Abandonment and sidetrack drilling programme


07 abandonment sidetrack1. Programme Summary


This programme will prepare the existing well for a forthcoming horizontal side-track which is due to begin immediately upon the successful completion of the abandonment. Due to the target constraints, the abandonment will commence from below the existing 20" shoe.

The existing completion will be retrieved from the wellhead down to the ELTSR which is located just above the production packer. The well will then be abandoned with cement plugs. After cutting and retrieving (and milling if necessary) a quantity of 9-5/8" casing, a window shall be milled in the 13-3/8" casing.


A 12-1/4" hole will be drilled out of the window in the13-3/8" casing prior to setting the 9-5/8" casing. The 9-5/8"casing point has been chosen to reduce the open hole time for the subsequent 8-1/2" build up section (from 12 deg. to 65 deg. of inclination) over troublesome sticky shales to as short a time as possible. A 6" hole willbe drilled out of the 7" liner and continue to build until horizontal, thehorizontal section will be 3000' long. The side-track is to be drilled horizontally as close as possible to the top of the reservoir in order to maximisethe recovery of the attic oil.


The existing mud behind the 9-5/8" casing is gypsum lignosulphonate, following the casing cut H2S may be circulated to surface. The H2S may have been produced due to the degradation of the WBM.

The formation which overlies the chalk is known for itsreactive (sticky) shales.

The well will pass through the Zechstein dolomites wherelosses have been encountered on previous occasions due to the fractured nature of this reservoir.

At T.D. of the horizontal section the well is planned to intercept an abandoned appraisal well. The planned separation factor of 0.1 isnot considered to be a problem as the well was successfully abandoned. The well did not penetrate any other deeper reservoirs of a higher pressure.

2. Preparation and Background

Wellhead and X-mas tree

The existing equipment is a 3000 psi Cameron X-mas treemated directly to a 3000 psi WP Cameron wellhead (pack-off, casing spool and housing).

Reservoir data

Reservoir pressure : 3500 +/- 100 psi at 7735' tvbdf

HC gradient : 0.33 psi/ft

Water gradient : 0.48 psi/ft

Perforations AHBDF : 10000' - 11000' 2-1/8" slimkone 4spf.

Geological prognosis

Formation TVBDF Accuracy

Geological targets

Deviation data sheet

Requirements for offshore staff

Prior to the commencement of the milling operations the rig should be in possession of the latest definitive data set for the area (including relevant exploration and appraisal wells) and the proposed wellplan.

Drilling Targets

The target sizes noted in section 2.6 (above) refer to the geological target only.

The lateral drilling target sizes are calculated by subtractingfrom the geological lateral target the survey tool uncertainties (lateral).

The vertical drilling target sizes are calculated by subtracting from the geological vertical target the vertical survey tool uncertainty.

The drilling targets are: xxxx


The S.F. is 1.3 between 11000' and 11200' ahbdf. As the wellhas been abandoned and side-tracked no further action is required.


Mud logging: A geologist will be on site from the 7" liner shoe onwards. Monitoring of cuttings should begin after the casing has been set in the top of the chalk. Two sets of wet cuttings and one set of dry cuttings are required every 30'. Logging of the cuttings will assist in the early recognition of the reservoir.

Logging: MWD/GR is required in the 8-1/2" section to facilitate the picking of the top chalk (casing point). MWD/GR is also requiredin the 6" section to assist in the early recognition and correlation of the reservoir units. Logging at T.D. of the 6" section will involve the following pipe conveyed logging equipment; GR/LDT/CNT/DSI/ARI/FMI. RFT locations will be advised nearer the time.


A separate completion programme will be issued nearer to the required time.


The drilling and well services BOPs, risers and lubricators should be rated to 5000psi. Ensure that the latest workshop test dates are checked.

Upon arrival on the rig all equipment should be thoroughly inspected to ensure that it is fit for the intended purpose.

In case of asphaltene deposits being encountered in the wellbore, asphaltene dissolver (Clear 2961) should be available.

The well shall be killed by circulating to kill weight WBM via punched holes in the tubing. WBM will be used instead of bull heading to brine because it can also be used for the subsequent milling operations. A Schlumberger tubing punch will be required to punch holes in the 3-1/2" 9.3 lbs/ft. tubing just above the 2.813 OTIS nipple. Ensure that sufficient explosive charges (10' carrier length with "small" tubing punch charges) are on-board.

Plugs are planned to be set in either the 2.313 or 2.813OTIS nipples, should this prove to be impossible then the contingency will be to set a Pengo plug. Ensure that two 2.187" Pengo plugs (range 2.375"-3.000"), adapter kits and Baker series 10 setting kits are on board.

A 7" PES plug (hydraulic set) should be onboard in case either the TWCV profile is damaged or the pressure tests fail.

The kill weight for the brine has been calculated to provide 200 psi overbalance at the top of the tubing punch holes of 10348' ahbdf (7419' tvbdf).

Maximum anticipated reservoir pressure = 3600 psi at 7735' tvbdf.

Assume oil gradient between 7735' and 7419' tvbdf is 0.35psi/ft.

Assume casing housing is at 50' tvbdf.

Kill fluid gradient = [3600 - (7735'-7419') 0.35 + 200] 7419'-50' = 0.500 psi/ft.

3. Detailed Programme

3.1 Preparation

3.1.1 Skid rig and transfer control

Notes :

- Prior to operations commencing, soak the tubing hanger tie-down bolts in penetrating oil.

- Prior to the start of operations check the annula rpressures and record on the DR.

- Ensure that sufficient WBM is mixed to carry out two full circulation's whilst having a reserve for LCM pills.

1) Mix WBM as per mud programme.

2) Skid the rig over and take control of it from Production.

3) Check the integrity of the tubing hanger seal.

3.1.2 Well kill

Notes :

- The well will be killed by circulating to WBM via punched holes in the tubing. The same mud will be used for the subsequent milling operations.

- A 10' carrier length of tubing punch with 4 spf and "small" tubing punch charges should be used.

- The required kill weight is 500 pptf, note that there is already 520 pptf CaCl2 brine in the "A" annulus. Sufficient quantities of LCM must be onboard prior to commencing the well kill.

- Ensure that the production facilities can accommodate a possibly large quantity of contaminated fluids.

1) Rig up the Schlumberger lubricator and BOP, install the CCL/10' tubing punch toolstring and pressure test to 3000 psi for 5 mins. RIH, correlate on depth and punch holes between 10348' and 10338' i.e. in the first full joint above the 2.813 OTIS nipple.

2) Rig up kill lines to the KWV and the"A"-annulus outlet valve and test to 3000 psi.

3) Perform a reverse well kill by pumping a 500' equivalent seawater spacer followed by WBM through the "A" annulus and up through the tubing via the drilling choke to the production facilities. Ensure that the surface pressure does not exceed 2500 psi due to the tubing having been successfully pressure tested to only 3000 psi.

4) After reverse circulation line up the well to the trip tank and observe the well for losses. If losses are greater than 30 bbls/hr, pump and displace a 50 bbls pill as per the recipe below:

Pill for losses >30bbls/hr

Pump a viscous spacer (2 ppb X/C polymer) prior to the 50 bbl. viscous LCM pill.

30 ppb limestone grit 30 ppb Carb 425 30 ppb Carb 200

If no limestone grit is available use the following recipe instead;

45 ppb Carb 425 (coarse) 45 ppb Carb 200 (coarse &medium)

If losses are less than 30 bbls/hr, pump and displace a 50bbl pill as per the recipe below:

Pill for losses <30 bbls/hr

50 bbl. viscous LCM pill :

20 ppb Carb 200 20 ppb Snocal G2 20 ppb Snocal 3ML 10 ppbmica coarse 10 ppb mica medium 10 ppb mica fine

If no mica is available use the following recipe instead;

30 ppb Carb 200 30 ppb Snocal G2 30 ppb Snocal 3ML

Allow the pill to soak, if losses are reduced to 20 bbl/hr or less continue with the programme, if greater than 20 bbls/hr pump a second LCM pill.

3.1.3 Install plug in 2.313" OTIS nipple

Notes :

If it proves impossible to set the 2.313" plug then follow Appendix 2 and set a plug in the 2.813" OTIS nipple, or if that too fails a Pengo plug in the 3-1/2" tubing below the MOE.

Set plug as per Well Servicing Proedures.

1) R/U drift assembly and pressure test to 3000 psi. Perform a drift run to the HUD, POOH and R/D.

2) R/U and test as above with an OTIS 2.313" plug in the lubricator. RIH and set in the OTIS 2.313" landing nipple at 10454',POOH and R/D.

3) Pressure test the plug to 2000 psi whilst monitoring the"A" annulus for returns.

4) Perform an inflow test as per Standard Procedures.

3.1.4 Install TWCV

1) Install the TWCV in the tubing hanger profile.

2) Pressure test the TWCV to 2000 psi from above for 15 mins.

3) Pressure test the TWCV to 2000 psi from below for 15 mins. via the "A" annulus. The KWV should be kept open during this test and monitored for returns.

Note :

A 7" PES bridge plug (hydraulic set) should be on board as a contingency.


At this stage the barriers in the well are;

i) Plug set in the 2.313" OTIS nipple, pressure tested to 2000 psi and inflow tested.

ii) Tubing and annulus filled with 500 pptf mud.

iii) A TWCV set in the tubing hanger, pressure tested to2000 psi from above and below.

iv) Tubing hanger/"A" annulus seals pressure tested.

v) Production packer pressure and inflow tested at installation.

3.2 Removal of Tubulars

3.2.1 Remove X-mas tree

1) Check the condition of the tubing hanger tie-down bolts,if in poor condition change them and the chevron seals out one at a time.

Notes : Ensure that any pressure between the tubing hanger seals and the X-mas tree P-seals has been blown down prior to replacing the tie-downbolts.

Keep the tubing hanger seal fully energised whilst all the tie-down bolts are been replaced.

2) Ensure that the X-mas tree seals have been fullyde-energised.

3) Nipple down and remove the X-mas tree. Check the condition of the thread for pulling the tubing hanger and tubing. Make up the hanger pulling tool to the thread, count the number of turns for make-up. (Ifthe thread is in poor condition a spear will be used.)

4) Isolate the control line, in order to prevent pressurebleed-off during testing the BOP's.

3.2.2 Install riser and BOP stack

1) Install an 11" 3000 psi * 13-5/8" 10,000 psi adapter flange, riser and 13-5/8" BOP stack with rams as follows (from top):

Variable bore rams (7" - 4-1/2") Blind shear ramsVariable bore pipe rams (2-7/8" - 5").

2) Install a chicksan line from one of the "A"annulus outlets to a BOP side outlet (to allow fluid to bypass the hanger when circulating or lowering/ pulling the hanger). Ensure that the chicksan line istested when the BOP's are tested.

3) RIH with 5" drillpipe, BOP test tool and crossover.Make up into the tubing hanger threads. If the hanger threads are corroded or damaged it will not be possible to make up the crossover tool. Space a drill pipe tooljoint immediately under the rams being tested (in order to avoid upward movement of the string while testing).

4) Test lower rams, chicksan loop (against a closed valve) to 3000 psi and the Hydril to 2000 psi. Remove the test string. Test the blind shear rams to 3000 psi against the TWCV. Monitor the volumes pumped.

5) Run a drift through the BOP stack and riser to ensure clear passage for pulling the tubing hanger/seal assembly.

3.2.3 Recover TWCV

Run in and retrieve the TWCV.

3.2.4 Recover tubing

Notes :

Recover tubulars as per Tubing Recovery Procedures.

It is not anticipated that radioactive scale will be encountered during the recovery of these tubulars, however, precautions should be followed as indicated above.

A Schlumberger tubing cutter should be on board as a contingency.

1) RIH 7" landing joint and engage with the hanger threads (chain tong tight), count the number of turns. Alternatively, if the tubing hanger threads are damaged RIH with a 7" casing spear. Back out the tubing hanger tie-down bolts fully to permit pulling of the hanger.

2) Unseat the tubing hanger and shear off the extend a joint from the slick joint assembly (string weight up 135 klbs, down 110 klbs and landed with 15 klbs compression when installed originally).

3) Pull back to rotary table, observe well and if required carry out one circulation.

4) If the well is static or losses are less than 20 bbls/hr., POOH and L/D the tubing whilst keeping the annulus full. Observe closely for overpulls which may indicate the loss of control line clamps. Maintain tension on the control line while pulling to give an indication of control line integrity.

Record the number of control line clamps recovered on the DDR. The total number of control line clamps installed when the well was completed originally was not recorded.

Number all of the joints sequentially as they are pulled out of the well with water proof paint. Inspect all joints visually and report the tubing condition. Any joints with obvious defects should be bundled separatelyand noted in the DDR.

If losses are greater than 20 bbls/hr. then pump LCM pills as indicated in section 3.1.2 Well kill.

Note :

Ensure that an adequate number of protectors are on site.

3.2.5 Install wearbushing

Install the wearbushing.

3.3 Abandonment of reservoir

3.3.1 Abandon reservoir

Note :

Abandon the reservoir as perGUIDEX>Procedures>Suspension and Abandonment>Plugging back. GUIDEXstates that the final cement plug should be approximately 500' long with theTOC at least 100' above the previous shoe (in this case assume TOL).

1) RIH with a 500' of 2-7/8" tubing stinger, 1000' of3-1/2" DP and 5" DP to surface. The top of the liner is at 9065'ahbdf.

2) Cement plug No.1 = 10365'-9865'. With the stinger abovethe remainder of the ELTSR slickjoint at 10365'ahbdf pump a 30 bbl preflushthen set a 500' balanced cement plug. Pull back 100' above the TTOC, close theannular and reverse circulate the string clean. Perform a hesitation squeezeand attempt to squeeze away 5 bbls. POOH.

The cement recipe for plug No.1 is; Cement/mixwater : ClassG/freshwater Weight : 830 pptf Slurry yield : 4.73 bbls/MT. M/W requirement :2.72 bbls/MT. (includes additives) Additives (by volume) : Halad-22A = 0.4%CFR3 = 0.5% D81 = 0.03 gps D47 = 0.02 gps

Pumping time : 4 hrs. 15 mins Thickening time : 4 hrs. 40mins Setting time : 8 hrs. 30 mins

Notes :

The mixwater should be made up at least 4 hrs. prior to, butnot more than 24 hrs. before mixing the slurry. If background gas has beendetected then 2% (by slurry volume) Drillfoam S55 should be injected at thesuction side of the cement unit.

The spacers are mud with 1.5 ppb X/C polymer and weighted toa weight mid-way between the cement and mud densities.

Preflush : 30 bbls of weighted spacer Postflush : Suitablefor balanced plug.

3) RIH with a 6" slick assembly. Dress off the cementby 20', weight test the plug to 15 klbs. (whilst circulating) and then circulatethe hole clean.

4) Establish a base annular flow from the "B"annulus. Pressure test the cement plug to 3000 psi in leak-off mode and monitorfor returns from the "B" annulus.

5) Inflow test the plug by displacing the string toseawater, this will provide approximately 120 psi drawdown on the anticipatedreservoir pressure of 3500 psi. POOH.

6) Spot a viscous pill below the bottom of the next cementplug (9365').

7) Cement plug No.2 = 9365' - 8865'. Pump a 30 bbl preflushthen set the second 500' cement plug. Pull back 100' above the TTOC, close theannular and reverse circulate the string clean. Perform a hesitation squeezeand attempt to squeeze away 5 bbls. POOH.

If losses have been observed contact base as it may benecessary to set a further cement plug. POOH with the stinger.

The cement recipe for plug No.2 is; Cement/mixwater : ClassG/freshwater Weight : 830 pptf Slurry yield : 4.72 bbls/MT. M/W requirement :2.74 bbls/MT. (includes additives) Additives (by volume) : CFR3 = 0.1% D81 =0.06 gps D47 = 0.02 gps

Pumping time : Thickening time : Setting time :

3.4 Sidetrack

The procedures outlined in sections 3.4.1 and 3.4.2 can beexpanded upon from the notes in Appendix 4.

Check the dimensions of all equipment and make drawings ofall sub-assemblies on site.

The maximum TTOC (no open hole excess is assumed) in the 9-5/8" - 13-3/8" annulus is 1840 ahbdf, consequently it is not expected that cement will be encountered whilst cutting and retrieving the9 -5/8" casing. If a 10% open hole excess is assumed the TTOC is at 2322' ahbdf. Baryte settlement may also cause problems in retrieving the casing.

Milling equipment should be on board prior to commencing the sidetrack.

A free point indicator should be onboard as a contingency.

** CBL/CET required due to comment in cement reportindicating TOC at surface **

3.4.1 Cut and retrieve 9-5/8" casing

1) Rig up a temporary flow line from a "B" annulusside outlet valve to the circulating system.

2) RIH with the casing cutter and cut the 9-5/8" casingat 1750'ahbdf. The maximum knife opening is 10-3/4".

3) Attempt to circulate by closing the Hydril and taking returns via the "B" annulus side outlet valves. Restrict the surface pressure to protect the integrity of the 20" shoe. The 20" EMMG =0.772 psi/ft (using 510 pptf mud). POOH.

Notes :

The original 12-1/4" hole was drilled with a gypsum lignosulphonate seawater mud. Pump a viscous spacer ahead of the brine prior to circulating out the old mud.

The mud behind the 9-5/8" casing may have degraded andH2S may be detected at surface, normal H2S precautions must be adhered to.

4) Retrieve the wear bushing.

5) Retrieve the pack-off seal assembly.

6) M/U casing spear assembly and retrieve the casing.

3.4.2 Mill 13-3/8" window

Note :

Constant observation and recording of the steel recoveryrate versus the milling rate is required.

1) RIH with Red Baron section mill BHA and cut casing at1620'.

2) Mill casing from 1620' to 1720' whilst circulatingbottoms up periodically and also rotating and reciprocating the string.

3) Clean the hole and POOH.

3.4.3 Set kick-off plug and displace to Petrofree

Note :

Use a 20% open hole excess for the portion of the kick-offplug opposite open hole.

1) RIH with 500' of 3-1/2" stinger, and spot a viscouspill below the bottom of the proposed cement plug (1820').

2) Kick-off plug = 1820' - 1520'. Pump a 30 bbl preflushthen set a 300' balanced cement plug. Pull back 100' above the TTOC, close theannular and reverse circulate the string clean. Perform a hesitation squeezeand attempt to squeeze away 5 bbls. POOH.

The cement recipe for the kick-off plug is; Cement/mixwater: Class G/freshwater Weight : pptf Slurry yield : bbls/MT. M/W requirement : bbls/MT.(including additives) Additives (by volume) : CFR3 = D81 = D47 =

? Pumping time : Thickening time : Setting time :

3) RIH with 12-1/4" cleanout assembly, locate TOC anddress off by 20', weight test to 15 klbs and pressure test to 1000 psi.

4) Displace well to Petrofree and condition mud.

4) Dress off cement to 1620' (top of 13-3/8" casingcut).

5) POOH with cleanout assembly.

3.5 12-1/4" hole section

Notes :

The 12-1/4" section is planned to T.D. at 5018 tvbdf (5149'ahbdf). This depth has been chosen for the following reasons : - To reduce the length of the subsequent 8-1/2" section as much as possible asit will contain the sticky shales above the chalk. - To permit the jet pump ofthe completion to be set as deep as practical in order to provide an artificiallift capability.

The Compass anti-collision data scan based upon the well having SDC Finder from seabed to 1600' and MWD to section T.D. indicates that the following wells have the lowest separation factors :


Recent experience drilling the formations between 1500' and 5200' ahbdf has been with OBM (not Pseudo), few problems were noted other than slight packing off of the hole andassociated minor overpulls (<20 klbs).

Ensure that the gyro is compatible with the UBHO sub. Run the gyro every stand until the MWD is free from magnetic interference.

Refer to Appendix 5 for details on the parameters required for the mud and hydraulics for this hole section.

Avoid pumping whilst passing the bit and motor through thewindow to avoid flipping over the motor as a result of reactive torque. The chance of creating a washout is also reduced.

3.5.1 Drilling 12-1/4" hole

1) M/U the 12-1/4" drilling assembly comprising 9-1/2" Navi-drill set @ 1.0 deg.and UBHO sub. RIH to the top of the13-3/8" casing window.

2) R/U SDC and run the Finder steering tool to the UBHO subto orientate the BHA.

3) Perform the kick-off with the toolface set to the lowside.

4) Drill ahead to section T.D. at 5149'ahbdf.

5) Make wiper trips every 500' or more frequently ifconditions dictate otherwise.

3.6 Run 9-5/8" casing

Note :

Refer to standard procedures for casing and cubing running and cementing requirements on centralizers, spacers etc.

1) Run the 9-5/8" casing as per programme cover sheetto 5129'ahbdf.

2) Cement the casing with a 20% open hole excess having the TTOC at 2000'ahbdf. The tail cement is designed to provide extra strength overthe bottom 500'.

3) Pressure test casing to 3000 psi upon bump.

3.7 8-1/2" hole section

Notes :

The 8-1/2" section is planned to T.D. at 7334' tvbdf (8012'ahbdf) i.e. the 7" liner shoe is to be set 50' tv into the deepest prognosed top chalk at an inclination of 62 deg. The aim is to case off thesticky shale section above the top of the chalk as quickly as possible.

The Compass anti-collision data scan based upon the well having RIGS from seabed to 4800' and MWD to section T.D. at 8012' ahbdf indicates that the following wells have the lowest separation factors :

The Zechstein formation should not be encountered in this hole section, however LCM materials should be on board as a contingency as it ishighly fractured.

Recent experience drilling the formations between approximately 5000' and 7200'tvbdf has been with OBM (not Pseudo). Apart from minor occurrences of pack-offs and associated overpulls the only major problemwas encountered when the well had to be side-tracked due to severe problems possibly caused by the 12-1/4" rat hole.

Refer to Appendix 5 for further details on the parameters required for the mud and hydraulics in this hole section.

Carry out the leak-off test and fax the results (including graph) immediately following the test.

3.7.1 Drilling 8-1/2" hole

1) M/U the 8-1/2" drilling assembly comprising of a6-3/4" Navi-drill, MWD etc.

2) After drilling 20' of new formation carry out a leak-offtest.

3) Drill ahead to section T.D. at 8012'ahbdf. The T.D. maybe extended if the chalk has not been found on depth. If necessary consult with base.

4) Make wiper trips every 500' or more frequently if conditions dictate otherwise. POOH.

3.8 Run 7" liner

3.8.1 Liner equipment

1) Liner string Float shoe Two joints of casing for the shoetrack Float collar Joints of 7"/29lbs#/13%Cr/L80/VAM to 4629' (500' inside9-5/8" shoe).

N.B. Install one flexible centralizer per joint - shoe track= ?? - open hole = ??

2) Liner hanger sub-assembly Liner hanger assembly PBRtie-back sleeve Running tool 5" HWDP 5" DP to surface

3.8.2 Liner running and cementing procedures


Run and Cement the liner as per Standard Procedures.

Perform a check trip with all of the 5" HWDP requiredfor running the liner and circulate at least 2 times bottoms up and POOH.

Drift the string on POOH to ensure free travel for the liner setting ball.

Before entering open hole with the liner, stop and break circulation to condition the mud by reducing its viscosity.

Use a 10% open hole volume excess for the cement volumes.

The density of the main slurry must be as stated in the programme cover page i.e. 830 pptf.

Always use a Halliburton "Tru-weight" balance and not a Baroid mud balance to monitor the cement density.

If the batch tank is unable to accommodate all of the mainslurry then the recipe excess may be mixed and pumped conventionally prior to pumping the slurry from the batch tank.

1) Run the liner assembly to 5' above the 8-1/2"section TD. Slight adjustment may be required to allow the top of the PBR to be spaced out such that the sealing elements of the tie-back packer will not be within 3' of a casing connection.

2) Batch mix the scavenger slurry as per the drilling programme cover sheet in the batch tank. The scavenger slurry should fill 500' of 9-5/8" casing with the drillpipe removed.

3) Pump 250' equivalent of the scavenger mixwater (i.e. nosilicalite).

4) Pump the scavenger slurry.

5) Weigh up the remainder of the scavenger slurry to the weight required for the main slurry.

6) Pump the main slurry.

3.8.3 Dress off the PBR

Note :

The DSV must be on the rig floor during all operations inside the PBR.

1) M/U the following BHA; 6" bit 3-1/2" DP Tiebac kmill Spacer sub 5" HWDP 5" DP

Space out the tieback mill so that the bit will be 5' abovethe HUD when the tieback mill bottoms out in the PBR.

2) RIH with the tieback mill assembly. Circulate clean priorto entering the PBR.

3) Clean out the PBR with the tieback mill. Observe a pressure increase as the mill enters the PBR and a further pressure increase 6' deeper as the mill shoulders out on the 30 deg. chamfer at the bottom of the PBR. Back out of the PBR rotating slowly. Do not re-enter the PBR with the tieback mill. Mark the pipe when above the PBR as a reference point.

4) POOH.

3.8.4 Run the tieback packer

Note :

The JM tieback packer assembly consists of a compression set tieback packer with centralising lugs (welded onto the packer body), a 6.25'PBR above and a PBR seal stem below with 3 stacks of packer seal elements.

The seal elements seal in the first 3' of the PBR. Theassembly is already made up to the special running tool complete with a thrust bearing and seal assembly which is located into the PBR on top of the packer.The complete assembly is pressure tested to 4000 psi prior to shipment offshore.

Run and set the tieback packer as per Procedures.

1) Run and set the tieback packer as per note (above).

2) Pressure test the 9-5/8" casing and 7" liner to3000 psi for 30 mins.

3) Perform an inflow test by displacing the string toseawater.

3.9 6" hole section

Notes :

well control guidelines in horizontal sections should be available for consultation offshore.

The 6" hole section is planed to build up to horizontal from 62 deg. at a BUR of 6 deg./100'. The horizontal section is 3040' long.

The Compass anti-collision data scan based upon well havingRIGS from seabed to 4800', SDC Finder from 4800' to 8000' and MWD to the section T.D. at 11,934' ahbdf indicates that the following wells have the lowest separation factors :

xxx List of nearby wells with separation factors xxx

The mud weight for the 6" section should be a least 490pptf pptf based upon the data presented in section 2, Preparation and background.

i.e. Max. reservoir pressure = 3600 psi at 7735'tvbdf. Wellprofile TVD = 7660'tvbdf. Oil gradient = 0.33 psi/ft between 7735' and 7660'Safety margin = 200 psi

Mud weight = 3600psi - (7735'-7660')0.33 + 200psi 7660' = 486 pptf

Drag and torque are not a concern in this particular 3000'horizontal section. See Appendix 6 for further details.

When using a steerable motor assembly minimise pumping whilstthe bit is inside the casing/liner to avoid damage to the liner.

The Cansco PBL circulating sub should be available onboardfor running above the 3-1/2" DP in case problems are experienced with hole cleaning. The circulating sub should not be used whilst drilling.

BHA wear has been experienced whilst drilling the 6" horizontal section, therefore drill a maximum of 1000' or 70 hr between inspections.

Carry out the leak-off test Fax the results (including graph) immediately following the test.

3.9.1 Drilling 6" hole and displace to TAME

1) M/U the 6" drilling assembly comprising of a 4-3/4" Navi-drill, MWD etc. and RIH.

2) Displace the hole to BW Mud's TAME.

3) After drilling 20' of new formation carry out a leak-off test.

4) Drill ahead to section T.D. at 11934'ahbdf.

5) Make wiper trips every 500' or more frequently ifconditions dictate otherwise.

6) Refer to Appendix 5 for further details on the parameters required for the mud and hydraulics for this hole section.

3.10 Logging

Notes :

A third run may be required due to possible compatibility problems between some of the Schlumberger tools. A final decision will be made nearer to the time.

The ARI tool requires the MAXIS unit.

A spare cable drum must be on site.

1) Carry out the following Schlumberger drillpipe conveyed logs from T.D. to the 7" liner shoe.


Run 2 : GR/FMI/RFT

2) After the logging runs perform a check trip. Ream if necessary. Do not use a rock bit, thus minimising the risk of side-tracking thewell, rather use the bit which was used to drill the original section.

3.11 Run 4-1/2" slotted liner

Note :

Due to an as yet undetermined problem of excessive sand production, the decision on whether to run either a slotted liner or pre-packed screens will be deferred until Production Technology have examined the sonic and density logs from the 6" section. The need to defer the decision onwhether to run either a slotted liner or pre-packed screens effectively meansthat the rig must be prepared to run either completion. An additional programme(s) will be issued nearer the relevant time.




1. Policy exemption package.

2. Target isometric diagram.

3. Deviation data sheet.

4. Anti-collision data sheet.

5. BHI enclosures.


CASE 1 : Drilling the 12-1/4" hole.

CASE 2 : Drilling the 8-1/2" hole.

CASE 3 : Drilling the 6" hole.AMENDMENT FOR ITEM 3.1.3


This amendment should only be followed if item 3.1.3 of the Detailed programme has been unsuccessful i.e. a plug cannot be set in the 2.313" OTIS nipple.

A1.1 Install plug in the 2.813" OTIS nipple

Rig up wireline with a 2.813" plug and pressure test to 3000 psi, RIH and set in the OTIS nipple at 10361' ahbdf. POOH and R/D.

Pressure test to 2000 psi whilst monitoring the"A" annulus outlets for flow.

Perform an inflow test.

Note : If this is successful continue with item 3.1.4 of the detailed programme.

If unsuccessful proceed with item A1.2 below.

A1.2 Install Pengo plug in tubing

Note : Radio silence is required for this operation.

Rig up Schlumberger lubricator and BOP's and pressure test to3000 psi. RIH, correlate on depth and set the plug at approximately 10440' ahbdf.Do not set within 3' of a connection.

Details of the Pengo plug are listed below:

Plug OD = 2.187" Plug setting range = 2.375" -3.000" Minimum restriction = 2.66" (2.813" OTIS nipple at 10361' ahbdf).

Pressure test to 2000 psi whilst monitoring the"A" annulus outlets for flow.

Perform an inflow test.

Continue with item 3.1.4 of the Detailed programme.



The following is a summary of useful hints for the successful placement of cement plugs based upon previous experience.

These notes must be read in conjunction with the relevant guidelines.

1) Set the plug on a firm foundation, if one is not available set the plug on an X/C polymer retaining spacer with the same weight as the mud.

2) Always use an X/C polymer weighted to midway between the mud and cement weights. Use a volume of spacer sufficient to give at least a 250 ft. separation between the mud and cement.

3) In order to maximise hole cleaning, the spacer should leave the stinger at a rate of at least 8 bpm. However, as the spacer/ cement interface approaches the end of the stinger the displacement rate should be slowed so that the cement is displaced at a rate of between 2 and 3 bpm giving an annular velocity < 90 fpm.

4) A batch tank should be used to mix cement plugs.

5) Prior to making the mixwater the drillwater freshwatershould be tested to ensure that it is free from salt and solids contamination.

6) Always under displace the cement slurry (4-5 bbls @10000').

7) Unless hole stability is a problem use a stinger fitted with some form of a diverter tool.

8) Good centralization, rotation and reciprocation of thestinger will all increase the probability of achieving a successful cement plug.

9) Once the slurry is in place, minimise the risk of contamination by pulling the stinger slowly out of the cement (30 fpm maximum).

10) Pull the stinger well back above the cement before circulating out the excess cement (2-300' above TTOC).



Cut and retrieve 9-5/8" casing

1. Ensure that there is no pressure on the "B"annulus.

2. M/U and RIH the 8-1/4" pipe cutter on drill pipe to the cutting depth, which will either have been calculated from the TTOC or from a CBL/CET log.

3. Cut the casing either in the middle of a joint or no closer than 4' above a casing collar on the first free joint above the stuck point.

4. Once the casing is severed confirm the cut by measuring the "gap". Stop the rotary and the pumps and pull up into the upper casing by 5'. Start the pumps and record the pressure at 20 SPM. Lower the pipe until a pressure drop is noticed then mark the kelly. Continue to lower the string until weight is taken. An opening of between 1' and 3' should be noticed due to the release of casing tension.

5. After the cut has been confirmed, close the Hydill and open the side outlet valve on the 9-5/8" * 13-3/8" annulus. Circulate the casing to an even mud weight prior to POOH the cutting assembly. Ensure when circulating that the hole does not pack off or that any excessive pressure is applied to the 13-3/8" shoe. Note step 3 of 3.4.1.

6A. Pull the 9-5/8" wear bushing and seal assembly, M/U the casing spear assembly including pack-off, engage the spear and pull the casing free. Again circulate the hole prior to laying down the casing.

6B. Should the cut indicate that the casing is stuck i.e. no circulation or that the casing hanger will not pull free, then make a cut 60' below the hanger. Recover the hanger.

M/U the casing spear (large diameter bore with special wireline entry guide) on drill pipe.

Engage the spear in the casing stub and run a free point indicator. From the depth indicated cut and retrieve the 9-5/8" casing ata free point reading of 10-15%.

Should the stuck point be higher than the required depth mill the remaining casing to the required depth.

Mill 13-3/8" window

The start of the window should be made approximately 10-15' above a casing collar in cemented casing. This will reduce the risk of the premature backing off of a short stub of casing.

1. M/U the assembly and test the section mill (dry torque all connections).

2. At cutting depth rotate at 80 RPM and record the torque.Bring up the pumps slowly - 80 SPM should be sufficient. When the strokes andpressure is established maintain them without surging until the cut is complete. The cut generally takes between 15 and 30 mins. A pressure drop ofapproximately 250 psi will be observed.

3. When the pipe is severed continue rotation, graduallyincreasing both RPM and SPM until the desired milling parameters are achieved.

4. After 10-20 mins. or once the torque reduces to close tothe initial free rotating value, start adding weight to the assembly.

5. Mill approximately 5-7', ensure that steel returns are observed at surface and check the window length. To do this stop rotation, pickup the string to the top of the section where an overpull should be observed.Lower the string and set down weight on the casing stub.

A further check is to stop the pumps whilst continuingcirculation to equalize the pressures. Stop rotation then pull the string upinto the casing approximately 4-5'. Engage the pumps at 80 SPM and slack offinto the section, a pressure drop of approximately 250 psi should be seen.Continue to slack off until the down weight is set on the casing stub.

Note : A constant observation and record of steel and cementrecovery must be maintained.



The mud properties given on the front page of the drilling programme are preliminary. Final properties are given in the following mud programmes;

General notes

Circulate the complete hole clean before wiper trips.

Do not start to trip until the hole is clean. All tripping in new hole should be performed whilst pumping at half the rate as when drilling.

It is imperative to have full circulation before attempting to pull out of hole. Before breaking off each stand always go down 30' with circulation to establish some free hole beneath the bit and to establish that the BHA is free and not packed off.

At the first sign of packing off (reduced flow rate and increased pump pressure), cut back the pump rate slightly and go back down. Do not continue to POOH. Continued pumping whilst pulling out may be accompanied by a reduction in apparent drag,. This should not be interpreted as the string coming free but rather that the assembly is being hydraulically pumped out ofthe hole. Continued pulling out of the hole will exacerbate the problem.

Once the assembly has been run back down beneath the cuttings, gradually increase the pump strokes to the previous rate and come upagain. It is imperative to have full circulation before attempting to pull out of the hole. If unable to go down, do not on any account jar up. Jar down ifpossible, pick up the kelly and try to work free with rotation until the string becomes free.

Whilst drilling a horizontal hole procedures must ensure effective hole cleaning in order to reduce the risk of stuck pipe. Effective hole cleaning can be achieved by combining BHA, mud system and hydraulic esigns with sound cuttings removal procedures. Tripping procedures and intervals are to be developed as the hole is progressed to take account of the lack of a top drive.

The formation of cuttings beds on the low side of an inclined or horizontal hole can be identified as a common cause of stuck pipe.To reduce the build up of cuttings beds the annulus must be kept in an agitated state. The use of the following practices will help to achieve this :

1) Use the circulating elevator to pump out of hole on all trips, if necessary pick up the kelly and rotate the string (extreme care has to be taken to prevent side-tracking the hole).

2) Closely monitor the drag and torque as a means of providing an early indication of the formation of cuttings beds.

3) Closely monitor the quantity and quality of the cuttings returning at the shakers, particularly at the bottoms up of any viscous pills.

4) Carry out check trips every 300'-500' in the 8-1/2"hole and every 200'-300' in the 6" hole or more frequently if conditions dictate that cuttings beds should be cleared.

5) Use low viscosity brine sweeps to agitate and remove possible cuttings beds.

It is NOT recommended that a high viscosity pill follows the low viscosity pill because of the detrimental effect they have on the mud properties.

Great care must be taken to fully circulate the hole clean prior to the use of such pills because the low viscosity pills can be so effective at agitating the cuttings that a packed -off annulus can result if excessive volumes are pumped.

6) During tripping it is recommended to use coarse CaCO3 forheavy pills instead of baryte.

Hydraulics calculations

The following hydraulics figures have been supplied by BakerHughes Inteq for the 12-1/4", 8-1/2" and 6" hole sections.



Baker Hughes Inteq have carried out a drag and torqueanalysis which correlates with what has been noted in the previous horizontalside-track


The following assumptions have been made for the drag andtorque calculations.


Wellpath = xxx Mud weight = 581 pptf Bit torque= 1500 ftlbs Depth = 11974'ahbdf *

* The T.D. of the well has been reduced slightly, since thedrag and torque evaluation was undertaken, to 11934' ahbdf in order to reducethe size of the 6" pocket.

Friction factors

A study was undertaken during the drilling of the 6" hole section to determine the friction factors. The back calculated friction factors were;

Cased hole = 0.15 - 0.20 Open hole = 0.20 - 0.30

The high end values are thought to have been due to a cuttings bed build up, since the back calculated values reduced significantly following a wiper trip.

Friction factors used in the calculation were,

Cased hole = 0.20 Open hole = 0.25

Bottom hole assembly

6" bit 4-3/4" Navi-drill, PDM c/w 5-7/8" UBHstabiliser 5-1/2" stabiliser MWD 2 * NMCSDP 3-1/2" HWDP Jar 3 *3-1/2" HWDP 5" DP (19.5 pptf, S135) to surface


A detailed output of the calculations can be found in thef ollowing three pages.

A summary of the results are noted below.

Surface pick-up weight = 170,333 lbs (SF = 70%) Surfacedrilling torque = 9441 ftlbs (SF = 67%) Pick up load at top of 3-1/2" DP =70982 lbs (SF = 84%) Torque at top of 3-1/2" DP = 6098 ftlbs (SF = 58%)

No buckling is predicted for either rotary or oriented drilling, with WOB's of 15000 lbs (rotary) and 10000 lbs (oriented).


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