technical specifications and dimensions of the drilling tools are available, in particular the jar settings.

• Check that the Jars have been re-dressed (0 hours at start of the section).

• Ensure fishing diagrams are available for all downhole tools.

• DD to prepare BHA listing and discuss with toolpusher to minimise handling.

• DD/MWD to run vibration software using actual BHA dimensions and identify critical rpm.

• Prior to drill out, the Drilling contractor will provide an accurate BHA report including serial numbers and dimensions of all the components.

• Ensure the weights (in air and mud) of the BHA and maximum pull are clearly visible to the Driller.

• Ensure 6” liners are installed on the mud pumps.

• Ensure sufficient availability of viscosifiers at the well site to improve the low-end rheology if needed.

• Ensure sufficient quantities of broad-spectrum LCM additives are available.

• If LCM is to be used, ensure that a PBL sub is included in the drilling assembly to augment pumping coarser grained LCM material.  If coarser grained LCM is pumped through the PBL sub, ensure to flush the sub with LCM free Hi-Vis fluid before functioning it closed.

• If heavy losses are expected (shallow salt wells), the cement unit should be on site at the start of section.  Ensure that there is enough cement and cementing additives on site to prepare Thixotropic cement plugs if required.

• Ensure the ID of the bell nipple will allow the running of the wear bushing:

  • The max OD of the 20” nom. Wear bushing is 20.625

  • The minimum ID of the Diverter Spool is 20.75”

• Prior to starting the section, ensure that all personnel on rig site are aware of Low Tox Oil Based Mud handling procedures.

• Plan to get the 13 5/8” BOP tested on stump to rated working pressure (10K), as per KPO pressure test procedure.

• Ensure enough cutting skips are available for each hole section, if drilled with OBM.

• Ensure enough shakers screens are available on the rig.

• Flow rates above 4000 lpm are required for this section.

• Ensure different sizes of bits nozzles are available on the rig for hydraulics optimization

Wellsite checklist

• 2 x 13 3/8” casing tongs & power units
• Start getting vibro truck for 12 ¼” hole if required
• Schlumberger to call out
• Cmt samples to send to hassi
• Alert weatherford & bring out 2 days prior
• Bits & jets
• Check barytes
• Review ultra seal / lcm
• Check bj. Float equipment & cmt / plug head – xo… etc
• Consider jar hour before rih
• Install casing shoe & f/c & install stop rings & centralisers
• Test & flush vacuum degasser with 10.5ppg mud
• Check ton miles prior to wiper trip

• Drilling Engineer to organise pre-section meeting at the rig site, with rig and office personnel to discuss section objectives and hazards.
• Gauge of all stabilizers will be checked prior to making up the BHA. Prior to RIH, the Drilling contractor will provide an accurate BHA report including serial numbers and dimensions of all the components.
• If a steerable motor is used, the bent and the tool face offset must be verified by the DD, MWD Engineers and the Drilling Supervisor.  The tool face offset must correctly be entered into the MWD computer and a hard copy passed to the drilling supervisor.
• If GeoPilot RST is to be used ensure stabiliser is run on top of tool below flex collar to mitigate vibration.
• Liners size must be optimized for flow rates and pressures.
• Confirm chemicals (e.g. torque trim for WBM or acid for releasing stuck pipe) are readily available.
• The instructions describing the well shut-in procedures will be posted in the dog house, drilling supervisor and toolpusher’s offices.
• The following information is available in the doghouse, drilling supervisor and toolpusher’s offices: FIT, LOT, MAASP, casing burst pressures, Well Control datasheet.
• Confirm primary and contingency bits (including milled tooth and insert tri-cone) are available on location.
• Confirm hydraulics and bit nozzle requirements with Operations Engineer and dress bit accordingly.
• Ensure the following information is available in the doghouse: Jar settings, weights (in air and mud) of the BHA and maximum pull.  Note that the pull to activate the jars will be higher once the BHA is in the kick-off and tangent section.
• Washpipe seals should be changed.
• Mud Loggers to ensure that all ditch magnets are cleaned and re-installed in the header box. Metal recovered should be reported daily, as ‘metal recovered (grams) per total revs and reported in the DDR.
• Mud Loggers to check and calibrate all sensors (gas, pit volume, pump stroke, torque, WOB, rpm etc).
• There is no requirement to function test the PBL sub on surface.

6" Section Drilling - Sequence of Operations

• Surface test all drilling tools. Repeat test at 1500m to confirm all sensors operational. There is no requirement to further test the tools until drilling commences.
• Independent cross check DP tally when picking up 3 ½” DP
• Prepare and RIH BHA. Fill pipe every 500m, break circulation every 1000m.

Before drilling out the shoe track a pit drill, strip drill and choke manipulation drill will be performed.

• Ensure that mud all round is conditioned to parameters as specified in the programme.
• Drill section to TD.  Take surveys with MWD tool after every stand.
• Closely monitor real time downhole vibration levels:
• Perform swab test after any mud weight change.
• Use at least 1.5% torque trim with water base mud to minimise vibration of downhole tools.
• If cuttings thin sections are required for biostratigraphy perform the following:
• Alternatively: Pump high vis pill, keep drilling with 60 rpm for 2100 strokes.  P/U off bottom, reduce flow rate and pump cuttings into vertical and resume drilling.
• If activating circulating sub pump ball down at normal flow rate until reaching 80% of string capacity. Pump the last 20% very slowly 5-10spm. This should stop the ball from being forced through the seat.
• At TD of the section:
  • Continue to POOH with 5” and 3 ½” DP.
  • POOH with BHA and clear rig floor.
  • Accurate trip sheet volumes (in litres) will be maintained at all times.
  • These will be cross checked by Rig Tool Pusher, DSV and Mud Logger.
  • Mud logging unit will track volumes during trip and inform driller immediately of any discrepancy.
  • If there are any discrepancies, the well must be shut in and if safe to do so, the BHA run or stripped back to bottom.
• Lay out the drilling tools.  If possible download LWD data offline.
• Rig up and prepare and run pipe conveyed logs as per the logging programme (if required).
  • Ensure driller is aware of vibration types and effects and action to take
  • Modify drilling parameters accordingly
  • Drill to the agreed sampling depth.
  • Slow TDS RPM to 80, drop WOB down to 3 - 5 Klbs and drill 2m.
  • Pump 3m3 of barolift while drilling with above parameters.
  • Once the barolift pill reaches the bit, pick up off bottom and reduce the TDS RPM to 20 until the bottom sample is in the vertical part of the well.
  • Once the bottom sample reaches the vertical part of the well, continue drilling with normal parameters until the next sampling depth. 
  • Circulate hole clean.
  • Increase mud density to equivalent value of ECD.
  • Flow check.
  • Perform swab test.
  • Pump out of hole to KOP (8-1/2” hole) or TOL (5-7/8” hole) at same flow rate used for drilling
  • Flow check well for 30 minutes. 
  • Rig up Schlumberger Wireline (if required), and Run cement bond evaluation logs in 7” Liner and Scab liner.

This article presents some tips for running drilling fluid systems.

PV and YP

For optimum hydraulic parameters the values of PV and YP should be as low as hole cleaning efficiency and suspension of solids will allow. Low viscosities result in turbulent flow at any given pump rate.

Gel Strength

A ‘ten minute’ gel strength of 25 lbs/100 ft2 shall be considered the absolute maximum for all muds under all conditions.

ECD

ECD should be kept to a minimum at all times. At laminar flow the frictional pressure drop is lower than at turbulent flow.

Borehole Stability

To minimise borehole deterioration in water-sensitive formations (eg., shales and loose sandstones) the erosional forces on the formation are lower at laminar flow than at turbulent flow.

Milling Fluid Rheology

Milling fluid should have a rheology similar to values shown below

PV = 14 cp

YP = 76 lb/100ft²

GELS = 30/40 lb/100ft²

Viscosity = 120 s/qt

Inhibition

The pH of the drilling fluid shall be maintained between 9.5 and 10.5 with caustic.

Corrosion Inhibitor

Corrosion inhibitors shall be used in packer fluids.

Well Control

Barite should not be used as weighting material for well control purposes in reservoir sections. Salt and CaCO₃ should be used for this purpose.

Lubricating Fluid

Lubraglide or oil seed rape oil is used as a lubricating fluid or for sliding assistance.

Contingency - Heavy losses

It is recommended not to attempt to drill ahead with heavy losses. LCM pills and/or cement plugs should be set as soon as the losses occurred, so that they can be positioned easily on bottom and across the loss zone.

If losses are not manageable, the hole can be opened to 20” and a 16” contingency casing will be set. The next section will be drilled with 14 ¾” bit and BHA to 13 3/8” casing setting point, and opened to 16” in order to run and cement the 13 3/8” casing.

The alternative will be to drill blind. Some wells had multiple loss zones. In this event, the following guidelines should be followed when losses occur at the interface:

• Rapid return to good fluid loss control is recommended
• Work the pipe regularly. This should involve drilling ½ a single and reaming the same section again before continuing.
• Every third stand, perform a wiper trip back to the depth where losses commenced.
• Watch drilling parameters as described above for warning signs of the hole packing off.
• Maintain normal flow rates. In the event of running out of water on site, pull back to the shoe and wait for water while monitoring for possible gas.
• Check that shakers are totally clean before commencing POOH operations.

Ensure a drilling water line is lined up on the drill string by the 20” casing and drill water is bled at an agreed rate, which will depends on the rates of the mud returns and if a total lost circulation situation had occurred.

Bleeding drill water in the annulus is called low head procedure, the basic idea is to find out the dynamic level of the mud in the annulus and adjust the drill water filling/bleeding rate accordingly.

Guidelines for suspected bit balling

Avoid bit balling (- even to the detriment of ROP).

P/u 0.3 m off bottom, increase flow rate and rpm to maximum possible. This worked on 9806 when ROP increased from 0.7m/hr to 2.7m/hr.

An attempt was also made on Well 9806 to clear bit balling using a nut plug sweep to "scour" the 16" bit. The result of the test was "inconclusive" - but as no mud ring fragments were returned with the nut plug at the shakers it is most likely that this material is not the best medium for providing a "scouring" action. On Well 9808 a nut plug sweep was pumped ( for a different reason ) and this plugged the surface screen which is run in the drill pipe to protect the MWD. It was speculated that the screen plugged because the nut plug sweep was not prepared correctly - however in order to avoid similar problems in future, ( particularly downhole at the MWD), the use of nut plug as a bit balling treatment is not recommended.

When POOH, look for (and report in the DDR) any increase in overpull as the stabilisers and bit enter the casing shoe. This is a good indication of the presence of Bit /BHA balling.

• Test plug ready
• Install wear bushing
• Float valve installed
• BHA on racks and strapped
• Stabilizers, jars strapped and ready to RIH. Check jar hours
• Bits, nozzles, tools and breaker on location
• Bit hand on location
• OBM weighted up
• Get 9 5/8” csg on location, strap, drift, clean and dress. Have bakerlock on location
• Back load 13 3/8” csg
• Make sure Weatherford are on location and ready 1 day prior to casing run
• Make sure cementers are ready, equipment serviced and silos full
• Schlumberger & vibro truck
• Stabilizers
• Check contractors ton miles
• Tubing head and accessories on location and prepared
• Have mud man/solids control preparing diluted OBM
• Coring equipment and personnel to be put on notice
• Have cementers check cmt quantity for next job

• core hand on location
• schlumberger vibro truck if required
• logging tools for section
• pup jnts for coring 7 or full kelly weatherford
• 4 ½” csg tongs & 2 x power packs
• run flare lines
• completion containers
• polish mill for 4 ½”
• csng scraper for 4 ½” x 2
• bits 3 ¾” x 3
• flush all lines for completion, mud pumps choke, stand pipe…etc
• batch mixer for liner job
• note: break kelly prior to laying down same
• Insure that the cleanout  string —drill pipe and dc’s are properly torqued with the  correct  torque values, when the dp and dc’s are being  handled  by the drilling crews
• All of the  company clean out string handling tools—xo subs, slips,elevators,safety valves are used/ handled properly.

26” Section - Preparation

In addition to the items specified in the pre-spud section, the following preparation and checks will be performed:

• Pre-cut conductor from ground level. Keep attached in 4 areas with 2” tabs. Install 30” dresser sleeve.
• Test all mechanical surface equipment (Mud Engineer and solid control personnel to check all Mud equipment and inform Drilling Supervisor of any deficiency).
• Pressure test cement and standpipe lines to 7500psi.
• DSV will carry out Rig acceptance checks (Test Top drive functions as per test procedure).
• DSV to verify distance from RTE (Rotary Table Elevation) to AGL (Above Ground Level, i.e. Top Cellar) once rig is rigged up. This height is to be reported to the Operations Drilling Engineer.
• Gauge of all stabilizers will be checked prior to making up the BHA. Prior to drill out, the Drilling contractor will provide an accurate BHA report including serial numbers and dimensions of all the components.
• Prepare 20” Casing on racks (Check shoe jt for any debris inside, install centralizers on stop collars as per tally).
• Confirm cellar jet pump installed and tested.
• Confirm Cement stinger/Centralizer/spare seals on location.
• Confirm 20 ¾” Well head housing M/U with landing joint flange and 5”DP.
• Confirm Wellhead orientation drawing on location.
• Confirm Thread lock compound in DSV office.
• PU 3 x 8 ¼” D/C, and 15 x 5 ½” DP and rack back (Check well centre with 8” D/C stand before rack back).
• Losses are not expected in this section. However sufficient LCM material should be available at the wellsite.
  • Ensure the weights (in air and mud) of the BHA and maximum pull is clearly visible to the Driller.

26” Section – Sequence of Operations

• Hold Pre-Job safety meeting. Discuss with crew the Drilling Contractor Shallow Gas Procedures
• Make up the 26” rotary BHA. Include a float valve.  Ensure that a Totco ring is installed.
• Circulate through BHA and report weight in DDR.
• RIH with the 26” BHA inside the 30” Conductor.
  • The 30” conductor has been pre-installed to a depth of approximately 10-12 m below top cellar.
• Drill out the 30” shoe, and carefully clean out the rathole in case of cement blocks.  Use a lower flow rate when around the 30” shoe area to avoid washing out the shoe.
  • To prevent washout under the shoe, the flow rate will be limited to 2200 LPM until the bit is 5m below the shoe. The flow rate is then increased to 2400 LPM to drill the first 30m and to 3000 LPM for the rest of the section.
• Drill ahead to 20” casing point, allowing for a 3 m rathole below the 20” shoe. The exact depth of section TD will be adjusted to space out the casing.
  • ­Drill water and viscous sweeps to be used for drilling this section pump a sweep prior to making connections. Add additional sweeps as required. Ensure sweeps of sufficient size to clean hole. The basic mud plan is to drill with water in a closed circulation system, the formation will provide a native mud which will be maintained as per the mud program.
  • ­­Report in the DDR the shape and size of cuttings as well as the % increase in cuttings when circulating hi-vis pills.
  • Ensure mud specifications are as per mud programme.

• At TD sweep hole with 10m3 Hi Vis and circulate clean.

• Perform wiper trip by POOH bit to 30” csg shoe (DSV / Toolpusher will be on Rig floor).

• RIH, wash last +/-10 metres @ 20SPM to avoid plugging of nozzle and confirm any fill (increase to full flow rate and clear fill).

• Sweep hole with 10m3 Hi Vis and circulate clean @220SPM.

• Drop Totco.
  • If severe hole problems occur run the Totco barrel on the rig’s slick line.
• Pump out of hole.
  • Use high flow rates while pumping out of hole with mud in order to reduce the risk of fill.
  •  If inclination is greater than 1° then ream down the hole to section TD in an attempt to reduce the inclination. Confirm this step with the Drilling Superintendent.

• Drain riser into cellar and clear cellar with jet pump or vacuum truck (if available).

• Disconnect dresser coupling and cut 30” conductor (ensure Hot work Permit obtained).
  • If possible PU Weatherford equipment.
• Lay down riser.

• Hold pre-job planning meeting. All equipment to be checked and personnel familiar with the plan.
• The final cement programme to be issued to the rig and approved by the Drilling Superintendent.
• Ensure that BJ needs to blow out water from the lines after performing pressure test to avoid frozen the lines if job is carried out in cold weather.
• Before cement job begins, ensure that the cement is fluffed and transferred from one tank to another tank to make sure it would transfer in the cold weather.
• Carry out pressure testing of cement line while mixing cement.
• Prior to start cementing, ensure to perform the following:
  • Total required volume of technical water to be stored on the rig site some days in advance of the job.
  • Pre-job analysis of technical water, slurry and spacers. Perform tests for possible fluid contamination and include in the program.
  • Be sure the slurry formula is fit to avoid flash setting due to possible slurry dehydration while passing through TOL.
• Prepare cement mix water in the batch mixers and store in the KPO tanks, prepare spacers in the batch mixer and store in same.
• Confirm that the Technical water is being supplied directly from the LMP. Do not use water from any other source.  BJ supervisor to check the water.
• Avoid using NaCL Brine to perform BJ lines test until a contamination test has been performed.
• Ensure correct tanks and drill water are delivered at least 24 hours in advance of the cementing job.
• Check that cement chemicals have been added to the mix water in the correct order (e.g.: FP-21L, A-9, EC-1, R-3, CD-32 & FL-25)
• Thoroughly mix each chemical after adding them to the mix water. Take samples of final mix fluids, label and retain for lab verification tests.
• Ensure all BJ washer and spacers should be prepared in the batch mixer and pumped by the BJ unit. For improved job control avoid preparing washer and spacer in rig pits and avoid using rig pumps.
• Take 5 gallons dry cement sample in advance of the cement job so that pilot testing at cementing lab using rig samples can be carried out.
• Take 1 gallon mix water sample during the cement job. 
• Check that the following equipment is available at the rig site:  Weatherford circulating tool; Long elevator bails (Parker Supplied).
• Mud Logger to ensure stroke counters set to zero before pumping spacer and displacement.
• If losses encountered during drilling 8 ½” hole section, attempt to cure losses before mixing and pumping cement slurry. Note: if no losses encountered mixing of slurry could commence during liner running so as to be ready once circulation of liner contents complete.
• While preparing the slurry, continue to circulate and check the following:
  • Cement head bearing is secured to the derrick prior to rotating the liner
  • The tugger must be manned at all times during rotation.
  • There is a minimum of 20 Klbs (10 tonne) of drillpipe weight onto the liner prior to rotation and re-engage torque fingers of ‘HRD’ tool in ‘HRD’ profile of ‘ZXP’ packer to allow rotation of liner.
  • Establish circulation and rotation (generally ensure continued circulation during all rotation) prior to cement job and monitor rates and pressures.
  • Note torque readings at 20 and 30 RPM with a minimum weight of 20 Klbs (10 Tonne) of drill pipe weight on liner.
  • Check that the top drive is set properly in order not to limit the torque below programmed for rotating the liner during the cementing job.
  • Make sure there is good communication possible between the rig-floor and the cement unit.  Have spare cement unit on location.
• Ensure that TDS IBOP is closed before hooking up the cement lines.  Open the low torque valve.
• If possible use the caliper log to calculate the slurry volume required.
  • The Liner should be set 100m inside the 9 7/8" casing. Reduce the slurry top to 50 - 100m above TOL. Hole volume % excess and TOC should be agreed & communicated to the team once the logs are run.
  • Before the job check & calibrate all Saipar and WFD-Datalog sensors and stroke counters.
• Pump the required amount of cement as per cementing programme, allowing for volume of approximately 100m above the Liner Top (with the DP connected to the hanger).  Observe and note the torque required to rotate the Liner.
• Stop rotation to allow safe release of the Drill Pipe Pump Down Plug as follows (it is not allowed to have man in riding belt whilst rotating).
• When cementing the 7'' liner after bumping the plug pressure up to 1000psi over final displacement pressure and hold for 5 mins.

• After cementing operation on the 13 3/8" section.  Do not attempt to back out the landing joint to let fluid out. The normal procedures consist of cutting two holes and letting the fluid drain and then proceed with cutting the casing.      
• Rough cut 13 3/8” casing.  Refer to the manufacturer installation procedures.
• Remove landing joint and diverter stack. 
• Final cut 13 3/8” casing.  Dress cut, and install casing seals.
• Change bail arms and service top drive offline.
• Nipple up 20 ¾” 3K x 13 5/8” 10K casing spool and 13 5/8” 10K Vetco adapter.  Nipple up wing valves and blind flange on casing spool. 
• Nipple up and Test 13 5/8” 10K BOP stack.
• Recommended BOP Configuration
  • Annular
  • Rams (3 ½” – 5 ½” Variable)
  • Rams (Blind/Shear)
  • Mud Cross
  • Rams (4 ½” - 7” variable)
• BOP test pressures:
  • Annular:     300 psi 5 min / 3500 psi 10 min (70% WP)
  • Rams:       300 psi 5 min / 5000 psi 10 min (anticipated WH pressure)
• Run two stands of DP (or 5” HWDP if NC50 connections on plug tester) into the hole. Make up the 13 5/8” nominal BOP cup tester onto DP and install ‘Quick Make/ Break saver Sub’.
  • Note: Open the lower outlets in the wellhead housing.
• Lower the BOP tester through BOP stack into the wellhead housing and land off on the 45° shoulder. 
• Pressure test BOP drilling adaptor/wellhead connections to 5000 psi.  Note that a plug tester must be used, as the 13 3/8” casing has been tested to 3000 psi only and has a burst pressure of 5020 psi.
• POOH with BOP test equipment and lay out same.
• Install wear bushing.
• Lay down 16” BHA

1. Preparation

The Drilling Supervisor shall approve and provide written instructions to the Contractor Toolpusher prior to any trip out of the hole. These instructions shall include the:

• sequence of operations  i.e. flow check, circulate bottoms up, drop survey, etc.
• maximum allowed overpull
• procedures if tight hole is encountered
• maximum running/pulling speeds
• preparation of equipment for the following operation when out of the hole
• Trip sheet

Pipe Tally

The drilling contractor shall ensure that a master drill pipe tally book is maintained at all times.  This shall include stand number, single number, single identification, drill pipe grade, single length, stand length and total length.

Trip Tank

Prior to pulling out of the hole, the trip tank shall be filled. The fill-up pump to the trip tank should never be left running while tripping out.

Circulation

•  For any trip out of the hole, a minimum of one bottoms up circulation, or appropriate circulation for deviated wells, shall be performed.
•  When circulating to condition mud, a circulating rate of 50 - 75% of the normal circulating rate shall be used.
•  A trip sheet shall be filled out by the Driller and Mud logging contractor for each trip out of the hole.

 2 - General Guidelines

Responsibilities

The Drilling Supervisor shall be on the rig floor for the first 10 stands during tripping out to observe for correct hole fill, overpull, etc. He shall also be on the rig floor for the last five stands when tripping in, tight hole problems, testing mud motors & MWD, RIH across liner hanger and when casing 3 stands off bottom.

Pipe Movements

• Care shall be exercised to minimise surge/swab pressures by controlling the speed of pipe movements.
• Pull the pipe carefully and check for swabbing. In the event of the hole swabbing, the pipe shall be run back to bottom and the hole circulated bottoms up. Mudloggers shall run the swab programme prior to each round trip to determine the maximum trip speed.

Notes: A hole is swabbing whenever the volume of fluid required to fill the  hole is less than the volume of steel pulled out of the hole. THE HOLE CAN BE SWABBING WITHOUT FLOW AT THE FLOWLINE.

Circulation, Hole Fill, and Pipe Fill

•  During tripping operations, the hole shall be kept full at all times.
  •  The pipe shall be filled every 10 stands while running in the hole and the displacement checked.
•  When pulling the pipe, the hole shall be kept full from the trip tank. The hole shall be checked regularly to ensure that it is taking the correct amount of fluid.
•  The volume required to fill the hole every 3-5 stands shall be recorded in the Trip Sheet until the bit is out of the hole.

 Tight Hole / Bridging Conditions

•  If tight hole or bridging conditions occur during trips, the pipe shall be pulled back to the nearest stand and reaming/washing commenced in accordance with stuck pipe procedure.
•  If tight spots occur while tripping out, the top drive or kelly shall be engaged to commence reaming and circulating out.
•  Reaming trips might be required prior to running LWD/density tools and/or 7in liner.

Directional Wells

While tripping out of the hole from below the surface casing in directional wells:

• reciprocate at all times and rotate the pipe at intervals while circulating and conditioning the mud prior to POOH
• record the pick-up, slack-off and rotating weight indicator readings with the mud pump off. Note: These values shall be used to monitor changes in drag during pulling out.
•  the top drive, if available, shall be used to pump out and/or ream out the first 5 to 10 stands off bottom.

Flow Checks

While tripping flow checks shall be taken:

•  just off bottom
•  at the cement casing shoe
•  prior to pulling drill collars through BOP stack
•  after BHA out of horizontal section
•  while RIH after drilling out shoe
•  while RIH before BHA enters horizontal section.

3 - Requirements When Out Of Hole

 Time Out of the Hole

The time spent with the pipe out of the hole shall be minimised wherever possible. Operations such as routine repairs and slipping and cutting of the drill-line shall be performed with pipe at the casing shoe whenever possible.

Requirements When Out of Hole

The trip tank volume indicator shall be set at 1/2 barrel gain or loss whenever the trip tank is being circulated on the hole.

Whenever the blind rams are closed, the Driller and the Assistant Driller shall open the rams and check the fluid level at least every half hour, fill the hole as required and report any losses to the Drilling Supervisor. (Before opening blind ram open choke)

During logging operations, the trip tank shall be circulated continuously to keep the hole full.  The volumes shall be recorded every 15 minutes and any losses reported to the Drilling Supervisor.

Whenever the mud pumps are turned off with the pipe still in hole, the trip tank shall be circulated continuously. The volume shall be recorded every 15 minutes and any losses reported to the Drilling Supervisor.

4 - Wiper Trips and Check Trips

Wiper Trips

Wiper trips shall be run at the discretion of the Drilling Supervisor and Drilling Contractor Toolpusher:

• during logging when hole conditions deteriorate and become sticky
• after logging and before running casing when hole conditions deteriorate and become sticky
• before RFT tools are run
• to push junk down the hole (e.g. lost SWS bullets, etc.).
• after 500-1000 ft of hole has been drilled

Note:    In general, wiper trips shall be made to the shoe. However, when there are no indications of hole problem but there is a major change in parameters, a short trip of 10-15 stands shall be made.

Check Trips

Check trips shall be run at the discretion of the Drilling Supervisor and Drilling Contractor Toolpusher but shall be run:

• whenever significant torque/drag increase is noted
• before running casing if hole conditions during logging indicate that this is necessary
• during logging when mud overbalance is limited/low or there is gas cutting of mud
• when the bit has been on bottom for 24 hours.

For casing check trips, the BHA shall include full gauge stabilisers and be at least equal in stiffness to the casing string. MWD’s, NMDC’s and other expensive BHA components shall not be run.

The following table contains the basic guideline procedure to be followed when making a check trip:

1. Circulate bottoms up

2. Flow check for 15 minutes

3. Slowly pull 10-15 stands while using the trip tank to ensure that the hole is taking the correct quantity of mud

4. Flow check

5. Run back to bottom, check for fill and for flow again

6. Circulate bottoms up and condition the mud

7. Check mud returns for gas and salinity and report to the Drilling Supervisor

Note : If a well demonstrates a tendency to swab, pumping out of the hole maybe necessary.

5 - Making Connections

The following guideline procedure shall be followed for all drilling operations in order to minimise the time during which the drill string is motionless:

1. Drill the stand/joint down to the desired point but DO NOT drill-off the WOB or stop the pumps

2. Reduce the rotary speed to 20-30 RPM

3. Begin upward movement of the pipe while maintaining 20-30 RPM rotation

4. Pull one stand/joint of pipe above the rotary to wipe all newly drilled hole

5. Lower the pipe and REAM the stand/joint down, if necessary

Note :   The Directional Driller shall be notified before any reaming is carried out

6. Repeat Steps 4-5 until drag and torque are acceptable

7. Lower the drill string without rotation and observe drag

8. Set the slips and break the tool joint to make connection

9. Pick-up the new stand/joint of pipe and make the connection

10. Start the pumps, lift the pipe and remove the slips

11. When the mud pumps are near required speed, begin rotation, lower the pipe and resume drilling

12. When the pipe is in the open hole, always set the slips on a down stroke long enough to ensure that the pipe is actually moving down the hole when the slips are set; never set the slips with drill pipe tension on the BHA.

• Operations Engineer to organise pre-job planning meeting at the rig site, with rig and office personnel to discuss the job objective and hazards.
• Sections are picked up in 30-foot lengths, so the steps outlined should be multiplied for a given core barrel length.
• Check if hole conditions allow run 81 meter core barrel.
• Do not run roller reamer on top of core barrel.
• When picking up a section of core barrel fitted with an outer barrel stabiliser using the crane only, the slings should be positioned on the outside of the stabiliser blades. This ensures that the slings are pulling towards the centre of the load, and are prevented from moving inward by the stabiliser blades. (Prevents the load from slipping and causing trapped limbs/blows to the body).
• When picking up the barrel using the drill floor tugger and tailing the load in with the crane, the slings should be placed just inboard from the stabilisers as the slings are being pulled away from the centre of the barrel.      
• When handling core barrel do not hammer the slips as the cotter pins can be parted and button dies fall down the hole and ensure to tap the slips into place. Once dog collar is removed the slips can be visually inspected prior to pulling.
• Ensure that all personnel are standing clear of the catwalk when hoisting the barrel from the pipe deck to the rig floor.
• Ensure that a tag line is attached to the load to keep control of any swinging.
• Make sure no personnel are standing between the core barrel and the pipe racked in the derrick.
• Ensure that the elevators are attached to the core barrel before removing the top sling.
• Keep hands away from the core barrel body while it is being hoisted by the blocks, as the lower sling may slip.
• Control the barrel movement with racking arm/tugger line prior to positioning in the rotary table.
• When tripping out with core if gas is associated with the core apply 3 minutes a stand to 500m and then 6 minutes a stand to surface.
• When applying torque to the connections on the outer barrel, keep hands away from the core barrel body and stand back from the rig tongs.
• Ensure that the barrel is kept securely centralized when applying torque to the connections on the near bit stabilizer and core head. This prevents any possibility of the barrel being pulled out of the rotary table.
• When picking up a section of core barrel fitted with an outer barrel stabiliser using the crane only, the slings should be positioned on the outside of the stabiliser blades. This ensures that the slings are pulling towards the centre of the load, and are prevented from moving inward by the stabiliser blades. (Prevents the load from slipping and causing trapped limbs/blows to the body

• Insure wear busing out of hole
• Check connections on retrieving tool & test plug
• Antifreeze in test fluid
• Pump through manifold
• Test cement unit w/chart
• Accumulator drill
• Remote panel function
• Test procedure
• Verify test pressures/times
• Check space out
• Spare test plug & rubbers
• Spare parts; gaskets, seals etc.
• Test Safety valves (IBOP, Gray valve)
• Open casing valve on outer string
• Brief cementer on procedures & requirements
• How test blind shear ram
• Test with water
• How to handle check valve if installed
• Return koomey to drilling position after test
• Fill out paperwork correctly

• Remove casing hanger running tool by rotating to the right (approx 14 turns).
• Change out bail arms on top drive.
• RIH one joint of drill pipe. Clean out BOP and wellhead area. POOH
• RIH with KIOS flushing tool and jet on top of the casing hanger neck.
• Clean out wellhead. POOH.
• RIH setting tool and set MST seal assembly. Pressure test to 500 psi for 15 mins.
• Nipple down BOP.
• Nipple up 13 5/8” x 11” 10k tubing spool and test to 5000 psi for 15 mins.
• N/U 13-5/8” BOPs
• Install test plug.
  • Do not install O ring until after pulling tool has been turned over to use as test plug.
• Test BOPs
  • Annnular: 300 psi 5 min \ 3500 psi 10 min
  • Rams: 300 psi 5 min \ 5000 psi 10 min
  • TIW valves, IBOP, Stand pipe manifold: 300 psi 5 min \ 5000 psi 10 min

Note: choke and kill manifold valves to have been tested off line:300 psi 5 min \ 5000 psi 10 min

Blind rams to have been stump tested off line

• If salt saturated mud is used, ensure to flush/ clean all lines from salt crystals and cutting to avoid lines getting plugged up
• Ensure to consider jetting and washing wellhead and BOP prior to removing Bell Nipple to eliminate the chance of getting junk or cuttings to fall from pollution pan into BOP
• All pressure tests shall be recorded on chart and include the volume pumped to reach the test pressure and the volume bled back. Test recording charts and other documents shall be filed at the rig site by the Rig contractor superintendent. Copies of all test charts and other documents shall be sent to the Drilling Superintendent in office.
• While running in the NBP pulling tool to pull out; the steamer could be utilized to ensure the side valves are not frozen.
• Run and install the wear bushing with the WB combination running tool according to ABB Vetco Grey procedures.

The end product of a reconnaissance visit is a report which summarises the views of a team of experienced specialists on all aspects of the proposed campaign. This report should be used to put on record the team's recommendations concerning the drilling campaign strategy, the skills/staff requirements (including an organisation chart with timing), the contracting strategy and an operations planning time chart. It should also address local politics, labour laws and difficulties, special difficulties in doing business, customs, immigration and residence formalities, climate, health, etc. It should include maps and photographs where appropriate to illustrate access routes, proposed drilling locations, possible bases, ports, other local facilities, etc.

As a guideline, the report should address the following items:

1 Concession Agreement

• tax position
• exoneration from import duties
• government reporting procedures
• remittal of foreign currency.

2 Joint Venture Agreement (if partners)

• reporting procedures
• authority constraints
• rules concerning buying/selling of surplus materials.

3 Contact with local authorities

• List addresses and contact details for the following entities:
• Ministry of Finance (Customs & Excise)
• Ministry of Mines (Licences)
• Ministry of Transport (Special transport permits)
• local authorities (Police, Harbour Master, PTT)
• embassy, consulate.

4 Local conditions

• political climate/stability (Nationality constraints, labour disputes)
• seasonal effects (weather windows)
• holidays/weekends (Ramadan).
• check procurement policy for diesel,  luboils and greases.
• check on import restrictions.
• are there "blacklisted" suppliers?
• is there a "buy local" policy?

5 Contact with other local companies

• List addresses and contact details for the following:
  •  supply agents/ stockists
  •  manufacturers
  •  suppliers.
• Are work/ machine shops available for
  • engine repairs (do they have spare parts)
  • thread cutting (are they licensed)?
• Visit any competitors in the area and see if there is any potential for learning from their experience with bureaucratic procedures, etc. or for optimisation by sharing common facilities.
• availability of drilling surplus
• check whether tools/equipment can be hired.

6 Contact with International Services Companies (Halliburton, Baker, Schlumberger, etc.)

• Check availability of key services in country (or neighbouring countries):
  •  drilling
  •  cementing
  •  logging
  •  well testing.
• Check buy-back possibilities for
  •  bits + nozzles
  •  packers
  •  bridge plugs
  •  cementing equipment
  •  wellhead equipment
  •  cement
  •  mud chemicals.
• rental possibilities for running tools.
• quality requirements (inspection, certification)?
• delivery times (FOB, etc.)?
• prices ex works and country prices?
• possibility of back-up support (reciprocating)

7 Local supply of key material and equipment:

•  safety clothing (helmets, goggles, shoes, overalls, etc.)
•  safety eqt. (fire extinguishers)
•  packing materials
•  general tools (incl. strapping machine)
•  timber (dunnage for storage of pipes, etc.)
•  slings, shackles, baskets, containers (+ certs.), pallets
•  stationery (incl. computer paper)
•  communications eqt.
•  foodstuffs
•  generator sets
•  pumps, waterpipes
•  office equipment
•  furniture
•  air-conditioners
•  fuels, luboils, greases
•  construction materials (cement, rebar, angle iron)
•  check surplus available (condition and certificates available)

8 HSE

• contact details for local and government agencies responsible for Health Occupational Safety and Environment.
• contact details for local hospital (suitable for expats) or clinic
• contact details for environmental /safety consultants for in (or neighbouring) country expertise.
• contact details for suppliers in (or neighbouring) country of medical equipment
• contact details of aviation suppliers for light aircraft and helicopters
• contact details for safety training schools
• contact details for local doctors accredited to provide health care for expat families
• contact details for suppliers of safety equipment - PPE and ability to service same.

 9 Human Resources

• contact details for local labour lawyer
• contact details for local employment agencies
• contact details for HR representatives of other oil and international companies operating in-country.
• contact details for contractors to provide competent manpower for support ops.

10 IT and Telecomms

•  Address & Contact details for the Ministry of Posts & Teleccomunications (PTT) For Radio & Satellite Licence Applications
•  Address & Contact details for the National telephone service provider (Is it a state monopoly eg PTT, or other ?)
•  Details of local and national Internet Service Providers (ISP's)
•  Details of mobile phone operators and networks (coverage) in Mozambique
•  Details of local telecomms suppliers (phone systems, fax machines)
•  Details of local IT companies, particularly those who can provide local IT support services (not just hardware sales)
•  Details of any companies specialising in Office cabling / fit-outs.

11 Buying

•  How do local prices compare with international prices?
•  What are delivery time guaranties (is expediting required)?
•  Can international freight be sent directly or need to transit in neighbouring conntry
•  Can foreign currency be transmitted (what is procedure)?

12 Preservation and packing

•  climatic conditions during materials transport and storage?
•  extent of handling and transport involved?
•  are there weight/size restrictions?
•  what lifting devices are required:
•  hoisting eyes?
•  pre-slinging?
•  palletising (jungle wrapping)?
•  heavy lifting bags?
•  containerizing?
•  sufficient materials available for rebagging and strapping?
•  packing need to be resistant to theft?
•  packing require easy access for inspection (customs)?
• own containers required for storage on-site?

13 Insurance

•  what needs to be insured (Company policy)?
•  regulations (local insurance compulsory or recommended)?
•  who covers transport (time limit)?
•  who covers storage (block cover?)?
•  what are claims procedures?
•  are claims paid in local or foreign currency by local insurers?
•  premiums to be paid in local currency?

14 Shipping

•  local regulations or policies regarding choice of shipping/airline companies?
•  recommended (air)port of discharge
•  infrastructure?
•  facilities?
•  shipping frequencies?
•  information on reliable shipping lines and airlines:
•  shipping times
•  schedules
•  tariffs
•  are there ro-ro/container/conventional services?
•  what is the inducement tonnage for alternative ports of call?
•  .Is there sufficient tonnage for economical charter?

15 Seaport facilities

Capacity and condition

• ship's berth (size, draft)?
• cranes (shore, mobile, floating; ranges)?
• barges?
• forklift trucks?
•  trucks/trailers?
• slings, shackles, spreader bars, etc. (certificates)?
• quay, space/access (weight restrictions)?
• open/covered storage?

Security:

• access control (are passes required for personnel and vehicles)?
• fencing?
• lighting?
• locked stores? 

Tariffs:

• materials handling from/to ships/storage/truck etc.?
• use of equipment?
• use of open/covered storage?
• free storage time in port?
• What is clearance/on-forwarding capacity of the port?
• Port congestion, which times of year, priority berthing?
• Working hours of dock labour, opening hours of port, office hours of the port administration?

16 Airport facilities

• Airport facilities and charges for handling, storage, clearance and onforwarding of materials?
• airport agents available/required and what are their tariffs?
• International traffic?

17 Importation and exportation

• reputable and experienced agents available (check with other Companies and port authorities)?
• agent's conditions and tariffs?
• import or export licenses required (general or for certain commodities)?
• certain materials prohibited from import or export?
• import/export tariffs (duties and taxes)?
• documents required for
  • licence application?
  • importation, exportation?
  • payment (foreign currency remittance)?
• who needs these documents, how many original/copies and what are time factors involved?
• should courier services be use for document transmittal? which courier services are available?
• do documents require special clauses (country of origin, non-transferal) and/or do they require legalisation by embassy or consulate?
• is pre-shipment inspection required by Government approved agent. If so, what are procedures?
• procedures concerning dangerous goods?
• do agents provide clearance services only or also on-forwarding services. (Which transporters do they use and what are the costs)?
• time required for customs clearance and on-forwarding?
• It is essential to be very precise on documentation (pro-forma invoices, letters of credit) required for the import of material. Giving government departments exactly what they require/expect can avoid unnecessary delays (exact wording to be used, the number of copies, the size of the paper, the colour of the paper, etc).

18 Transportation

• road system LH or RH?
• road conditions (seasonal differences)?
• weight/size restrictions by road/rail/air?
• capacities of bridges?
• heights of overhead cables (HT, telephone, etc.)?
• rules for police escort and expatriate movement?
• restrictions for transport of dangerous goods (road/rail/air), such as chemicals, explosives and radioactive materials?
• road haulage contractors available:
• what is reputation?
  • do they have well trained staff?
  • what are their safety records?
  • what type of vehicles do they use, how many, what condition?
  • what are size/tonnage restrictions per type of vehicle?
  • what are optimum loads?
  • what are general tariffs?
  • what is insurance cover?
  • do they have certified/good condition lashing equipment/tarpaulins/nets?
  • is adequate supervision available during loading/offloading?
  • Is there adequate public road transport (buses, taxis)?
  • Is there possibility of car rental:
  • what firms?
  • what conditions/tariffs?
  • what is condition of vehicles?
  • what is insurance cover?
  • Is there sufficient fuel at all times?
  • What are freight transport possibilities by rail:
  • what are frequences/schedules (are they reliable)?
  • what are costs (including demurrage)?
  • is transfer required (what are costs)?
  • how is security?
  • do they have loading/lashing eqt./tarpaulins, etc.?
  • what is their insurance cover?
  • What are freight transport possibilities by fixed wing and/or helicopter (airlines, charters, military, contractors)?
  • Are flight operators and aeroplanes/helicopters approved by Company?
  • Is aircraft fuel and fuel dispensing equipment available?
  • What are schedules, capacities and rates of airline workers?
  • What are quantity, types, back-up possibilities, action radiuses and standing/flying charges for helicopters (do they accept Company standard contract terms)?
  • What are airfield/airstrip conditions and facilities (night flying, NDB, refuelling)?
• What sea transport is available:
  • liner vessel Ro-ro, general cargo, container?
  • charter?
  • supply vessel?
  • barge + tug?
  • landing craft?
  • What are schedules, shipping times, rates?
  • What are demurrage rates?
  • Do vessels have/require own gear for loading/offloading?
  • What are maximum lifting capacities?
  • What are hatch dimensions?
  • What are dimensions, capacities, draft, restrictions of vessels?
  • What flag (flag dispensation required?)?
  • Can Company charter party be used?
  • Are fuel, luboils/grease, maintenance days included?
  • Who supplies certified lifting tackle?
  • Who covers insurance of materials, contractors materials, third party liability?
  • What are weather restrictions?
  • What are safety records?
  • How is security?

19 Storage

• Is a staging area required/available?
• What size of open/covered area available?
• What is optimum location?
• How is surface/drainage?
• How is security (lighting/fencing) and safety (proximity of public areas)?
• Are watchmen required?
• How are access roads?
• What is condition of stores (construction, access for FL/truck etc., potable water, electricity/lighting, office space)?
• What are climatic conditions?
• Is racking available?
• Is fire fighting eqt. available?
• What are rental charges/rental periods?

20 Handling

• Can cranes, forklift trucks be hired (inspected/certified only)?
• What contractors are available; check
  • reputation;
  • types/quantities/condition of equipment;
  • repair possibilities/spare parts back-up;
  • safety records;
  • available slings, hooks, etc. (certification;
  • supervision;
  • skilled/licensed drivers.
• Are containers/baskets etc. required and available (check lifting appliances and certs)?
• What type/size of pallets are used (do sizes correspond with truck dimensions for economical loading)?
• Are wrapping and strapping materials and tarpaulins available?
• Are bulk handling facilities available
  • what is capacity (double or single silo)?
  • back-up compressor?
  • connections (couplings/hoses)?
• Are heavy lifting bags used; what type/capacity?
• Is Area Classification 2 required (when operating on rig site)?

21 Administration

• What is size/complexity/location of operations?
• Where will other administrative functions be based?
• What system is being used by Finance?
• What computer hardware/support is available locally, what is cost?
• What is reliability of electricity supply and what is voltage/frequency?
• Is training required?
• Are their special records and accounting procedures required by government/or partners?
• Does end-responsibility for import/export of contractor's materials rest with the company?
• Are local procedures known/available concerning materials documentation and has Group Materials been informed of relevant requirements?

22 Staffing

• What materials/supply staff will be required:
• • skills (knowledge, experience)?
  • quantity?
  • married or bachelor?
  • nationality (policies, languages, schooling)?
  • preferred age?
• What are living conditions:
  • housing/furnishing?
  • schooling?
  • food?
  • medical facilities?
  • safety/security?
  • working hours/holidays?
  • public transport?
  • postal/telephone services?
• Where will the materials/supply staff be located?
• What are leave schemes?
• Is suitable local staff available (can they be trained short-term or taken on loan form established OpCo)?
• Can work be executed in existing OpCo (or leave relief provided)?
• What are restrictions/procedures concerning work permits/visas?
• What is availability and condition of hotels and offices?

23 Emergency back-up

• What reserves are required:
  • plugging materials?
  • chemicals/cement?
  • tubular?
  • wellheads?
• Are there other companies in the country or in neighbouring countries (provided there are easy and quick import facilities)?
• Can these companies help out in case of
  • unexpected mud losses?
  • loss of hole (re-drill)?
  • delayed delivery of own supplies?
• What is the fastest mode of transportation between these parties in emergencies?
• Should assistance be on basis on loan, hire or purchase?

• Do you need an electrician? Somebody must shut off th egenerators from the time the head is connected to the time the packer is 100 m below RT. Radio silence is also required. Thesame procedure should be applied when POOH.
• Generaly, no gauge ring is run if a scraper has been used. If another packer was set previously, the zone is likely tohave been damaged. Do not run your packer in front of thiszone even if the zone has been cleaned by the scraper.
• Never run your packer below the perforations and below TDscraper.
• Be present when CCL is cheked at surface.
• Do you know the distance CCL / TOP PACKER.
• Stop at 500 m and log up 2/3 joints (check CCL and depth).
• The packer can set at anytime. If this happen, you should beable to know if it is on a collar.
• Running speed: 40 m / min.
• Remind to the operator that he should watch the tensionwhile logging up. And that he should not go below the TDscraper.
• What is the OD of the packer and of the scraper? Do you need to run a gauge?

Issues related to the preparation and/or abandonment should be included in the Well Planning Document. These could be related to a new well with or without a conductor installed or could be related to the abandonment of an existing well as a preparation for side tracking.

Conductor

Pre-installed conductors may need to be repaired or replaced.

Talon connector have a reputation of failing and therefore have to be taken out before the new well is drilled.

Issues to address are:

• Curved conductor or straight conductor
• If curved conductor, which direction?
• Conductor shoe depth
• Drive only or drill and drive
• Junk in conductor
• Circulation ports (MCJ, CGC) or not

Abandonment

To abandon the well, the X-mass tree needs to be taken off, and the BOPs need to be installed. Before taking off the tree, barriers need to be installed in the well.

The abandonment procedures depend on legislation and reservoir management

If reservoir management requires that the existing open formations are isolated to prevent cross flow, often plugs have to be set and the completion has to be pulled. Milling the packer(s) to isolate the formations may be required.

If cross flow between the perforated intervals is allowed, a simpler method can be used. A plug can be set in the upper production packer (act as a cement retainer). On top of this packer a 500 ft cement plug is set. For setting this cement plug consider using the existingg production tubing.

Other issue to be addressed:

• Well kill considerations
• Recovery of completion
• Side track options
• Casing pressure test required
• workover/ abandoment fluids: What type of mud is behind the casing. is there a rsikl of contamination. will the fluid contact the reservoir and cause mpairment?

All radio transmitters turned off ?

Radioroom locked and key held by Drilling Supervisor ?

All hand held transmitters off and locked away ?

All vehicle radios off and doors locked ?

Are there any large commercial transmitters nearby ?

Are all electric welding machines electric isolated ?

Are all personnel aware of ‘no welding’ ?

Is logging unit grounded to wellhead ?

Has potential difference between rig and logging unit been checked ?

Have road signs been installed 500ft from location warning of radio silence in progress ?

Have signs been installed around the work area warning of hazardous operation?

Are all non essential personnel instructed to keep clear of explosives ?

Is weather suitable ie., no electric / dust storms ?

Has a safety meeting been held ?

Have other locations been advised of impending radio silence and its duration ?

If perforating under drawdown, is all production equipment tested and operational ?

If H₂S is expected, have all precautions been taken ?

If kill fluid available and ready for pumping ?

Is firefighitng equipment ready ?

Is the arming key held by the Logging Engineer ?

Has a hot work permit been completed and are all precautions adhered to ?

Is fork lift truck out of use ?

1. Grounding of the wellhead, vented junction box and switchboard should be checked.
2. Phase rotation equipment should be used to ensure that the motor will rotate in the correct direction.
3. All flowline valves should be opened.
4. The voltages and kVA ratings of the power transformers should be checked.
5. The fuses, overload and underload settings should be checked.
6. The current and voltage transformer ratios should be checked.
7. The ammeter charts should correspond to the current transformer ratio, and the speed of rotation set to 1 revolution/day.
8. A pressure gauge should be installed on the flowline.
9. Bottom hole pressure and temperature should be recorded or the annulus fluid level checked.
10. If a check valve has been installed the well should be filled to surface to enable back pressure to be maintained, and the pump to operate within its recommended range. Pumping at a very high rate, out of the recommended range, may cause vibration and damage due to upthrust.

This checklist is primarily concerned with the engineering design of the well.  It is not intended to be a project planning tool covering different well, rig and time related activities such as the submission of the operational information to all the necessary regulatory authorities. It is to be completed concurrently with the compilation of the detailed programme.

As packers are probably one of the most important items of downhole equipment in well completions, great care must be taken with their preparation and installation where they are used. All packers should have been functionally checked and pressure tested in Base workshops before dispatch to the well site but should still be inspected before use.

The different makes/types of packer have different featured which must be inspected with reference to the vendor literature, however the following should not be overlooked:

• ·correct size and type;
• ·cutting edges of teeth on internal/external slips;
• ·location and integrity of springs;
• ·positioning of sleeves;
• ·number and correct material of shear pins/screws and release value;
• ·insertion/removal of set screws as required;
• ·positioning of locking devices (snap rings, etc.);
• ·expanding elements, comet hardnesss and condition;
• ·clearances between components;
• ·location and integrity of 'O'-rings, chevron and other seals;
• ·condition of screw threads;
• ·condition of polished/honed surfaces;
• ·freedom of movement of flappers;
• ·packers operating envelope.

Instances have been known where the incorrect size has been stamped on the packer body. It is therefore recommended to physically measure the OD of the packer to ensure that the correct size is being used.

• When calculating cement displacement consider very cold weather as the efficiency of the mud pumps will be reduced under these conditions.
• Drilling Contractor to provide an air heater to blow under the cement units before and during the cement operations to ensure no freezing in the cold weather. Ensure that heater is on location and working before start of operations.
• Before the cement job fluff the cement by transferring from one tank to another tank to ensure it will transfer in the cold weather.
• Cementing Compay needs to ensure that their equipment has had the water blown out after pressure testing.
• When running in the NBP pulling tool it had to be pushed into the hole as the side valves on the well head were frozen and the fluid could not be drained from the stack. While pulling out of hole the steam truck should be utilized to ensure the side valves are not frozen.
• For 3SB-ST connections to avoid over doping in cold weather apply dope as normal to pin but only to seal area of coupling. Refer to Tenaris Operational Guidelines (in this folder).

• Analyse logging and survey data from original hole
• Select base of higher ROP interval as sidetrack point (probable over gauge hole overlying gauge hole)
• Sidetrack point with inclination or dog-leg in original hole will be advantageous
• Optimise cement slurry recipe (potential for gas cut)
• Confirm cement quality by drill off test
• BHA for first attempt should be capable of drilling to TD
• Should first attempt fail then dedicated sidetrack BHA with tri-cone bit and 2.2 deg bend motor should be used to initiate sidetrack.
• Dedicated sidetrack PDC bit (if available) should be on location

Rope Socket Kit

• 1 x Spear Head Over Shot 1 11/16” O.D.
• 1 x Wireline Swivel 1 11/16” O.D.
• 1 x Top Sub
• 2 x Cone Type Rope Socket for Cut & Thread
• 1 x Spear Head Sub

Overshot Kit

• 1x Guide 5 ¾”
• 1 x Guide 4 ¼”
• 1 x Guide Control
• 3 x Grapple 2 5/16” for Logging Head
• 1 x Bowl w/Circulating Holes
• 1 x Bowen Overshot Bushing

Auxillary Equipment

• 1 x 6 ft. Fishing sling 10 ton SWL
• 2 x 7-46 Cable Sinker Bars
• 8 x Sinker Bar Pins
• 2 x T-Bar Clamp w/7-46 Cable Bushings
• 1 x Spare 7-46 Bushings for 7-46 Cable
• 1 x Circulating Sub w/ 4 ½” IF thread

Pre-cutting of core

• Check that the inside of the core barrel is clear of manufacturing or any other residue.
• Ensure adequate stock of coring consumables are available, plus cradles, saw etc for laydown
• Hold meeting with geologist, core hand and TP to confirm procedures
• Before dropping the ball insure that there is no restriction in the string. (mud check valve etc)
• Consider increasing the mud weight for coring/ drilling the reservoir. This could reduce the washout, lower gas readings and improve coring performance

Core Recovery / Handling Procedures for recovering and transporting unconsolidated core

• Refer to Wellsite Coring Guideline document
• Have sufficient plastic water bottles available for mud samples
• Ensure rig crew are aware of method to trip core from hole e.g. min rotation, jarring etc
• Prior to laying out of the core, hold informal meeting with key personnel and rig crews to discuss safe, effective handling procedures
• Ensure geologist has all necessary equipment and a suitable area to process the core
• Have crane driver ready to assist laydown and make sure he understands his task
• Get full operational summary from corehand prior to his departure

• Operations Engineer to organise pre-job meeting at the rig site with rig and office personnel to discuss the job objective and hazards.
• Pictorials to be prepared and discussed during pre-job meeting so it can be followed during rigging up.
• When MRX logging is required, ensure that two units available on location prior to starting the job.
• Ensure that all personnel are standing clear of the catwalk when hoisting the tools from the cat walk to the rig floor.
• Ensure that a tag line is attached to the load to keep control of any swinging.
• When performing free point and back off operations, ensure that a correct bicycle size is used to avoid any potential damage to wireline  due to sheave damage.

To prevent diferential sticking, Strict attention should be paid to drilling practices at all times whilst in open hole.

• Hold toolbox meetings with all crews including mud engineer and mud logging engineer to discuss differential sticking and the action to be taken to avoid it.  Holld meetings before starting the interval and a refresher whilst in the reservoir.
• The drillstring has EPDP pipe to help stabilise the string and minimize wall contact. 
• Minimize time in the slips and keep pipe moving at all other times when not in the slips.  Reciprocation is preferable to rotation in this respect.
• Drillers to utilize a hand over sheet detailing all overpulls experienced, on/off bottom torques, mud properties, etc. 
• The bridging materials in the mud and programmed filtration properties will assist in reducing the risk.
• Maintain mud weight at a safe minimum
• Keep solids content and fluid loss to an economic minimum
• Stuck pipe analysis has shown that most incidents occur within two hours either side of shift change.  Drilling Supervisor and Parker Toolpusher will ensure that either of them is on the rig floor at least 1 hour before and 1 hour after the driller’s have crew changed.  
• Should a stuck pipe incident occur due to differential sticking it is important to act fast and pump a pill to try and free the pipe.  Consult Mud Engineer for the stuck pipe chemicals available for use.  These should be at the rigsite ready for use.
• Minimise the time which the drill string is not being reciprocated or rotated

The drilling fluids programme contains further information and details of spotting fluids which may be used in the event that differential sticking is observed.

Lost Circulation

Lost Circulation is a risk in the production zone.  Should losses occur, reduce ROP, minimize flowrate (considering hole cleaning at the new ROP).  Under no circumstances add any LCM without pre-discussion with town. . 

Sour Gas (H2S, CO2)

Maintain lime excess in the appropriate range: average >9 kg/m³

General Information

• File name and location
• Well Name
• Classification
• Country
• Concession
• Ground Level
• Surface Location: Lattitiude ___ N, Longitude ___ E
• Surface Coordinates: Field ___ N, Field ___ E
• Seismic Line
• Cost Centre
• Planned Total Depth
• Rig
• Objective (top Hydrocarbon)
• Target Coordinates and Tolerances
• Coring requirements

Casing Programme Summary

• Hole size / Depth / OD / Wt / Grade / Coupling / Top Cement

Mud Programme Summary

• Hole size / Mud type / Density

Logging Programme Summary

• Hole size / logging programme

Coring Programme Summary

• Hoe size / Formation / depth

Possible Drilling Problems

• Hole size / Problem

Approvals

• Name / Position / Signature / Date

Detailed Programme

General Planning Notes:

This section should describe the general planning notes:

• This programme is a guide to help ensure that safe and efficient operations are carried out. The Drilling Supervisors must review this programme and suggest appropriate changes to further enhance safety and efficiency.
• Any changes to the programmed activities should be discussed with and approved by the Drilling Superintendent.
• In order to capture the information while the well is being drilled, the Drilling Supervisors will are to meet the following requirements:

•  
  • A daily diary is to be kept. This will record informal notes on drilling the well, including ideas and recommendations for improving operations on the following well. This will ensure that data not traditionally recorded by the daily reporting systems but that will be valuable for future well planning will not be lost. Information is especially required on each formation encountered; recommendations for improved bit/BHA selection, particular drilling practices etc.
  • The diary must also record the reasoning behind decisions made on the rig which affect drilling operations. Decisions such as which bit to run, or why to wiper trip (if different to this well programme) must be justified with an engineering analysis showing the expected benefits of the change.
  • At the end of a hitch each Drilling Supervisor will write a short, informal report for the office which can be used as the basis for the final well report. This will give specific details on problems encountered (how solved and recommendations to avoid or mitigate those problems on future wells), reasons behind decisions made on the rig and anything else that is relevant to evaluating drilling performance.

• A separate file (“Notes for Drilling Supervisors”), will contain information on daily drilling reports, cost reporting, mud inventory etc and general advisory and contact information.
• Any changes to the approved drilling programme will be documented using the Management of Change procedure.
• Operations are to be carried out safely, in accordance with good oilfield practice and in compliance with the Company Drilling and Technical Manuals, unless dispensation has been granted from the Drilling Manager. Operations should be executed to minimise adverse impact on the environment.
• Drillstring components are to have been inspected to API RP7G prior to running in the hole. Ensure that all drillcollars have stress relief grooves and are bored back, steel DC’s are to be spiral.
• The programme should make reference to the offset wells applicable: Well Name / Approx Surface Distance / Approx Direction /
• Depths given in this programme are in metres BRT.  RT elevation is assumed to be Xm above MSL.
• Shallow gas review based on seismic surveys and offset wells.
• Minimum stocks to be kept on site during drilling; 100MT Baryte, 500 SX LCM and 1000 SX cement.
• Leakoff tests will be performed after drilling out all casings where a BOP is in use.
• Measure mud density with both Pressurised and Atmospheric balances and record this at 15 minute intervals while drilling for mud in the pits and at the flowline, for all sections below the surface casing.  Use the pressurised balance measurement for maintaining the correct mud density.
• Floats should have a small hole in them to allow drillpipe fillup while RIH and to allow direct readout of DP pressure if we get a kick.  The float will still be effective against heavy backflow and will enhance safety while tripping.
• Amendments to this Drilling Programme will be sent from the Drilling Office from time to time.  For minor changes which do not impact on the well design and do not have serious operational impact, this will be approved by the Drilling Superintendent.  For larger changes, some or all of the original signatories may sign.

Pre-spud: positioning and anchor operations

Drilling Operations

Planning for each hole section:

• Drilling Practices
• Kick Tolerance at TD for expected pore pressure and fracture gradient
• Any special notes or requirementsReporting requirements (daily and post-well);
• Monitoring cavings levels and sampling / describing / preserving cavings;
• Mud sampling requirements (times, sample sizes, how preserved etc);
• Mud gradients, types, required properties, pH, test requirements, any special requirements (such as shale inhibition);
• Wellbore Stability requirements;Potential ProblemsMud - formation requirements;
• Solids Control requirements.
• Recommended Bits and BHA’s
• Hydraulics