Wellbore Cleaning Services – a Proposal for South Tongkol 1X well

by Dachnial Dan Imansyah

WELL INFORMATION

Operator	Total E&P Indonesie
Well Name	Tongkol South-1X
Engineer	–
Company Representative	–
Rig Name / Type	Topaz Driller / Jack-up
Operation	Wellbore Cleanup
Field / Block	Trekulu
Lease Name	–
ITT Number	–

PBTD	3171m MD/RT
KOP	–
Rotary Table Elevation	105 m
Water Depth	+/- 70 m
Max. Deviation	28.3°
Max. DLS	2.23 @ 2221.5m MD
Completion Method	Cased hole, perforated
Mud Weight / Type	1.77-1.87 S.G. OBM
Brine Weight / Type / TCT	1.35 S.G. CaCL2
Packer Fluid Weight / Type / TCT	–
Packer Type	–
Packer Depth	–
Reservoir Temperature / BHT	120°C @ 3171 m MD/RT
Reservoir Pressure / BHP	–
Reservoir Permeability	–
Reservoir Porosity	–
CO2 Content	–
H2S Content	–

Type	Size (in)	Weight (ppf)	Metallurgy	From	To (MD)	To (TVD)
Conductor Pipe	30.00	456.47	X56	0 m	220 m	185 m
Casing	20.00	133	P110	0 m	835 m	800 m
Casing	13.625	88.2	P110	0 m	1858 m	1949 m
Casing	9.625	53.5	Q125	0 m	2221 m	2100 m
Liner	7.00	32	P110	2071 m	2796 m	2675 m
Liner	4.50	13.5	L80 Cr	2646 m	3171 m	3050 m

# of Pumps	3
Total Pump Output	3 x 2,200 HP = 6,600 HHP
Maximum Working Pressure	7,500 psi
Pump Liner	–
Boost Line	–
Choke Line	–
Kill Line	–

WELLBORE CLEANING OBJECTIVES

Once the well is drilled to TD and the 4-1/2” liner run and cemented, the well should be displaced to 1.35 SG CaCl₂ before commencing with well test ops. There are a number of possible alternatives including running an additional contingency 16” liner in case of top hole section issues, but this proposal discusses only the WBC operation for the most likely case with both 7” and 4-1/2” liner being run. Regardless of the completion method, all displacements are designed to achieve the following:

• Remove the drilling mud from the wellbore, and ensure that the casing, riser, and/or open hole are free of drilling mud residue.
• Minimize fluid interface and associated waste during the transition from drilling mud to sweater / completion fluid (i.e. minimize disposal costs).
• Reduce non-productive time (i.e. rig time).
• Reduce filtration time.
• Maximize future well productivity.
• Perform the operation with high QHSE standards.

To achieve these objectives, all displacements must consider the two essential elements of wellbore cleaning: mechanical cleaning and chemical cleaning. Regardless of the mud system or completion method, both elements are critically important and therefore must be considered.

MECHANICAL WELLBORE CLEANING

It is important to understand the client’s objectives when designing a mechanical wellbore cleaning string. Mechanical wellbore cleaning tools are designed to work in a single trip. This means that multiple operations can be performed using a single clean-up string. This flexibility provides the client with significant cost savings and dramatically reduces the number of trips (i.e. cuts down on rig time). Simultaneous operations will be:

• Conduct a liner lap / inflow test to confirm well integrity prior to displacing to lighter seawater.
• Boost the annulus to ensure that solids and debris flow back to the surface.
• Scrape the casing (including all packer set points) to remove scale and mud solids.

CHEMICAL WELLBORE CLEANING

Chemical spacers are designed to work in conjunction with MWCT to remove debris and leave downhole tubulars water-wet. Improper chemical design can lead to the following:

• Chemical incompatibilities that create emulsions or precipitation.
• Contamination of completion fluid, leading to long filtration time and high disposal costs.
• Improper removal of drilling mud, resulting in oil-wet downhole tubulars.
• Solids and debris settling out in the chemical spacers due to improper rheology.
• Inducing formation damage by changing rock wettability.
• Reduction of rock permeability by particle plugging and/or emulsification with production fluids.
• Crystallization of completion fluid or formation of gas hydrate.

Each mud system is different, so it is important to customize the chemical spacer train to the specific drilling mud to eliminate the potential issues above.

FILTRATION AND SURFACE CLEANING

Equally critical but sometimes overlooked aspects of a successful completion operation are cleanliness of surface facilities and filtration of completion fluid. If mud solids or residue are left in the pits and lines, they will mix with completion brine thus contaminating it. Additionally, solids-laden brines (even at very low concentration) have the potential to partially or completely plug the producing zone.

However in this scenario, the Filtration equipment will be used to filter seawater for displacing the well only. This will:

• Ensure tool operability
• Prevent solids accumulation in the well annulus
• Safeguard any future completion assembly from particle settlement
• Reduce waste volumes
• Meet discharge compliance legislation

DISPLACEMENT OVERVIEW

It is recommended that all mechanical wellbore cleaning tools and Weatherford personnel are on location before the operation commences.

Drilling fluid should be circulated across the shakers to the lowest possible rheology prior to pumping the displacement.

BHA#1 : BOP Jetting and Cleaning Run

Tool Type	Length (m)
5″ Drill Pipe 19.5# S-135 – 1 Joint  (GPDS50)	5.21
5″ Pup Joint (4-1/2″ IF B x P)	1.60
10″ CLEARMAX BOP  Wash Tool (4-1/2″ IF B x P)	1.79
5″ Drill Pipe 19.5# S-135 – 2 Joint  (GPDS50)	19.25
9″  Max-Force Magnet (4.1/2″ IF BxP )	2.50
X/Over  (4-1/2 IF B x 3-1/2 IF P)	0.78
9.5/8″ CLEARMAX SENTINEL (3.1/2 IF B x 4.1/2 IF P)	2.94
6.1/2″ Bull Nose Sub	0.21

BHA#2: MECHANICAL WELLBORE CLEANING TOOLS

Tool Type	Length (m)
5″ Drill Pipe to surface (19.5 ppf, S-135, GPDS50 BxP)	2047.08
X/O Sub (GPDS50 B x 4.1/2″ IF P)	0.81
Pup Joint (23.4 ppf, S-135, 4.1/2 IF BxP)	1.60
9.5/8″ Max-Brush (4.1/2″ IF BxP )	2.02
6½”  Max-Force Magnet (4.1/2″ IF BxP )	2.50
6½”  Max-Force Magnet (4.1/2″ IF BxP )	2.50
9.5/8″ CLEARMAX SRCT (4.1/2″ IF BxP )	3.25
Pup Joint (23.4 ppf, S-135, 4.1/2″ IF BxP)	3.00
9.5/8″ ISO-MAX (4.1/2″ IF BxP )	5.25
9.5/8″ MAX-Blade (4.1/2″ IF BxP )	2.02
8 1/4″ CLEARMAX Landing Sub (4.1/2″ IF B x 3.1/2″ IF P )	0.97
3.1/2″ Drill Pipe (13.3 ppf, S-135, 3.1/2″ IF)	557.85
Pup Joint (13.3 ppf, S-135, 3.1/2″ IF)	1.60
7″ Max-Brush (3.1/2″ IF BxP )	1.77
5″ Max-Force Magnet (3.1/2″ IF BxP )	2.01
7″ MAX-Blade ( 3.1/2″ IF BxP )	1.77
X-Over (4.1/2″ IF B x 2-7/8″ HTPAC P)	0.80
2.7/8″ HTPAC DP	528.00
4.1/2″ MAX-Blade (2.7/8″ HTPAC BxB)	1.98
3.1/2″ Rock Bit	0.20

CHEMICAL DISPLACEMENT SPACERS

Spacer	Fluid Type	Volume	Flow Rate	Density	PV (cP)	YP (#/100 ft2)
	OBM	780 bbls	225 gpm	1.770  s.g.	32.7	16.7
1	Base Oil	50 bbls	225 gpm	0.840 s.g.	1	0.1
2	Transition Spacer	55 bbls	225 gpm	1.810 s.g.	22	28
3	Cleaning Spacer	45 bbls	225 gpm	1.010 s.g.	1	0.1
4	Hi-Vis Spacer	55 bbls	225 gpm	1.030 s.g.	1	0.2
5	Seawater	870 bbls	750 gpm	1.350 s.g.	4	0.2

DISPLACEMENT OVERVIEW

RIH WITH BOP CLEANING TOOLS

1. Conduct tool box talk and ensure that all personnel are aware of the operations which will take place and any potential hazards associated with them.

2. Make up the MAX-Force and Sentinel assembly (as Section 3.1) to 2 joint drillpipe according to the recommended MUT.

3. Make up the BOP Jetting tool to the string and lower it below the rotary to function test it.

4. RIH the string until the BOP Jetting Tool is below the wellhead. Pump filtered brine at 1200gpm at 20 rpm across the BOP cavities with 3-5 passes. However, it is recommended to pump at 500gpm across Hydril Bag/ annular preventer to avoid damage.

5. POOH the assembly to surface and collect the debris that is collected on the MAX-Force and Sentinel’s wiper cup. Weigh the total debris collected.

RIH WITH MECHANICAL WELLBORE CLEANING TOOLS

1. Conduct tool box talk and ensure that all personnel are aware of the operations which will take place and any potential hazards associated with them. Adequate lines of communication should be established between the rig floor and the pit room. 
2. Make up the mechanical wellbore cleaning string as described in Section 3.2 (also see page 7). It is recommended to break circulation every 500 m.
3. Mechanical cleaning will take place as the tools are RIH. Reciprocate five times over the packer setting area and other areas of interest. Record up and down weights.
4. Ensure correct space-out and circulate 1.5 hole volumes at 225 gpm to condition mud and record SPP while pumping.
5. Check that the company man and wellbore cleaning engineer have both confirmed that the drilling mud properties are acceptable.
6. Reciprocate three additional passes with rotation and circulation to clean the ISO-MAX Security Packer setting depth.

LINER TOP NEGATIVE PRESSURE TESTING

1. Confirm that the mud density going in and out of the well is equal so that the mud system is in balance both within the string and in the annulus.
2. Shut down pumps and cease rotation and reciprocation.
3. Confirm the up and down string weights without circulation or rotation.
4. Re-tag the liner top PBR before dropping the ISO-MAX operating ball (OD = 1.875”) and pumping to depth at no more than 2 bpm.
5. Once the operating ball is at depth (drop rate will be approximately 150 m/min without pumping), pressure up to +/- 2,750 psi incrementally in 500 psi stages, allowing 1-2 min per stage.
6. Once at 2,750 psi, hold for 5-10 min to fully set slips and inflate the packer element as well as opening a channel to the ISO-MAX bypass valves.
7. Perform a push/pull test (+/- 10,000 – 15,000lb) whilst holding pressure on the string to confirm both sets of slips have fully set.
8. Increase the pressure to +/- 3,250psi to shear out internal piston and allow flow through the tool once more.
9. Close the annular BOP and apply 1,000 psi to the annulus and check that the packer element is holding pressure for 5 min. This is vital to confirm that there will be no U-tubing of drilling mud back into the work string. It also tests that the check valves are sealing properly.
10. Pump 50 bbl of base oil at no more than 2-3 bpm (to allow for thermal effects) into the string to achieve the required draw down for the inflow test. Record the final SPP.
11. Bleed off 1,000 psi slowly over 5 min before stopping to confirm that the bypass valves are operating correctly. Line up the trip tank to monitor the annulus level during the test.
12. Since the SRCT is being run, it is important that the string is picked up as soon as packer element integrity has been confirmed. This will prevent pre-shearing the SRCT due to thermal elongation of the string.
13. Continue to reduce drill pipe pressure in 500 psi stages at a rate of approximately 100 – 200 psi per minute, waiting approximately 1 minute between stages until the string pressure is zero. Confirm the packer element is still holding, as well as the volume returned. Monitor the annulus level to check the packer element seal is still good.
14. Carry out the inflow test as per the client requirement.
15. Re-pressure the drill string to equalize the U-tube pressure in the annulus and drill pipe before picking up with 48,000 lb overpull to unseat and release the ISO-MAX whilst holding pressure on the string.
16. Continue to the mud displacement procedure if all parties agree that the negative pressure test was successful. If not, remedial action must be taken to ensure pressure integrity of the wellbore.

PUMPING SCHEDULE

1. Before starting the pumping schedule, pre-shear the SRCT to verify the tool works properly.
2. Pick up the drill string to close the SRCT.
3. With the workstring at the bottom of the 7” liner, pump (down the workstring and up the annulus) in the following order:
   • 50 bbls of 0.839 S.G. Base Oil (225 gpm)
   • 55 bbls of 1.810 S.G. Transition Spacer (225 gpm)
   • 45 bbls of 1.010 S.G. Cleaning Spacer (225 gpm)
   • 55 bbls of 1.030 S.G. Hi-Vis Spacer (225 gpm)
   • 215 bbls of 1.350 S.G. Brine (225 gpm)
4. A rotation of 60-90 RPM and reciprocation of +/- 10 m needs to be maintained throughout this displacement.
5. At this point all of the brine interface will be in the annulus approximately 100 m above the 7” liner top.
6. The SRCT should now be activated in order to increase annular velocity inside of the 9-5/8” casing annulus.
7. To do so, cease pumping and rotation and set down 15,000 lbs plus the weight of the drill string below the SRCT.
8. Activation of the tool will be confirmed by a 20” downward stroke of the drill string and lower SPP when pumping resumes at the same rate.
9. Once tool activation has been confirmed, maintain rotation of 60 rpm with NO reciprocation while monitoring surface torque. Pump:
   • 655 bbls of 1.349 S.G. Brine (750 gpm)
10. Condition the brine by circulating at the maximum possible rate until returns at the surface are < 0.05% TSS and 100 NTU for three consecutive measurements.
11. Shut down pumps and cease rotation of the string. POOH with the mechanical wellbore cleaning string. Inspection of the string should be performed at this time for further indication of the cleanliness of the casing.
12. Refer to Figure 1, Figure 2, Figure 3, Table 1, Table 2 & Table 3 for a description of flow regimes and pump output during the displacement.

13. Pumping schedule is subject to change based on data supplied by the client.

POOH AND INSPECT MAGNET DEBRIS TOOL

1. Cease pumping and POOH at 30 m/min.
2. Inspect the workstring as it is POOH for further indication of the cleanliness of the casing/riser.
3. Continue POOH until the MAX-Force string magnets reach surface. Take note of the amount of metal swarf on the MAX-Force string magnets. Optionally, the material can be weighed.
4. L/D all wellbore cleaning tools.
5. Once out of the hole, remove the metal cuttings from the magnet and record their weight.
6. Have company man fill out Field Service Quality report and identify any problem areas during the job.
7. Proceed to next step in the completion program.

MECHANICAL WELLBORE CLEANUP SCHEMATIC

BHA 1 – BOP JETTING

BHA 2 – Main Cleanout and Inflow Test BHA Schematic

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