DST Programme Example

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1. Objective:

DST the 14,000’ sand to evaluate production potential.

2. Well Information

Water Depth: 130’
RKB to WL: 90’
RKB to ML: 220’

MW Drilled With: 17.0 ppg
TD: 14,150’MD/TVD
PBTD: ±13,960’ MD/TVD

Directional Information Vertical Well

Casing Size: 26”, 202 ppf , Gr B at 470’ MD/TVD
Casing Size: 18 5/8” 87.5# J-55 BTC at 745’ MD/TVD
Casing Size: 13-3/8” 68# J-55 BTC at 3,531’ MD/TVD
Casing Size: 9-5/8” 53.5# HCQ-125 ANJO at 12,643’ MD/TVD
Casing Size: 7” 32# Q-125 ANJO at 14,050’ MD/TVD

3. Zone of Interest

Sand 14,000’ Sand

MD Perforations: 13,834’ – 13,860’
TVD Perforations 13,834’ – 13,860’

Number of JSPF: 12
Max Deviation: 2.5 at 13,862’
Estimated BHP: 11,332 psi (15.7 ppg)
Estimated BHT: ± 248° F
Estimated SITP: ± 6,280psi

Completion Fluid: 16.5ppg WBM

4. Vendor List:

5. Casing Information

Capacity Casing Strength
Size BBL/LF LF/BBL ID Drift Collapse Burst
9-5/8” 53.5 ppf 0.0707 14.13 8.535 8.500 8,850 12,390
7” 32.0 ppf 0.0360 27.72 6.094
5.969 11,720 14,160

6. Drills and Tests

1. Test BOP’s every fourteen (14) days to 250 psi low and 10,000 psi high. Test annular to 250 psi low and 3,500 psi high. Function test all rams once every seven (7) days alternating between stations and record on IADC report.
2. A Well-Control Drill will be performed at least once a week with each crew as per regulatory requirements and recorded on the IADC reports.
3. Abandon Ship and Fire Drills will be performed weekly as per Coast Guard Regulations.
4. EPA compliance with effluent limitations and monitoring requirements will be performed as per the “NPDES” permit.

7. Procedure

Run Liner and prepare for DST
1. Make up BHA for conditioning trip and TIH. Circulate and condition mud until the hole is free of cuttings and gas. Insure Yp is within range or slightly lower. POOH to run 7” production liner.

2. RU casing tools and run 7” 32 ppf Q-125 ANJO liner, running tool, hanger, and liner top packer with two joints between float shoe and float collar; and, one joint between float collar and landing collar. Run bow spring centralizers/turbolizers on bottom three joints; two per joint across all prospective zones; and one every other joint to the 9-5/8” shoe. Total 20 centralizers. Space out for hanger to be 400’ to 500’ above 9-5/8” shoe, or as required for completion objectives.
Note: Run a high-flow bypass tool from the Liner Hanger Company

3. Run liner to bottom on drill pipe washing down last stand. Circulate bottoms up, drop ball and set liner hanger. Release running tool and set back down to confirm hanger is set.

4. MU cementing head, test surface lines and cement liner as follows (cement to have zero free water):

a. Pump 35 bbl Mud Push II Spacer mixed at 17.00 ppg (mixed with fresh water)
b. Tail: 476 sx Premium cement Class “H” + 0.02 gps D047 (Antifoam Agent) + 0.30 gps D-168 (Uniflac-L) + 0.04 gps B158A (Viscous Liquid Suspension) + 0.08 gps D197 (AccuSET Retarder) + 0.02 gps D080 (Cement Liquid Dispersant) + D030 (Silica Cement) equal to 35% BWOB

Slurry Weight: 17.5 ppg
Slurry Yield: 1.24 ft3/sack
Water Ratio: 3.78 gal/sack (fresh water)

(Cement volume calculated to bring TOC to TOL at 12,300’ MD, 300’ lap, with 25% open hole excess. Volume to be adjusted for actual hole condition)
Note: Have samples of mix water and cement tested prior to job to confirm pumping times and catch two samples of slurry.

5. Bump plug with 1000 psi over cementing pressure. Do not over displace by more than half the shoe track volume.

6. PU and set back down to set liner top packer. Reverse out cement and contaminated mud at TOL.

7. Close annular and test liner top packer/casing to 1,220 psi. POOH.

8. Change upper rams to 3-1/2” x 5” flex rams. Test rams to 250 psi low and 10,000 psi high on the 5” and 3-1/2”. Test annular to 250 psi low and 3,500 psi high on the 5” and 3-1/2”.

9. RU e-line and run GR-CCL with junk basket/gauge ring to PBTD. Confirm PBTD depth to be used for TCP space out. Have a casing scraper available should the gauge ring hang up.

Run TCP assembly and perforate

10. MU 4-12” 12 spf TCP/packer assembly in accordance with diagram.

11. RIH on drill pipe with 18 x 5” drill collars. Lightly tag PBTD and pick up to perforating depth. Set packer at 13,585’. Test backside to 1,000psi.

12. RU 3” 10,000psi well test equipment and StricLan test tree.
Note: Have a minimum of 2 x 210 bbls stock tanks and sufficient NPT tanks to transport 2,000 bbls of liquid.

13. RU surface test equipment. Hold a pre-job safety meeting and test surface lines and equipment to 10,000psi. Install Wellhead monitoring systems on well testers manifold. RU e-line and SRO gauges.

14. Displace drill pipe with seawater to within 5 bbls of the bypass. Close bypass and bleed tubing pressure to 3,550 psi (which equates to 1,500psi underbalance). Pressure up on annulus to 1,000 psi.

15. Pressure up on drill pipe to 7,500psi and hold for 2 minutes to initiate TCP firing sequence (Firing delay is 10 minutes). Bleed off test string pressure to 4,250 psi to achieve 800psi underbalance when guns fire.

Flow well

16. After guns fire, open well to flow initially on a 6/64 choke. Continue flowing at 300-to-500 bpd rate until all seawater and drilling mud has been unloaded and flow rate has stabilized at unloading velocity.

17. RIH logging during the later stage of the initial clean up period with SRO pressure & temperature tools, to 13,950 ft MD. DO NOT EXCEED 100 FT PER MINUTE while RIH.

18. Perform pressure/temp flowing profile across perforated interval up and down (13,950’ MD to 13,800’ MD) at 30 ft/min.

19. POOH to Mid Perfs @ 13,847’ MD and flow well for thirty minutes at test rate (or until well has cleaned up as per the Altec Engineer).

20. Collect all the well test data as follows.
Total Fluid in bbls/day Choke size in xx/64ths
Total Gas Rate in mscf/day Oil/gas gravity
Test Separator Temperature Casing Pressure in psi
Test Separator Pressure Water cut in %
Flowing Tubing Pressure Fluid/Gas properties

21. Shut in the well for initial build-up (+2 to +12) hours. Close the wing valve and the header valve.
THERE MUST BE NO LEAKS.
Continue to monitor surface pressures (tubing). All data will be sent to Altec Office prior to proceeding to next step

22. RIH to 13,950’ MD and repeat step five making static pass across the perforated interval.

23. POOH to Mid Perfs @ 13,847’ MD and open well to flow on a fixed choke based upon initial flow period @ +500 BOPD. Duration of flow will be determined by Altec Engineer.
Estimated stabilized flow time of two days with subsequent shut-in should be adequate. All decisions will be made in real time as to rate and duration based upon data acquired.

24. RIH to 13,950’ MD and repeat step five making flowing pass across the perforated interval.

25. POOH to Mid Perfs @ 13,847’ MD and flow well for one hour at test rate.

26. Collect all the well test data as follows for the extended flow period.
Total Fluid in bbls/day Choke size in xx/64ths
Total Gas Rate in mscf/day Oil/gas gravity
Test Separator Temperature Casing Pressure in psi
Test Separator Pressure Water cut in %
Flowing Tubing Pressure Fluid/Gas properties

Note: During final flow period, obtain duplicate samples of gas, condensate and water for laboratory analysis. Monitor and record pressures and produced gas and liquids. Have 5 gallon oil sample containers for cold finger test.

27. Shut in the well for +12 to +48 hours (depending on surface readout data). Close the wing valve and the header valve.
THERE MUST BE NO LEAKS.
Continue to monitor surface pressures (tubing).
All data will be sent to Altec Office prior to proceeding to next step

28. RIH to 13,950’ MD and repeat step five making static pass across the perforated interval.

29. POOH with test string obtaining static logging pass to surface (100 fpm)

30. RD e-line and download tools.

31. Open bypass and reverse out produced fluids at least two test string volumes with 16.5 ppg mud.

32. Check for losses and spot LCM pill if losses exceed 10 bbl/hr. Release packer and pick up above perforations and monitor well. POOH with test string and lay down TCP tools.

33. A separate procedure will be provided for suspension or P&A. Have a 7” retainer on board if well is to be plugged.

34. Perform Soil Boring procedures if the well is to be suspended at the mudline.

8. Morning Reports:

Fax in daily operations reports, cost sheets, fluid reports, test reports, Monthly DMR reports, end of well transfers, and well schematics to:

9. Support Staff:

Comments  

#1 Liz 2017-11-04 02:11
This is Liz from Puyang Zhongshi Group Co.,ltd
We are a manufactures of cementing tools
Like float collar float shoe ,casing centralizer ,cementing head ,cementing basket .cross coupling With API 5CT&10D certificate
3-1/2" Cross coupling dewnhole cable protector =15 USD
9-5/8" float collar :296USD
9-5/8" bow spring centralizer :21 USD
If you have needs please communicate with me freely
Regards
Liz
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