Objective
Drill 12 1/4" hole to approx. 140000ft TVDBDF (80ft below Marker). 30 ft above shallowest "overpressurised" zone, allowing ± 50 ft uncertainty on the seismic.
Run and set 103/4" x 9 7/8" casing 25ft off bottom.
General
1. Well path specific
2. TD determination: LWD (GR/Res), ROP, Cuttings, Gas readings, Calcimetry, Biostratigraphy, with most emphasis placed on LWD and Biostrat data.
3. MWD with GR/Restivity will be used from 5000 ft. The assembly will be pulled if the Resitivity fails. ROP should be optimised to obtain the best conditions for running the MWD tools.
4. If there is any small ambiguity between the biostrat data and the LWD data, the LWD data will take precedent.
5. If there is any ambiguity in the interpretation of the LWD and biostrat data, possible additional data may have to be acquired (wireline logs? VSP?). This will be decided when the need arises.
6. All BHA's to be run should be checked for critical rotary speed/drill string vibration analysis.
7. The mud used for this section will be the same mud as used previously. During the latter stages of drilling this section the mud will be treated with HT additives to upgrade the specifications.
8. The shoe track will be drilled out and the FIT performed with 700 pptf . The mud weight will have to be increased to 815 pptf prior to drilling ahead.
9. Maximum flow rates to promote good hole cleaning and enhance ROP should be maintained at all times while drilling the section..
10. Flowline temperatures of around 173 deg.F may be seen at the TD of this section.
11. Accurately calliper OD and ID for every tenth joint laid out for both 10 3/4" and 9 7/8" casings. This will be used for calculating displacement volumes for the cement job and should be recorded in the casing tally. An "OD Tape" and an "ID Micrometer" will be used to obtain these casing dimensions.
12. The depth of the x-over from 9 7/8" Q-125 to 10 3/4" AC-110SS at 8500ft AHBDF, is based on the geothermal temperature gradient (plus a 15% margin) so that the Q-125 casing is used where temperatures are above 175 deg F. (for H2S resistance purposes).
Drill 12 1/4" Hole
1. RIH with 12 1/4" directional BHA
2. Drill out cement and float equipment. Clean out rathole and drill 15ft of new formation.
3. Circulate the hole and balance mud.
4. Pull up inside 13 3/8" shoe and perform a limit test to 850 pptf EMW.
5. Increase the mud weight to 815pptf
5. Directionally drill the 12 1/4" hole to 100ft above top Hod.
6. POOH and run a rotary assembly with MWD/GR/RES
7. Casing shoe point which will be based on Res/Biostrat and other information available at the time. Maximum section TD is to be 80ft below below Marker NO.x
8. At section TD circulate the hole clean, if hole conditions indicate, make a wiper trip prior to POOH.
9. Run electric logs.
10. If necessary perform a wiper trip prior to running casing.
Run and Cement 10 3/4" x 9 7/8" Casing
As mud densities and formation parameters could change, a full computer simulation will be performed prior to the job using actual well and fluid parameters.
1. Pull wear bushing. Obtain accurate measurement of RT - hang off point for 10 3/4" casing hanger.
2. RIH with jetting sub and jet wellhead area.
3. Make up cement head and lay down. Make up casing hanger joint to running tool joint and lay down.
4. Rig up to run 9 7/8" casing
5. A 5 joint shoe track will be run. Baker lock connections on the rig. Use a special 10 ft pup on bottom to facilitate EST.
6. Ensure float equipment is functioning correctly.
7. Install centralisers as per Dowell recommendation.
8. Use "klepo" type thread protectors at all times.
9. Run 9 7/8" casing as per previously prepared running list. Install 9 7/8" x 10 3/4" bakerlocked xover joint and run 10 3/4" casing string. Check the number of joints remaining on deck before picking up the hanger. Pick up 10 3/4" hanger joint.
10. Run casing at speed calculated by Casing Surge Programme
11. Fill casing with mud every 5 joints. Monitor casing displacement carefully throughout.
12. Run casing with a 10 3/4" casing landing string, and land casing. The 10 3/4" casing will be run from 8500 ft to surface
13. The 9 7/8" shoe should be set +/- 25 ft of bottom.
14. Make up the cement head, ensuring plugs are loaded correctly.
15. Rig up surface lines and test same.
16. Break circulation with rig pumps. Stage up flowrates gradually in 1 bpm increments. Check for losses at each stage and establish maximum pumping rate. If losses are seen consider proceeding with cement job immediately , otherwise circulate 110% casing contents.
17. Pump spacers as per Dowell proposal.
18. Drop bottom plug.
19. Mix and pump cement as per cementing programme.
20. Drop top plug and displace cement with the rig pumps at maximum rate without losses. Ensure line to cement unit open to enable recording of displacement pressure.
Test the casing on bump to 3000 psi. Use the average micrometer casing dimensions previously obtained to calculate displacement volumes. If the plug does not bump limit overdisplacement to a MAXIMUM of half the shoe track volume.
21. Bleed off pressure and check for backflow. if holding, back out running tool. Flush wellhead area.
22. Run and set the 10 3/4" lock down seal assembly. Pressure test seal assembly to 500/13100 psi.
23. Displace the well to seawater above 6000ft and pressure test the casing to 13100 psi.
25. Perform complete BOP test to 500/13100 psi (500/10000 psi for annulars).
26. Run the wear bushing.
Bits
- FM 2943
- BBL 657
- F2 DL
- ATM 22GD
- BBL 678
- SMITH M37P
MOTOR CORRECTION ASSEMBLY
- 12 1/4" Bit
- 1 x 9 1/2" A.K.O., Navi Drill Mach IP/HF. 12 1/8" Screw on Stabiliser
- 1 x 12" Short Stabiliser 7 5/8" Reg Conn.
- 1 x 9 1/2" MWD Collar
- Circ Sub
- 1 x 12 1/8" Short Stabiliser
- 3 x 9 1/2" Drill Collar
- 1 x 9 1/2" OD Jar
- 1 x 9 1/2" Drill Collar
- 1 x XO
- 1 x 8" Drill Collar
- XO
- 6 5/8" SWDP
- 6 5/8" DP
- 5"
ROTARY ASSEMBLY
- 12 1/4" Bit
- 1 x 12 1/4" Near Bit Stabiliser
- 1 x 9 1/2" MWD Collar (DPR)
- Circ Sub
- 1 x 12 1/4" Stabiliser
- 1 x 9 1/2" Drill Collar
- 1 x 12 1/4" Stabiliser
- 3 x 9 1/2" Drill Collar
- 1 x 9 1/2" Jar
- 1 x 9 1/2" Drill Collar
- 1 x XO
- 1 x 8" Drill Collar
- 1 XO
- 6 5/8" SWDP
- 6 5/8" DP
Mud Type : Ultridrill POBM
- Mud Weight : 815 pptf
- Plastic Viscosity : < 70
- Yield Point : 28-22 lb/100sq ft
- Gels : 12/30
- HPHT Fluid Loss : < 4 MLS/30 min
- (at 250 Deg F)
- LGS : < 6%
- Water Phase Salinity : 200 - 220k mg/l chlorides
- Pseudo/Water Ratio : 65/35 - 80/20
- Excess Lime : 3 ppb
- Electrical Stability : >500 volts
CONTINGENCY PLANNING
The starting point for this section is a 13 3/8" casing set in the non-porous section and a limit test of 0.850 psi/ft. Three situations can be envisaged while drilling the 12 1/4" hole :
1. Planned 9 7/8" casing setting depth is reached without serious gas or other problems
2. Minor gas problems are encountered prior to reaching the planned 9 7/8" casing setting depth (similar situation is in the original 12 1/4" hole)
3. Major gas problems or a well control problem is encountered prior to reaching the planned 9 7/8" casing setting depth.
Each of these possibilities will now be looked into in greater detail, and the options will be considered:
1. If the planned 9 7/8" casing setting depth can be reached without major gas problems / kicks etc. then there are a total of 3 options for setting the 9 7/8" casing :
a) Run 9 7/8" liner without immediate tieback
b) Run 9 7/8" liner and tie this back immediately with a combined 9 7/8" x 10 3/4" string
c) Run a full combination string of 9 7/8" x 10 3/4" casing.
1.a.1 The shoe strength at the planned 9 7/8" casing setting depth is potentially in the range of 0.940 - 0.960 pi/ft. Taking an assumed value of 0.950 psi/ft. (at a setting depth of 13,500 ft. TV) then the maximum surface pressure that can be present when the casing is evacuated to 0.20 psi/ft. gas is : 13,500 x 0.95 - 13,500 x 0.20 = 10,125 psi. This calculation assumes that the maximum surface pressure is restricted to the formation strength at the 9 7/8" casing shoe.
This maximum surface pressure results in a differential burst pressure of : 10,125 + 377 x 0.20 - 0 = 10,200 psi. (assuming no backup pressure at the welled level).
The burst rating for the 14" casing is 9,770 / 1.1 = 8,881 psi. Obviously this burst capacity is not sufficient for the potential burst load during a full evacuation situation. Hence the option of a liner which is not tied back to surface whilst drilling the 8 3/8" hole section, is not feasible.
1.b.1 The available liner hanger for the 9 7/8" casing is actually a 9 5/8" P110 design. This liner hanger comes with a 15 ft. PBR in which the tie-back string will stab into with a 15 ft. seal stack. To ensure the pressure integrity, it is essential that the tieback string is cemented in place over the lower section. This will inhibit the movement of the seal stack, which increases the chance of pressure integrity. The drawback of this is that the annulus between the 14" x 13 3/8" casing & 10 3/4" x 9 7/8" tie-back is sealed both at the bottom (by means of cement) and at the top (by means of the seal assembly). The fluid in this so called trapped annulus has no room to expand during temperature increases. Hence during production testing, the heating up of the annulus fluid will result in increased annular pressure, which could potentially cause burst of the 14" casing at the top section of the well. (Burst of 14" casing is 9,770/1.1 - Collapse of 10 3/4" casing is 17,890/1 i.e. the 14" is sacrificial)
1.b.2 The trapped annulus problem could be designed for by using either crushable foam sections attached to the top part of the tie-back string (below the hanger) or by using a novel tie-back cementing technique, whereby use is made of differential pressure (displacement with seawater ??) to u-tube sufficient volume from the annulus, back into the tie-back string.
This volume must create a void space below the hanger, sufficient to allow for annulus fluid expansion due to temperature increase while production testing. It should be noted that this is not a practice that is widely supported and will most likely not be carried out.
1.b.3 An other alternative to 'design' round the trapped annulus scenario, is to perforate the 14" casing at the top of the casing string, prior to setting and cementing the 10 3/4" x 9 7/8" tie-back string.
1.c.1 This would be the most preferable option since the full casing integrity is guaranteed and top of cement can be manipulated to remain below the 13 3/8" casing shoe, hence no trapped annulus situation.
2. If minor gas problems are encountered prior to reaching the pre-determined 9 7/8" casing setting depth and these problems can be regarded similar to the ones in the original hole (i.e. do not result in a well control problem) then it can be assumed that drilling will continue despite the gas levels. However, the gas levels are expected to severely jeopardise the success of a casing cementation. The following options are open :
a) Drill on to 9 7/8" casing point and set liner + tie-back
b) Drill on to planned 9 7/8" casing point and run full string of casing
c) Stop, plug back and set casing above trouble zone.
2.a.1 If the liner were to be run, then an immediate tie back is required as justified in 1.a.1. In the original hole, it proved feasible to continue drilling despite the high gas readings. This scenario would mean that it is most likely possible to reach the pre-determined casing setting depth. However, a successful 9 7/8" cementation is doubtful because of the gas levels. The advantage of a liner option is the fact that after running several 1,000 ft. of liner, the drillstring is used to place the liner at the desired depth. Well control issues are then a lot simpler and an added advantage is that the pipe rams can be used if required (even shear rams !) Secondly, there is the option for a cement squeeze job at the top of the liner to positively seal off the top of the liner.
2.b.1 When serious problems with gas levels (gas ingress) are encountered, then it is not recommended to run a full string of casing, since the cement job will most likely be of a very poor quality, which can potentially lead to a live annulus !
2.c.1 This option should only be considered if and when the 12 1/4" hole depth is near the planned section TD. Anything shallower than top Hod should not be considered i.e. casing should not be run.
3. If major gas problems (or a well control incident) is encountered prior to reaching the pre-determined optimum 9 7/8" casing setting depth, then it is reasonable to assume that drilling can not continue beyond this depth. The following options are open :
a) Cure problem (barite pills / cement etc.) and abandon the well.