StageFRAC With ClearFRAC XT - LV03 Operating Procedure 4544619 01[1]

LV03 StageFRAC*LV03 StageFRAC*LV03 StageFRAC*LV03 StageFRAC*

Operating Procedure and Treatment DesignOperating Procedure and Treatment DesignOperating Procedure and Treatment DesignOperating Procedure and Treatment Design

Schlumberger Schlumberger Schlumberger Schlumberger ---- Well Production Services Well Production Services Well Production Services Well Production Services

v1.4v1.4v1.4v1.4

Prepared for:Prepared for:Prepared for:Prepared for: Alexandru Dragomir

Warwick Hughes

Location:Location:Location:Location: Romania Black Sea Offshore

Prepared by:Prepared by:Prepared by:Prepared by: Tomislav Bukovac - WPS DTE, Ploiesti, RO

[email protected]

+40 727 277 199

Date:Date:Date:Date: July 7th , 2008

LV03 StageFRAC* - Operating Procedure

Introduction........................................................................................................................................ 2 1. Scope of Work............................................................................................................................. 3 2. Operational Strategy Overview...................................................................................................... 4 3. Well Trajectory ............................................................................................................................ 5 4. StageFRAC* Completion Design .................................................................................................... 6 5. Completion - Proposed 3 Stage StageFRAC* System Installation and Operational Procedures............. 7

5.1. Procedure: Well preparation.................................................................................................. 7 5.2. Procedure: StageFRAC* Liner component space out considerations.......................................... 8 5.3. Procedure: Opening the Hydraulic FracPort & Preparing for Frac Job ...................................... 12

6. Equipment Lay-out and Rig-up..................................................................................................... 13 6.1. Wellhead Rig Up................................................................................................................. 13 6.2. Supply Vessel – “Active King”Rig-up .................................................................................... 14 6.3. Platform – “Jupiter” Rig-up.................................................................................................. 15

7. Fracture Design and Proppant Placement .................................................................................... 16 8. Pre Job Preparation ................................................................................................................... 20

8.1. Pre-job HP Rig-up ............................................................................................................... 20 8.2. Fluid Preparation on Vessel ................................................................................................. 20 8.3. Vessel Hookup to the Rig ..................................................................................................... 20 8.4. Pressure Test ..................................................................................................................... 20

9. Pumping Procedure ................................................................................................................... 22 9.1. DataFRAC .......................................................................................................................... 22 9.2. Main Fracturing Treatments................................................................................................. 25

10. Flowback............................................................................................................................... 30 11. On Site QA/QC Lab Testing Procedure for ClearFRAC XT Fluid..................................................... 31

11.1. Introduction - ClearFRAC XT Reference Rheology .................................................................. 31 11.2. On Site Fracturing Fluid QA/QC............................................................................................. 33

12. Screen Out Contingencies....................................................................................................... 36 12.1. Frac Screens Out (A)........................................................................................................... 37 12.2. Wellbore Free of Proppant (B).............................................................................................. 37 12.3. Frac Next Stage (C)............................................................................................................. 38 12.4. Proppant in Wellbore (D) ..................................................................................................... 38 12.5. Push Top Ball to Seat (E) ..................................................................................................... 39 12.6. FracPort Shifts Open (F)....................................................................................................... 39 12.7. FracPort Open, Frac Well (G) ............................................................................................... 40 12.8. Drop Another Top Ball (H).................................................................................................... 40 12.9. Coiled Tubing Wash (I) ........................................................................................................ 40

13. CT Cleanout Program.............................................................................................................. 42 13.1. Tubing Forces Results ......................................................................................................... 46 13.2. Procedure.......................................................................................................................... 50 13.3. Equipment.......................................................................................................................... 56 13.4. Prevention and Mitigation Measures on Location .................................................................. 57

14. Decision Tree ........................................................................................................................ 58 15. Appendix 1 - Lab Testing Report .............................................................................................. 59 16. Appendix 2 - Frac Design Stage 1............................................................................................. 59 17. Appendix 3 - Frac Design Stage 2............................................................................................. 59 18. Appendix 4 - Frac Design Stage 3............................................................................................. 59


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IntroductionIntroductionIntroductionIntroduction

StageFRAC* is a trademarked name of Schlumberger for providing multi-staged propped fracturing stimulation

using down hole completion hardware provided by Packers Plus Energy Services. Schlumberger is a minority

owner of this company and has exclusive rights to market and supply services of this hardware outside of the

United States and Canada.

As of this writing, Packers Plus is supplying and running 90-100 systems per month. This popularity of the system

is being driven by the un-paralleled production results that this system is able to deliver. The demand for this

system is increasing each month.

Schlumberger is now running systems in Africa, South America, Asia, Middle East and there is very strong

interest and planned placement in other oil production areas where it has not been applied to date.

This quantity of jobs has generated a significant amount of experience in running the systems into extreme

conditions and executing stimulation treatments. The document that is provided here is a collaboration of

information from Packers Plus Energy Services and Schlumberger.

Current StageFRAC* Condition Extremes to Date:

• Well conditions 340o F

• Surface tested in oven at 320o F and 10,000 psi for 24 hours to qualify packer elements.

• Well depths to 15,000 feet.

• Longest Open Hole Lateral to date 7,200 feet

• Maximum proppant through the system is 3.5 million pounds

• Maximum pump rate of 140 bpm

• Maximum pumping time of continuous injection of 26 hours


3

1.1.1.1. Scope of WorkScope of WorkScope of WorkScope of Work

The horizontal well LV03 will be drilled in order to establish production from not drained part of Lebada Vest

reservoir. This part of the reservoir has permeability which ranges from 0.1 mD to 2 mD.

The well will be drilled and open-hole interval will be completed with the 3 stage StageFRAC* completion.

Upon the completion while still jack up platform “Jupiter” will be on LV03 position 3 consecutive fracturing

treatments will be pumped from “Active King” supply vessel by land based frac equipment placed on the deck.


4

2.2.2.2. Operational Strategy Overview Operational Strategy Overview Operational Strategy Overview Operational Strategy Overview

• Jack Up platform “Jupiter” will stay on well position after finalizing StageFRAC* completion for frac

operation support

• SLB frac equipment will be placed on “Active King” supply vessel equipped with dynamic positioning

system

• Treatment will be pumped from equipment based on “Active King”, Coflex up to jack up deck then

through 3” piping to the drilling floor and then down to the wellhead

• Fracturing fluid ClearFRAC XT will be prepared with sea water and pumped on the fly

• Proppant will be stored in 2 x 50 tone gravity silo placed on the deck and additionally in 2 sub deck

cement p-silos

• For Stage #1 and Stage #2 and 80% of Stage#3 necessary proppant will be transferred before the job in

gravity silo on the deck by built in boat compressors.

• All RC proppant (compatible with CF XT if will be possible to source, if not, J501 PropNET additive will be

pumped during last stages) will be placed before the operation in one of gravity silos

• Sea water will be sucked from the sea to sub deck tanks (6x80m3) with the max rate of 4 m3/min by boat

pumps.

• Sea water than will be transferred by 4 boat c-pumps to the 28 m3 header tank with the max transfer

rate of 3.6 m3/min

• Header tank will ensure necessary hydrostatic pressure for phase 3 POD blender which will blend the

fluid

• Additives will be pumped with 3 LAS units (6 LAS pumps in total). Max theoretical additive rate will be

195 l/min for J590

• J590 will be stored in 50 m3 batch tank placed on boat deck

• The rest of the chemical additive (J589, L064, W054) will be placed on the boat deck in 1 m3 tote tanks

and during the job will be transferred by Wilden pumps to 1 m3 volume LAS tanks

• J567 breaker will be run as dry additive on the pod during proppant stages and M275 biocide will be

added in boat tanks during the treatment.

• Proppant concentration will be measured with 2 NRD densitometers

• Fluid will be pumped by 2 x SPF 343 pumps through 3” treating line on the boat deck, QD and coflex, 3”

treating iron placed on “Jupiter” platform to the 10K wellhead

• Max treating pressure will be 8500 psi and max rate 3m3/min.

• Design strategy: Perform DataFRAC before first stage and perform first 2 stages with conservative

approach, last stage design will be more aggressive with the respect to proximity of gas cap

• Pressure in annulus will be maintained by rig electric HP pump

• Two StageFRAC* balls will be launched from “Jupiter” platform deck through permanently based SLB

pump CPS 361

• Plan is to perform all 3 fracs in single treatment; however upon ongoing proppant rate transfer rates test

we might wait between each stage for few hours to transfer proppant on the deck and transfer

additives.


5

3.3.3.3. Well Trajectory Well Trajectory Well Trajectory Well Trajectory === ======== ====== ======= ====== ======== ======== ==================================== ===== ======Seq Measured Incl Azimuth Course TVD Vertical Displ Displ Total At DLS Srvy Tool# depth angle angle length depth section +N/S- +E/W- displ Azim (deg/ tool Corr- (m) (deg) (deg) (m) (m) (m) (m) (m) (m) (deg) 10m) type (deg)=== ======== ====== ======= ====== ======== ======== ==================================== ===== ======

1 1136.9 22.65 46.05 0 1100.46 203.8 153.02 135.16 204.16 41.45 0 TIP None2 1185.29 22.63 44.78 48.39 1145.12 222.27 166.09 148.43 222.75 41.78 0.1 PUP None3 1204.89 23.14 44.43 19.6 1163.18 229.85 171.52 153.78 230.36 41.88 0.27 PUP None4 1233.78 23.19 44.74 28.89 1189.74 241.14 179.62 161.76 241.72 42.01 0.05 PUP None5 1262.95 23.26 44.74 29.17 1216.55 252.56 187.79 169.85 253.21 42.13 0.02 PUP None

6 1292.23 23.24 42.34 29.28 1243.45 264.06 196.16 177.81 264.76 42.19 0.32 PUP None7 1320.67 23.11 39.82 28.44 1269.59 275.24 204.6 185.17 275.95 42.15 0.35 PUP None8 1349.52 23.2 39.85 28.85 1296.12 286.58 213.31 192.43 287.28 42.05 0.03 PUP None9 1377.82 23.22 39.31 28.3 1322.13 297.73 221.9 199.54 298.43 41.96 0.08 PUP None

10 1407.12 23.13 39.33 29.3 1349.07 309.25 230.83 206.85 309.94 41.86 0.03 PUP None

11 1435.72 23.12 39.3 28.6 1375.37 320.48 239.52 213.96 321.17 41.77 0.01 PUP None12 1464.59 23.2 39.44 28.87 1401.91 331.84 248.29 221.17 332.51 41.69 0.03 PUP None13 1493.55 23.16 41.27 28.96 1428.53 343.22 256.98 228.55 343.91 41.65 0.25 PUP None14 1522.39 23.19 42.77 28.84 1455.05 354.55 265.41 236.14 355.25 41.66 0.2 PUP None15 1551.51 23.26 43.95 29.12 1481.81 365.98 273.76 244.03 366.73 41.71 0.16 PUP None

16 1580.09 23.25 43.97 28.58 1508.06 377.2 281.88 251.86 378.01 41.78 0 PUP None17 1609.27 23.26 44.28 29.18 1534.87 388.66 290.15 259.88 389.52 41.85 0.04 PUP None18 1637.3 23.26 43.48 28.03 1560.63 399.67 298.13 267.55 400.58 41.91 0.11 PUP None19 1666.6 24.73 42.62 29.3 1587.39 411.54 306.84 275.68 412.49 41.94 0.52 PUP None20 1694.81 28.34 39.13 28.21 1612.63 424.12 316.38 283.91 425.09 41.9 1.39 PUP None

21 1723.88 30.85 36.64 29.07 1637.91 438.47 327.71 292.71 439.4 41.77 0.96 PUP None22 1753.28 33.8 34.97 29.4 1662.75 454.18 340.47 301.9 455.04 41.56 1.05 PUP None23 1781.85 36.76 35.64 28.57 1686.07 470.66 353.93 311.44 471.44 41.35 1.04 PUP None24 1810.4 39.34 36.64 28.55 1708.55 488.24 368.13 321.82 488.97 41.16 0.93 PUP None25 1839.3 41.26 36.4 28.9 1730.59 506.93 383.16 332.94 507.6 40.99 0.67 PUP None

26 1868.41 44.03 36.56 29.11 1752 526.64 399.01 344.67 527.26 40.82 0.95 PUP None27 1897.04 47.36 36.02 28.63 1771.99 547.12 415.52 356.79 547.69 40.65 1.17 PUP None28 1905.01 48.28 35.75 7.97 1777.34 553.02 420.31 360.25 553.57 40.6 1.18 PUP None29 1950.16 51.11 37.35 45.15 1806.55 587.43 447.96 380.76 587.92 40.36 0.68 IMP None30 1979.18 53.25 36.53 29.02 1824.34 610.35 466.28 394.53 610.8 40.24 0.77 IMP None

31 2008.47 56.12 36.49 29.29 1841.27 634.24 485.49 408.75 634.65 40.1 0.98 IMP None32 2037.33 59.83 36.77 28.86 1856.57 658.7 505.12 423.35 659.07 39.97 1.29 IMP None33 2066.19 61.28 35.01 28.86 1870.76 683.81 525.48 438.08 684.14 39.82 0.73 IMP None34 2095.26 64.67 33.15 29.07 1883.97 709.64 546.93 452.58 709.9 39.61 1.3 IMP None35 2124.43 66.89 32.95 29.17 1895.93 736.14 569.23 467.09 736.34 39.37 0.76 IMP None

36 2152.59 69.09 32.36 28.16 1906.49 762.13 591.21 481.17 762.27 39.14 0.81 IMP None37 2181.9 72.44 32.31 29.31 1916.14 789.66 614.59 495.97 789.75 38.9 1.14 IMP None38 2211.3 76.64 32.76 29.4 1923.98 817.86 638.47 511.21 817.91 38.68 1.44 IMP None39 2240.07 79.11 33 28.77 1930.02 845.87 662.09 526.48 845.9 38.49 0.86 IMP None40 2268.31 80.18 33.61 28.24 1935.1 873.56 685.31 541.73 873.57 38.33 0.43 IMP None

41 2297.92 81.34 33.59 29.61 1939.85 902.69 709.65 557.91 902.7 38.17 0.39 IMP None42 2308.84 81.75 33.28 10.92 1941.46 913.46 718.66 563.86 913.46 38.12 0.47 IMP None


6

4.4.4.4. StageFRAC* Completion DesignStageFRAC* Completion DesignStageFRAC* Completion DesignStageFRAC* Completion Design

Depth Drawing Description OD (in) ID(in) Length (m)

Perma-Plus Recommend Set less than Packer Set 40 Degree Inclination

1858.1m MD1790m TVD

3 1/2" PH-6 Hyd.TRSSSV 10K Safety Valve c/w 2.562" OTIS 'R' Profile ID c/w 1/4" Control Line 2.562" R Profile 3 1/2" PH-6 Hydril 12.95ppf L-80 Hydril Tubing Joints as Required 2.75" ID

3 1/2 PH-6 x 2.562" OTIS 'R' Selective Profile ID Nipple 2.562" R Profile

Handling Pup - 3-1/2" PH-6 Hydril 12.95ppf BxP x 6' Long L-80 Pup Joint 2.75"

3 1/2" PH-6 Hydril Box Up x 4.00" OD x 10' Long One Piece 'HSN' Bonded Seal Ass. (P-110) 5.875" 2.75" 7" (23-32ppf) Type 'CB' Perma-Plus Packer c/w 4.00" Seal Bore ID x 10' Long (P-110) 5.875" 4.00" 3.04m 7" Perma-Plus Seal Bore to 4 1/2" LTC 15.10ppf L-80 Tailpipe X-Over Sub 5.938" 3.826" .384m

Casing 7" 29 #/ft N-80 (Drift ID=6.059")21 JTS Liner - 4-1/2" LTC 15.10ppf N-80 (Drift ID=3.701") 257.82m

7" Shoe @

MD=1924m Confidential Information - Not to be disclosed outs ide PETROMTVD=1829m BHP- 3200PSI & BHT-86C

2132 m Packers Plus 7" x 4-1/2" Special Clearance RockSeal II Dual Element open hole packer system 5.675" 3.750" 4.69mwith 6ft & 3ft 15.10ppf LTC pup joints on top and bottom (L-80)

Rock Seal Centralizer - Special Clearance 5.750"2 JTS Liner 4 1/2" LTC 15.10ppf N-80 23.51m

STAGE 3 Packers Plus 4-1/2" LTC Re-Closable S.C. FracPort Tool c/w 2.25" Seat ID activated with 2.50" OD 5.675" 2.25" 3.72m2151.52m opening ball and 2000psi Open Pressure w/ 6ft & 3 ft 15.10ppf LTC pup joints on top and bottom (L-80) Seat ID

57 bbl (Note-Alternative Drillable Seat/Non-Closable Type Frac Port Tool Available c/w Max 3.70" Drill Out ID)1 JT Liner 4 1/2" LTC 15.10ppf N-80 11.83m

2167.07m Packers Plus 7" x 4-1/2" Special Clearance RockSeal II Dual Element open hole packer system 5.675" 3.750" 4.69mwith 6ft & 3ft 15.10ppf LTC pup joints on top and bottom (L-80)

Rock Seal Centralizer- Special Clearance 5.750"

2 JTS Liner 4 1/2" LTC 15.10ppf N-80 23.45m

STAGE 2 Packers Plus 4-1/2" LTC Re-Closable S.C. FracPort Tool c/w 2.00" Seat ID activated with 2.25" OD 5.675" 2.00" 3.72m2195.21m opening ball and 2000psi Open Pressure w/ 6ft & 3 ft 15.10ppf LTC pup joints on top and bottom (L-80) Seat ID

59 bbl (Note-Alternative Drillable Seat/Non-Closable Type Frac Port Tool Available c/w Max 3.70" Drill Out ID)

1 JT Liner 4 1/2" LTC 15.10ppf N-80 11.71m

2210.64m Packers Plus 7" x 4-1/2" Special Clearance RockSeal II Dual Element open hole packer system 5.675" 3.750" 4.69mwith 6ft & 3ft 15.10ppf LTC pup joints on top and bottom (L-80)



2226.95m Packers Plus 7" x 4-1/2" Special Clearance RockSeal IIS open hole Rock Anchor System 5.630" 2.900" 4.48mwith 6ft & 3ft 15.10ppf LTC pup joints on top and bottom (L-80) Min. I.D.




STAGE 1 4-1/2" LTC Special Clearance Hyd. Activated DEH FracPORT Tool c/w with 6 ft and 3 ft LTC 5.630" 4.74m2243.04 15.10ppf pup joints on top and bottom (L-80) Non-Closable 61 bbl Rock Seal Centralizer- Special Clearance 5.750"


62 bbl 4 1/2" Toe Circulating Sub with 1.00" seat for 1.25" ceramic closing ball 5.500" NA 5.93m

Rock Seal Centralizer- Special Clearance 5.750"4-1/2" LTC Single Valve Float Collar 5.500"

4-1/2" LTC Single Valve Float Collar 5.500"

2263.20m 4 1/2" LTC Packers Plus Guide Shoe 5.500"Well Total

Depth 2319m MD1943mTVD 6" Open Hole (Total Open Hole Length = 395m)


7

5.5.5.5. Completion Completion Completion Completion ---- Proposed 3 Stage StageFRAC* System Installation and Proposed 3 Stage StageFRAC* System Installation and Proposed 3 Stage StageFRAC* System Installation and Proposed 3 Stage StageFRAC* System Installation and

Operational ProceduresOperational ProceduresOperational ProceduresOperational Procedures

Well Data:Well Data:Well Data:Well Data:

• 9 5/8” 69.95kg/m (47ppf) Intermediate Casing

• 7” 43.17kg/m (29ppf) Production Casing

• 4 ½” 22.47kg/m (15.10ppf) StageFRAC* Open Hole Liner

• 6” Open Hole

5.1.5.1.5.1.5.1. Procedure: Well preparation Procedure: Well preparation Procedure: Well preparation Procedure: Well preparation

RIH w/ Casing Clean Out AssemblyRIH w/ Casing Clean Out AssemblyRIH w/ Casing Clean Out AssemblyRIH w/ Casing Clean Out Assembly

a. Pick up 3 ½” IF Drill Pipe c/w 6” Drill Bit (jets inserts removed) & 7” Casing Scraper to Clean

out casing string.

b. RIH to just above Casing Shoe & Circulate at a minimum of (4-5BBL/Min) to ensure all solids &

scale is removed from the casing (Hi-Vis Sweeps can be beneficial to assist in carrying solids

& scale from the well bore if available)

c. POOH with casing clean up assembly

RIH w/ Open Hole Clean Out & Prep AssemblyRIH w/ Open Hole Clean Out & Prep AssemblyRIH w/ Open Hole Clean Out & Prep AssemblyRIH w/ Open Hole Clean Out & Prep Assembly

a. 6” drill bit –(jet inserts removed)

b. X-Over from Drill Bit to 3 ½” IF

c. 2 Joints of 3 1/2” IF Drill Pipe

d. Packers Plus 5.875” OD open hole RockSEAL Spiral Clean-Out Reamer

e. 2 Joints 3 1/2” IF Drill Pipe (Heavy Weight Optional for stiff assembly)

f. Packers Plus 5.875” OD open hole RockSEAL Spiral Clean-Out Reamer

g. 3 1/2” IF Drill Pipe as required

h. Optional- 3 ½” Heavy Weight Drill Pipe & X-Overs if Required (Vertical Section if Required for

additional weight to push BHA to TD)

i. 3 1/2” IF Drill Pipe as Required to Surface

j. RIH with Bit & Reamers to Perma-Plus Liner Setting Depth and Establish Up & Down Weights

as well as Rotating String weight plus torque required to turn the string slowly and Record for

future reference.

k. Continue to RIH with Bit & Reamers and enter open hole section and Slide Only to Bottom thru

the Open Hole Section (No Rotation)

l. If Bit and Reamers hang up or hit a tight spot then the Reamer should be rotated thru the tight

spot until no drag is noticed going up or down with the string

m. Continue to RIH with Bit & Reamer to +or- 30m past the end of the StageFRAC* Liner Setting

Depth MD if room allows for it

n. Recommend to circulate (4-5BBL/Min) the well bore to clean any cuttings or solids in the open

hole and to push any solids or cuttings 30m +or- deeper in the well bore than the end of the

StageFRAC* Liner TD (Hi-Vis + Low Vis Sweep Combinations can be beneficial to assist in

carrying solids & scale from the well bore if available)

o. Pull Bit back to StageFRAC* Liner TD and again establish up & down weights for future

reference


8

p. Pull back Bit & Reamers just into casing and recommend to circulate (4-5BBL/Min) to clean

any cuttings or solids in the build section (Hi-Vis + Low Vis Sweep Combinations can be

beneficial to assist in carrying solids & scale from the well bore if available)

q. At Perma-Plus Packer Setting Depth establish both up & down string weights plus rotating

string weight and torque required to slowly turn the string. This is baseline information

required for future reference when time to release Hydraulic Setting Tool from Perma-Plus

Liner Hanger Packer.

r. POOH and Stand back the 3 ½ Drill Pipe and recover Bit & Reamer

s. Gauge & Caliper Bit & Reamer to check for wear. Ensure recovered Reamer OD’s are still

larger than RockSEAL Centralizer & RockSEAL Packer OD to be run into well.

5.2.5.2.5.2.5.2. Procedure: StageFRAC* Liner component space out considerationsProcedure: StageFRAC* Liner component space out considerationsProcedure: StageFRAC* Liner component space out considerationsProcedure: StageFRAC* Liner component space out considerations

1.1.1.1. Compare all of the positions of the RockSeal packers to the actual drilled directional survey to ensure that at

no time 2 or more RockSeals are not entering or passing thru any of the more severe dog legs at the same

time during run into TD. Adjust Packer space out as required to ensure this does not happen.

2.2.2.2. Check open hole caliper logs to ensure good packer seats and adjust space out of Packers as required.

3.3.3.3. Lower RockSEAL IIS Packer Seat critical to ensure set in good gauge hole and competent hard rock section

to provide good anchoring points for the StageFRAC* Liner at the bottom.

4.4.4.4. Check StageFRAC* Liner Maximum Hook Load Weights and Drag from Torque & Drag Modeling to ensure

Hydraulic Setting Tool will be in safe Operating Range

Procedure: Running and Setting StageFRAC* AssemblyProcedure: Running and Setting StageFRAC* AssemblyProcedure: Running and Setting StageFRAC* AssemblyProcedure: Running and Setting StageFRAC* Assembly

5.5.5.5. Recommend consideration that each joint of 4 ½” casing/liner below the Perma-Plus Liner Hanger Packer

that will be in the open hole could have a SpiraGlide (Weatherford) Centralizer (or equivalent) secured to the

middle of each joint. This helps in reducing Liner Friction while RIH as well aids in preventing getting

differentially stuck while running in hole with the liner.

6.6.6.6. All Frac Port Tool Seats should be Drift Checked on Location with both the ball size required to pass thru

each of the Frac Port Tool seats plus the actual ball size required to land out on its own specific seat.

7.7.7.7. Hydraulic Setting Tool should be Drift Checked on Location with both the ball size required for the Toe

Circulating Sub to pass thru the seat plus the ball size required to land out on its own specific seat.

8.8.8.8. NOTE- CARE MUST BE TAKEN IN PICKING UP AND HANDLING ALL STAGEFRAC* EQUIPMENT PLUS CARE

IN LOWERING DOWN & CENTERING ALL EQUIPMENT GOING THRU BOP STACK ESPECIALLY ALL

PACKERS.

9.9.9.9. Pick up and RIH with StageFRAC* Sub Assemblies & Liner as fPick up and RIH with StageFRAC* Sub Assemblies & Liner as fPick up and RIH with StageFRAC* Sub Assemblies & Liner as fPick up and RIH with StageFRAC* Sub Assemblies & Liner as follows:ollows:ollows:ollows:

a. 4 1/2” Guide Shoe, Float Equipment and Toe Circulating Sub Assembly with 1.00” seat for a

1.25” ceramic closing ball set to close with 1,100psi1,100psi1,100psi1,100psi +or- closing shear pressure.

b. 4 ½” 15.10ppf LTC J-55 liner as required (minimum 1-2 joints)

c. 4 1/2” SpeciaSpeciaSpeciaSpecial Clearancel Clearancel Clearancel Clearance DualDualDualDual----Hydraulic FracPort Tool (NonHydraulic FracPort Tool (NonHydraulic FracPort Tool (NonHydraulic FracPort Tool (Non----Closable) Closable) Closable) Closable) Sub Assembly

4000psi +or4000psi +or4000psi +or4000psi +or---- (Stage 1)

d. 4 ½” liner as required (minimum 1-2 joints) (Rig up and break circulation 10 BBLS +or- thru

floats to ensure opening properly at 1BBL/Min)


9

e. 7” x 4 1/2” Special ClearSpecial ClearSpecial ClearSpecial Clearanceanceanceance RockSeal IISRockSeal IISRockSeal IISRockSeal IIS Open Hole Anchor/Packer Sub Assembly (2268PSI

+or- Initiating Setting Pressure)

f. 4 ½” 15.10ppf LTC J-55 liner as required (minimum 2 joints)

g. 7” x 4 1/2” Special Clearance RockSeal IIRockSeal IIRockSeal IIRockSeal II Open Hole Packer Sub Assembly (2268PSI +or-

Initiating Setting Pressure)

h. 4 ½” 15.10ppf LTC J-55 liner as required

i. 4 1/2” Special Clearance FracPortFracPortFracPortFracPort Tool (ReTool (ReTool (ReTool (Re----Closable)Closable)Closable)Closable) Sub Assembly with 2” ball seat for

2.25” high pressure ball shear pinned to 1884 psi (Stage 2)

j. 4 ½” 15.10ppf LTC J-55 liner as required

k. 7” x 4 1/2” Special; Clearance RockSeal IIRockSeal IIRockSeal IIRockSeal II Open Hole Packer Sub Assembly (2268PSI +or-


l. 4 ½” 15.10ppf LTC J-55 liner as required

m. 4 1/2” Special Clearance FracPortFracPortFracPortFracPort Tool (ReTool (ReTool (ReTool (Re----Closable)Closable)Closable)Closable) Sub Assembly with 2.25”seat for 2.50”

high pressure ball shear pinned to 1884 psi (Stage 3)

n. 4 ½” 15.10ppf LTC J-55 liner as required

o. 7” x 4 1/2” Special Clearance RockSeal IIRockSeal IIRockSeal IIRockSeal II Open Hole Packer Sub Assembly (2268PSI +or-


p. 4 ½” 15.10ppf LTC J-55 liner as required

q. 7” x 4.00” x 10’-? Long (Seal Bore Length TBD) Seal Bore Type Perma-Plus Liner Hanger

Packer Assembly (Note- Liner Hanger Packer should be spaced out to set in the casing and in

a hole angle of 30 Degrees or less and in a section where doglegs are nor irregular)

r. 3 ½” IF Hydraulic Setting Tool f/ Perma-Plus Liner Hanger Packer (1587PSI +or- Initiating

Pressure)

s. Rig up and break circulation 10 BBLS +or- slowly thru floats to ensure opening properly at

1BBL/Min

t. Pick up & RIH w/ 3 ½” IF Drill Pipe to Surface

10.10.10.10. Use a fill hose (Not Tied in as a Close Loop) only to fill Liner with Clean Fluid or Clean Mud (Min Solids) every

15-20 Joints. Ensure the clean Fluid or Clean Mud that is used to fill the Liner & DP is the same weight of fluid

or slightly less than the fluid or mud weight that is in the Annulus (CANNOT BE HEAVIER FLUID)

11.11.11.11. Do not rotate the assembly while RIH.

12.12.12.12. The Pipe Running Speed of the StageFRAC* Liner should be set at maximum 40 Sec/30’ Joint in the Vertical

Section and 50 Sec/30’ Joint in the Build Section of the Casing.

13.13.13.13. RIH the end of the StageFRAC* Liner Assembly to just above the 7” Casing Shoe.

14.14.14.14. Establish up & down weights prior to entering Open Hole

15.15.15.15. Break circulation only by starting slow at 1 bbl/min and pump about 10 BBLS +or- do not exceed either

2bbls/min or 300psi DP differential which ever comes first.

16.16.16.16. Run assembly to setting depth not exceeding 60 sec/joint in the Open Hole Section (or specified running

speed Packers Plus service technician)


10

17.17.17.17. Do not circulate again until at TD – If difficulties are encountered while running StageFRAC* Assembly into

the horizontal open hole operations must stop & consider all possibilities to why the BHA is stick.

Recommend to discuss the situation first with PP StageFRAC* Tech Service Support Personnel prior to

attempting anything on location.

18.18.18.18. Once StageFRAC* Liner is at desired TD establish up & down weights and then get the Liner positioned on

desired depth and the 4 ½” Frac String sitting in Neutral Position. Space out the Frac String to install Tubing

Hanger plus Handling Pup to position the liner as required as well as adjustment for compression required

on string to do the Frac. (20,000lbs +or- Compression TBD Verify on Packers Plus Force Analysis Program)

19.19.19.19. Establish & Break Circulation starting slow at 1 BPM and do not exceed a recommended safe rate (not to

exceed 2 bpm or 300psi differential which ever comes first)

20.20.20.20. Optional - Circulate open hole section over to clean fluid if required prior to setting Packers

Setting and testing the PermaSetting and testing the PermaSetting and testing the PermaSetting and testing the Perma----Plus PackerPlus PackerPlus PackerPlus Packer

21.21.21.21. Drop 1.25” Toe Circulation shut off ball provided by Packer’s Plus

22.22.22.22. Circulate setting ball onto seat with clean KCL fluid not to exceed 2bpm or 300psi DP differential which ever

comes first

23.23.23.23. When the ball is on seat pressure up to 1,200psi (Toe Circulation Sub is set to shear closed at 1100 psi).

24.24.24.24. Pressure up slowly to 1750psi and hold for 10 Minutes to stroke Hydraulic Setting Tool and start setting

Perma-Plus Liner Hanger Packer

25.25.25.25. Maintain 1750 PSI on DP & pull 20,000lbs Tension into Perma-Plus & hold 5 Min. Pull 30,000lbs Tension and

hold for 5 Min. Pull 40,000lbs Tension and hold 10 Min.

26.26.26.26. Maintain 1750 PSI on DP and slack-off 30,000lbs compression on Perma-Plus Packer. Pull to neutral and

bleed off DP pressure to Zero.

27.27.27.27. Take Final Pull of 50,000lbs Tension into Packer & Hold 5 Min. Lower DP String into 30,000lbs Compression &

Hold 5 Min.

28.28.28.28. Pick up DP String to neutral and Pressure Test Annulus to 3000PSI

Setting the RockSEAL II & IIS PackersSetting the RockSEAL II & IIS PackersSetting the RockSEAL II & IIS PackersSetting the RockSEAL II & IIS Packers

29.29.29.29. Pressure up DP slowly to 2400psi to stroke the (4) RockSEAL II & IIS Packers. (2268PSI +or- Initiating Setting

Pressure) Hold 5Minutes

30.30.30.30. Stage Pressure up to 2700 psi to continue setting Packers. Hold 5 Minutes

31.31.31.31. Stage Final Pressure up to 3000 PSI to finalize packer setting. Hold 15 Minutes

Releasing the Running ToolReleasing the Running ToolReleasing the Running ToolReleasing the Running Tool

32.32.32.32. Bleed Off DP Pressure & place Drill pipe in 2-3000lbs tension over Rotating String Weight previously

established on Bit & Reamer Clean out Trip. Note- Reference Up & Down Weights plus Rotating String

Weights & Torque Required to turn the drill string established on clean out trip with Reamer Assembly at

Perma-Plus Packer Setting Depth.

33.33.33.33. Rotate 10-12 to the right while maintaining the tension and then slowly pull away from Packer 10-12’ minimal

with the Hyd. Setting Tool


11

34.34.34.34. Stop & Circulate rest of well bore over to desired fluid to be left in annulus and to displace Mud System out

of hole if applicable

35.35.35.35. POOH and lay out Drill Pipe & Hydraulic Setting Tool and Inspect

Procedure: Running and Spacing out TieProcedure: Running and Spacing out TieProcedure: Running and Spacing out TieProcedure: Running and Spacing out Tie----Back Seal AssemblyBack Seal AssemblyBack Seal AssemblyBack Seal Assembly

1.1.1.1. Pick up the PP 3 ½” EUE x 10’ Long (Seal Assembly Length TBD) x 4.00” OD Tie Back Seal Assembly Sub

Assembly

2.2.2.2. Pick up the PP 2.562” OTIS ‘R’ Nipple Sub Assembly

3.3.3.3. RIH with the 3 ½” PH-6 12.95ppf Hydril Frac/Production Tubing string.

4.4.4.4. Stop 3 joints above the Perma-Plus Packer. Establish up & down string weights plus torque required to turn

the string.

5.5.5.5. RIH slowly to tag the Perma-Plus Packer while watching for any Seal Drag entering the 10’ Long Packer Seal

Bore.(Correlate DP tally with Tubing tally)

6.6.6.6. Pick up 1m and Pressure Test down the annulus to double check if the Seals are actually Stung in to the

Perma-Plus or just hung up on top of the Perma-Plus Packer. If 3000 PSI Annular Pressure Test is successful

bleed off annulus pressure to zero.

7.7.7.7. Slack-off 20,000 lbs of compression (TBD) string weight on the Perma-Plus Packer. Mark the pipe to allow

for space out of the Frac String.

8.8.8.8. Pull the Seal Assembly back out as required to space out the tubing string for desired compression plus

adding in the SLB SSSV Assembly with (a) pup joint(s) to be able to land out the string with the tubing

hanger.

9.9.9.9. Install Schlumberger Tubing Retrievable Sub Surface Safety Valve Sub Assembly c/w 2CAMCO 2.562'' D.S.

Profile''Selective Profile ID

10.10.10.10. Install the ¼” Hydraulic Control Line to SSSV and Function SSSV & Pressure Test Line & Fittings to Safe

Working Test Pressures

11.11.11.11. Band Control Line as Required just above SSSV on Upper Flow Coupling

12.12.12.12. RIH with Tubing Joints and Install Control Line Protectors over each Hydril Connection.

13.13.13.13. Install Tubing Hanger & Terminate or FeedThru Hydraulic Control Line into Hanger as required.

14.14.14.14. Pressure Test Hydraulic Control Line after Termination

15.15.15.15. Install Hydraulic Jumper Line to the top of the Tubing Hanger to all for the SSSV to be kept in the open

position when stinging into the Perma-Plus Packer & Landing out the Tubing Hanger in the Bowl. Pressure

Test Jumper Line.

16.16.16.16. Lower the tubing slowly while maintaining Pressure on the Hyd. Jumper Line to sting the 10’ Long Seal

Assembly back into the Perma-Plus Packer

17.17.17.17. Ensure RISER & BOP Stack is drained to ensure Hanger is Centralized while lower down to land out in the

tubing head flange.

18.18.18.18. Ensure Casing Valve is open to allow fluid to displace out so that hanger can fully & properly bottom out.

19.19.19.19. The weight should show 20,000 lbs compression as the Tubing Hanger lands out in the Tubing Head Spool.


12

20.20.20.20. Install Tubing Hanger Lag Screws. Recommend remove 1 Lag Screw to do visual to ensure hanger

positioned properly prior to install lag screws to lock in the hanger.

21.21.21.21. Pressure Test the annulus to 3,000psi. Hold for 15minutes.

22.22.22.22. Bleed off annulus pressure.

23.23.23.23. Pressure up the tubing to 3000 psi to verify seal integrity from inside. Hold for 15 minutes. Bleed Off Tubing

Pressure

24.24.24.24. Install Back Pressure Valve as Required.

25.25.25.25. Nipple down BOP Stack & Nipple up Frac/Well Head as required.

26.26.26.26. Ensure Frac Head/Tree Saver is pre-drifted with largest Frac Ball to be pumped to ensure will pass thru.

27.27.27.27. Pressure Test Frac Head.

28.28.28.28. Remove Back Pressure Valve

29.29.29.29. Mobilize SLB for StageFRAC*

Notes:Notes:Notes:Notes:

If the assembly becomes stuck while RIH STOP Operations.

The PackersPlus Service Specialist on location will provide safe tension and compression limits for every 1000

feet of assembly in the open hole.

If it is determined that the assembly is differentially stuck, options for releasing the assembly should be explored.

Excessive pulling and compressing the assembly if differentially stuck could result in fatiguing components and

should be avoided.

Reducing Mud or Fluid Weights in the well if determined to be differentially stuck without constantly working the

string will help maintain Liner & Running String Integrity until the formation lets go of the liner once fluid weights

reduced to balance formation pressure.

5.3.5.3.5.3.5.3. Procedure: Opening the Hydraulic FracPort & Preparing for Frac JobProcedure: Opening the Hydraulic FracPort & Preparing for Frac JobProcedure: Opening the Hydraulic FracPort & Preparing for Frac JobProcedure: Opening the Hydraulic FracPort & Preparing for Frac Job

30.30.30.30. Install Tree Saver if Required & Nipple up both Frac Lines & Flow Line thru Testers c/w Ball Catcher in line

prior to testers equipment. (Drift Tree Saver with largest ball plus ball launch lines & return test line

plumbing to ball catcher to ensure largest Frac Ball will pass thru prior to rigging up on well head)

31.31.31.31. Apply +/- 2000 psi on the annulus

32.32.32.32. After the surface frac equipment has been installed and tested, apply +/- 2000 psi on the tubing

33.33.33.33. Apply 3000 psi on the tubing

34.34.34.34. Increase tubing pressure to +/- 4000 psi to open the Hydraulic FracPort

35.35.35.35. If able establish an injection rate and injection pressure

36.36.36.36. Ready to commence 1st stage frac job

37.37.37.37. Ensure adequate back pressure is maintained on the annulus for the entire Frac Job. Note- Verify required

amount of pressure to be held with Packers Plus Force Analysis Program.

38.38.38.38. Proceed with Frac Job as per Schlumberger Frac Engineer


13

6.6.6.6. Equipment LayEquipment LayEquipment LayEquipment Lay----out and Rigout and Rigout and Rigout and Rig----upupupup

6.1.6.1.6.1.6.1. Wellhead Rig UpWellhead Rig UpWellhead Rig UpWellhead Rig Up

General RecommendationsGeneral RecommendationsGeneral RecommendationsGeneral Recommendations

• Be very aware of the ID clearance of the entire system to accept the StageFRAC* balls

• This may be a very long lead item and specialty import if new to the area

• Tubing and BOP configuration must be carefully analyzed before being used

o System is less robust to high pressures or sudden increases of screen out pressure

• Rabbit all Frac Iron to be used for placement of the frac balls

o Max ball size for 3” 1502 iron is 2.5”

• Rabbit the Frac Tree with the largest ball

• Rabbit any crossovers that have been added to the system

Wellhead RigWellhead RigWellhead RigWellhead Rig----Up on “Jupiter” PlatformUp on “Jupiter” PlatformUp on “Jupiter” PlatformUp on “Jupiter” Platform


14

6.2.6.2.6.2.6.2. Supply Vessel Supply Vessel Supply Vessel Supply Vessel –––– “Active King”Rig “Active King”Rig “Active King”Rig “Active King”Rig----upupupup

Supply Vessel Supply Vessel Supply Vessel Supply Vessel ---- “Active King” “Active King” “Active King” “Active King” –––– Rig Up Rig Up Rig Up Rig Up


15

6.3.6.3.6.3.6.3. Platform Platform Platform Platform –––– “Jupiter” Rig “Jupiter” Rig “Jupiter” Rig “Jupiter” Rig----upupupup

“Jupiter” Platform Rig Up“Jupiter” Platform Rig Up“Jupiter” Platform Rig Up“Jupiter” Platform Rig Up

“Jupiter” Platform Rig Up “Jupiter” Platform Rig Up “Jupiter” Platform Rig Up “Jupiter” Platform Rig Up ---- Detail Detail Detail Detail


16

7.7.7.7. Fracture Design and Proppant PlacementFracture Design and Proppant PlacementFracture Design and Proppant PlacementFracture Design and Proppant Placement

Well Lebada Vest 03 is the first Petrom S.A. horizontal well where multiple hydraulic fracturing treatments will be

performed offshore Black Sea.

Previously performed fracturing treatments on Lebada Vest field (8) were performed in single stage by using 35#

or 40 #/1000 gal Guar or HPG polymer based fracturing fluid.

The design of those jobs was based on 20-30 % total clean fluid volume as PAD stage, 3.0 m3/min pump rate, up

to 100 tones of 20/40 or 16/20 Carbo Lite proppant with resin coated proppant run in final proppant stage.

Total fluid pumped per job was 200-250 m3 and the maximum slurry proppant concentration was up to 1200 KgPA.

Maximum wellhead treating pressure was bellow 400 bar.

The fracturing gradient in the offset well in the same zone of interest was 0.68 – 0.75 psi/ft and the reservoir

pressure at TVD is expected to have value of 210 to 220 bar, bottom hole static temperature is ~90 degC.

The zone of interest is 50 to 60% dirty limestone which is laminated with the streaks of different permeability

ranging from 0.1 to 2.0 mD, mostly in the range around 0.8 mD and porosity ranges between 15 to 22 %.

No screen out occurred during the previous fracturing treatments and no significant net pressure after the job

was recorded.

It was discovered that post job production per well in early treatments that is strongly related to mass and size of

proppant pumped and it was ranging from 30 tones oil per day in early treatments up to 70 tones of oil per day in

most recent well treated which had reservoir pressure value very close to virgin reservoir pressure.

Petrom geologists indicated that there is no water zone in proximity of targeted zone and the gas/oil contact (gas

cap) is expected on 1840m TVDSS.

The designs presented as attachment are based on conservative job design approach where PAD% is ranging

from 41% to 48% and maximum proppant concentration planned is up 5 or 6 PPA respectively in order to minimize

risk of premature screenout and capital retained fracture conductivity gains enabled by ClearFRAC XT non

damaging fluid chemistry.

The desired pump rate will be up to 3.0 m3/min and the total proppant mass per stage will range from 60 tones in

early conservative stages up to ~80 tones of 20/40 Carbo Lite in more aggressive final treatment.


17

LV 03 Well LV 03 Well LV 03 Well LV 03 Well ---- Geological Section Geological Section Geological Section Geological Section Lebada West Lebada West Lebada West Lebada West ---- Seismic Map Seismic Map Seismic Map Seismic Map

Lebada West Lebada West Lebada West Lebada West –––– Structural Map Structural Map Structural Map Structural Map Offset Well Offset Well Offset Well Offset Well ----LV 81 Log with respect to LV03LV 81 Log with respect to LV03LV 81 Log with respect to LV03LV 81 Log with respect to LV03

Note*Note*Note*Note*

Job designs for each stage are splayed in separate attachments.

Approximate LV03 windowApproximate LV03 window


18

LV03 Composite LogLV03 Composite LogLV03 Composite LogLV03 Composite Log


19

Structural cross section displayed with a NEStructural cross section displayed with a NEStructural cross section displayed with a NEStructural cross section displayed with a NE----SW orientation.SW orientation.SW orientation.SW orientation. Blue boxes represent conductive fractures

corridors, pink boxes faults corridors.

Conductive fracturesMaximum density

Micro-faultsMaximum density

Conductive fracturesMaximum density

Micro-faultsMaximum density


20

8.8.8.8. Pre Job PrepPre Job PrepPre Job PrepPre Job Preparationarationarationaration

8.1.8.1.8.1.8.1. PrePrePrePre----job HP Rigjob HP Rigjob HP Rigjob HP Rig----upupupup

• Prior to the vessel arriving on location at the jack-up rig GSP Jupiter, ensure sufficient 2” and 3”

treating iron. and a rig-up crew of 4 personnel have been dispatched to the Jupiter to cover the initial

rig-up operation of the 3” frac line from the vessel Coflex hanger area ( port side ) up to the rig floor, this

line can be pressure tested to 690 bar with the SLB cement unit before the vessel arrives on location.

• Install a pressure transducer in the main treating line and one in the annulus, an annular PRV should

also be installed.

8.2.8.2.8.2.8.2. Fluid Preparation on VesselFluid Preparation on VesselFluid Preparation on VesselFluid Preparation on Vessel

1. Ensure sufficient seawater volume ( non treated ) is added to the POD Blender header tank for pre-job

flushing lines, priming pumps and pressure testing.

2. Pre-load the 6 x 81m3 vessel liquid mud tanks with (filtered) seawater treated with M275 Biocide, Have

all liquid additives (ClearFRAC Surfactant J590, Rheology Modifier J589, Clay Stabilizer L064 and Non

Emulsifying Agent W054) readily prepared in the LAS tanks.

3. Set up the LAS pumps for the following liquid additives, J590, J589, L064 & W54, to be injected into the

relative injection points in the POD suction system, J567 (Encapsulated Breaker) will be added via the

dry additive screw feeder on the POD blender only during slurry stages. Perform LAS bucket tests and

base fluid QA/QA tests with samples from the liquid additive tanks.

8.3.8.3.8.3.8.3. Vessel Hookup to the RigVessel Hookup to the RigVessel Hookup to the RigVessel Hookup to the Rig

1. Confirm with the vessel bridge that the captain is satisfied with vessel dynamic positioning prior to

deploying the Coflex hose.

2. Establish good radio communication with SLB rig-up supervisor on the Jupiter and GSP crane operator,

follow Coflex hose deployment procedure.

3. Once the Coflex hose is secured in the Coflex hanger return the crane hook to the aft deck of the vessel

to pick up the 2 x pressure transducer cables ( tied together for a one lift operation ) the cables should

be secured to the hand-rail of the rig, the remaining length of cables will be run from the Coflex hanger

area up to the rig-floor to connect to the pressure transducers.

8.4.8.4.8.4.8.4. Pressure TestPressure TestPressure TestPressure Test

1. Hold a pre-job safety meeting on the Active king and Jupiter rig and discuss job assignments.


21

2. Flush and prime each SPF 343 pump with seawater through the bleed off line on the rig-floor. Close the

main line PRV isolation valve.

3. Pressure test the lines to 690 bar690 bar690 bar690 bar in three equal increments against the SLB Master isolation valve.

Inspect the lines. Observe the pressure record for 5 minutes5 minutes5 minutes5 minutes at each increment. Hold for 10 minutes10 minutes10 minutes10 minutes at

690 bar690 bar690 bar690 bar.

4. Ensure wellhead master valve is closed, bleed off the pressure to approx 70 bar 70 bar 70 bar 70 bar and open the SLB

Master valve. Open the 3” actuated valve from the cement unit and perform the same test, up to 610 bar

as above with the cement pump against the client master valve to ensure integrity of this section of

treating line as well as the integrity of the wellhead master valve.

5. Bleed off to 70 bar70 bar70 bar70 bar and open the GORV isolation valves, GORV set at 580 bar 580 bar 580 bar 580 bar (Confirm N2 set pressure =

589 bar ) NOTE; GORV discharge line to run to over-board vessel.

6. Set the vessel trip at 565 bar565 bar565 bar565 bar and re-pressure the lines to observe the vessel trip and hold the pressure

for 10 minutes10 minutes10 minutes10 minutes to test the GORV seat.

7. Install the 2” annulus PRV ( set for 170 bar170 bar170 bar170 bar ) and isolate, pressure test the Annulus to 202020200 bar0 bar0 bar0 bar hold for

10min, bleed the pressure down to approx 70 bar 70 bar 70 bar 70 bar and open PRV isolation valve, increase the pressure

to 160 bar160 bar160 bar160 bar to test annulus PRV seat.

8. Bleed off the pressure to 10 bar10 bar10 bar10 bar over the calculated WHP to equalize over the X-mass tree. Open the X-

mass tree valves and record the WHP.

Note:Note:Note:Note:

The Packers Plus Supervisor will notify the stimulation vessel engineer regarding the exact depths of the

3 frac ports and annulus pressure to be applied prior to pumping.

SLB engineer to calculate exact flush volume from vessel pumps to each frac port in the StageFRAC

assembly, taking into account the volume of all 3” treating lines between HP pump discharge ports and

wellhead, confirm volumes with client representative.

Prior to pumping into the well the Drilling Supervisor and Production operator are to confirm the following

valve status;

SLB Master valve ---- open open open open

Swab valve ---- open open open open

Service wing ---- closed closed closed closed

Production wing ---- closed closed closed closed

Upper master valve ---- hydraulically locked open hydraulically locked open hydraulically locked open hydraulically locked open

Lower master valve ---- open open open open

SLB SSSV - open, control line pressure of 690 bar applied


22

9.9.9.9. Pumping ProcedurePumping ProcedurePumping ProcedurePumping Procedure

9.1.9.1.9.1.9.1. DataFRACDataFRACDataFRACDataFRAC

Since it is newly drilled well and limited number information are available on the formation characteristics, it is

important to confirm some formation data related to transmissibility, closure pressure and fluid leakoff. Those

data can be gathered through series of the tests which are also part of DataFRAC* service.

DataFRAC PumpDataFRAC PumpDataFRAC PumpDataFRAC Pumping Sequence:ing Sequence:ing Sequence:ing Sequence:


23

9.1.1. DataFRAC - Injection Test

An Injection Test will be performed pumping treated seawater to breakdown the formation and initiate the

fracture.

The steps to be followed on the injection test are:

1. Pressure up annulus to 140 bar.

2. If no pressure was seen on surface, start pumping the treated sea water to fill the well through tubing.

3. Once the well is full after pumping aprox. 10 m3, after short shut in, start the injection test as

recommended and agreed on the pumping schedule (10 m3 of treated sea water which composition is

described in job design attachments) and then and hard shut in.

NoteNoteNoteNote: : : :

• The proposed pumping schedule is preliminary and will be subject to some modification on location

based on the observed pressure and the formation response.

• Monitor the annulus pressures during pumping operations.

4. After formation breakdown is observed, shut in and monitor the pressure decline and perform a Mini

Fall Off (MFO) analysis

Note: Note: Note: Note:

• Do not exceed 8,500 psi pump pressure. If breakdown has not occurred at 8,500 psi shutdown

pumps and reconsider options.

• Monitor annulus pressures throughout the pumping operation.

9.1.2. DataFRAC - Step Rate/Step Down Test

1. After closure is observed and MFO analysis completed resume the Injection Test and perform a Step

Rate Test and Step Down Test with the stages length upon on site engineer recommendation (steps

should be isochronal and volume will depend on pump rate – aprox 15 m3 of treated sea water will be

pumped in this stage).

2. After completion of the last step stage during Step Down Test – Shut In and monitor pressure decline.

Note: Note: Note: Note:

• Monitor annulus pressures throughout the pumping operation

9.1.3. DataFRAC - Pre–Flush

Prior the Calibration Injection pumped by using ClearFRAC XT fluid a Pre-Flush Stage (15 m3 of Pre-Flush fluid

which composition is described in job design attachments) will be pumped with Preflush Fluid at the same pump

rate. The objective of this stage is to inject into formation chemical additives which will enhance post job


24

viscosity degradation (breaking) of ClearFRAC XT fluid. After the planned volume of Pre-Flush fluid will be

pumped DataFRAC – calibration Injection stage will start.

9.1.4. DataFRAC - Calibration Injection

The DataFRAC* Calibration Injection will be performed using 60 m3 of ClearFRAC XT fluid at 3.0 m3/min pump rate

followed by displacement stage when treated sea water will be pumped. After “hard” Shut In pressure decline

will be monitored.

Prior to carrying out the Calibration Injection the on site fracturing QA/QC will be performed as per Appendix 1

and real time samples must be taken during all treatments.

NoteNoteNoteNote::::

• Displacement volume should be adjusted on-site to take into account actual surface line volumes.

• Once the DataFRAC treatment has been pumped shut down and monitor pressure fall off. This data

will be used to measure closure pressure, calculate fluid efficiency and redesign main frac

program if necessary.

• The pressure decline will be observed until clear fracture closure is observed or wellhead pressure

will reach 0 bar.


25

9.2.9.2.9.2.9.2. Main Fracturing TreatmentsMain Fracturing TreatmentsMain Fracturing TreatmentsMain Fracturing Treatments

The main fracture treatment will adjusted based on the observed parameters from the Injection Test, Step Rate

Test, Step Down Test and the DataFRAC Calibration Injection.

The pumping schedule is based on the previous operation experience and StageFRAC* and published ClearFRAC

XT documentation recommendations since the actual well data are not available at this moment.

9.2.1. Main fracturing Treatment – Stage #1

Main Frac Pump Schedule Main Frac Pump Schedule Main Frac Pump Schedule Main Frac Pump Schedule –––– Stage #1 Stage #1 Stage #1 Stage #1 (actual design will be determined after DataFRAC)

Ahead of each Main Fracturing Treatment a Pre-Flush will be pumped with Preflush Fluid at the same pump rate.

The objective of this stage is to inject into formation additives which will enhance post job viscosity degradation

(breaking) of ClearFRAC XT fluid. After the planned volume of Pre-Flush fluid will be pumped Main Fracturing

Treatment -PAD stage will start.


• Prior to carrying out the Main Fracturing Treatment QA/QC will be performed as per procedure

mentioned further in the test and real time samples must be taken.

• Displacement volume should be adjusted on-site to take into account actual surface line volumes.


26

Flushing and Ball Lunching Procedure Flushing and Ball Lunching Procedure Flushing and Ball Lunching Procedure Flushing and Ball Lunching Procedure –––– Stage #1 Stage #1 Stage #1 Stage #1

1. Once that designed proppant amount is pumped, proppant gate will be closed on POD blender and

flush procedure will start. (Assuming that 1st StageFRAC* ball (2.25”) is pre-loaded into the 3” ball

launching manifold)

2. End of proppant stage – Ensure NRD is reading zero PPA , flush volume will be the calculated

volume from this point ( NOTE Total Slurry Volume pumped )

3. Reduce treating pump rate from 3.0 m3/min to 2 m3/min bpm, pumping same gelled fluid, note

treating pressure once the rate at 2 m3/min and inform cement operator to apply same pressure to

cement treating line,

4. After ~1 m3 of flush fluid pumped ( treating line volume from vessel to Y ball launcher and to treating line volume from vessel to Y ball launcher and to treating line volume from vessel to Y ball launcher and to treating line volume from vessel to Y ball launcher and to

wellhead clean of proppant to be calculated after rig upwellhead clean of proppant to be calculated after rig upwellhead clean of proppant to be calculated after rig upwellhead clean of proppant to be calculated after rig up) reduce the pump rate to 1.5 m3/min,

inform rig-floor manifold operator as soon as pump rate is reading 10bpm to open 3” HP actuated

valve,

5. Once rig-floor manifold operator has confirmed that the 3” HP actuated valve is in the open

position, inform cement operator to begin pumping at 0.8 m3/min to launch the ball, the ball should

immediately be launched into the main treating line ( can be heard by manifold operator )

6. Manifold operator then confirms to Frac Master that the ball has been launched

7. Cement operator instructed by Frac Master to take his pump out of gear

8. Manifold operator instructed by Frac Master to close 3” HP actuated valve, manifold operator

confirms when valve is closed

9. Treating pump rate is brought back up to 3.0 m3/min

10. Frac Master to confirm with cement operator the volume of fluid that he pumped with his unit, this

volume is added to Total Slurry Volume to have an accurate account of flush volume pumped

11. Use the ball landing prediction excel spreadsheet, this will predict the ball arrival time at the

StageFRAC* tool seat, treatment pump rate will be reduced down to 1.6 m3/min or otherwise noted.

12. Once the ball has seated ( pressure spike indication ) the port will now be open, increase pump rate

to 3.0 m3/min to initiate fracture of 2nd

zone

13. Stop pumping if the proppant silos or additive tanks need reload, if not continue pumping.

ReReReRe----load ball launcher with 2load ball launcher with 2load ball launcher with 2load ball launcher with 2ndndndnd

StageFRAC* ball StageFRAC* ball StageFRAC* ball StageFRAC* ball

1. Manifold operator to communicate with cement operator to find out what pressure remains on the

cement line

2. Manifold operator to slowly bleed-off the pressure in the cement line ( between 3” actuated ULT

and 2” check valve )

3. Once pressure is bled off, close bleed off valves immediately ( to keep line full of fluid )

4. Slowly open the 3” ULT valve and load the 2nd

StageFRAC* (2.5”) ball ( confirm ball size prior to

loading )

5. Close 3” ULT valve, StageFRAC* ball is now loaded and ready to launch.


27

9.2.2. Main fracturing Treatment – Stage #2

According to pressure behavior while pumping Stage#1 pumps schedule for the Stage#2 might be modified in

order to prevent screen-out and ensure maximum frac performance.

The preliminary design for the Stage #2 represent slightly more aggressive design upper stated for the Stage #1.


Flushing and Ball Flushing and Ball Flushing and Ball Flushing and Ball Lunching Procedure Lunching Procedure Lunching Procedure Lunching Procedure –––– Stage #2 Stage #2 Stage #2 Stage #2

1. Once that designed proppant amount is pumped, proppant gate will be closed on POD blender and

flush procedure will start. (Assuming that 2nd

StageFRAC* ball (2.5”) is pre-loaded into the 3” ball

launching manifold)

2. End of proppant stage – Ensure NRD is reading zero PPA , flush volume will be the calculated

volume from this point ( NOTE Total Slurry Volume pumped )

3. Reduce treating pump rate from 3.0 m3/min to 2 m3/min bpm, pumping same gelled fluid, note

treating pressure once the rate at 2 m3/min and inform cement operator to apply same pressure to

cement treating line,

4. After ~1 m3 of flush fluid pumped (treating line volume from vessel to Y ball launcher and to treating line volume from vessel to Y ball launcher and to treating line volume from vessel to Y ball launcher and to treating line volume from vessel to Y ball launcher and to

wellhead clean of proppant to be calculated after rig upwellhead clean of proppant to be calculated after rig upwellhead clean of proppant to be calculated after rig upwellhead clean of proppant to be calculated after rig up) reduce the pump rate to 1.5 m3/min,

inform rig-floor manifold operator as soon as pump rate is reading 10bpm to open 3” HP actuated

valve,

5. Once rig-floor manifold operator has confirmed that the 3” HP actuated valve is in the open

position, inform cement operator to begin pumping at 0.8 m3/min to launch the ball, the ball should

immediately be launched into the main treating line ( can be heard by manifold operator )

6. Manifold operator then confirms to Frac Master that the ball has been launched

7. Cement operator instructed by Frac Master to take his pump out of gear

8. Manifold operator instructed by Frac Master to close 3” HP actuated valve, manifold operator

confirms when valve is closed


28

9. Treating pump rate is brought back up to 3.0 m3/min

10. Frac Master to confirm with cement operator the volume of fluid that he pumped with his unit, this

volume is added to Total Slurry Volume to have an accurate account of flush volume pumped

11. Use the ball landing prediction excel spreadsheet, this will predict the ball arrival time at the

StageFRAC* tool seat, treatment pump rate will be reduced down to 1.6 m3/min or otherwise noted.

12. Once the ball has seated ( pressure spike indication ) the port will now be open, increase pump rate

to 3.0 m3/min to initiate fracture of 3rd zone

13. Stop pumping if the proppant silos or additive tanks need reload, if not continue pumping.


29

Main fracturing Treatment – Stage #3

According to pressure behavior while pumping Stages #1 and Stage #2 pump schedule for the Stage#2 might be

modified in order to prevent screen-out and ensure maximum frac performance.

The preliminary design for the Stage #3 represent even more aggressive design prepared for previous stages.


Once that designed volume of flush stage has been pumped stop pumping under flashing the well for 4 bbl and

monitor pressure decline.


30

10.10.10.10. Flowback Flowback Flowback Flowback

The time required for the fracture to close should be closely monitored after the treatment. If pressure decline

data do not indicate the fracture is going to close before the fluid is scheduled to break, then pressure should be

bled off to the fracture closure pressure by flowing the well on a 2/64 inch to 4/64 inch at a rate of 5-10 gal/min.

Once fracture closure is achieved, the well can be shut in to allow the fluid to break.

If the well has the capacity to flow on its own after the treatment, then it should be kept on small chokes (6/64 to

8/64 inch) during the initial cleanup. Back pressure against the formation should be maximized.

Start flow backing thro small choke (6/64 to 8/64 inch) at rate of 5-10 gal/min until full tubing volume is retrieved, if

no proppant flowback is occurred gradually step like increase choke size crosschecking proppant flowback on

the surface .

A shut-in well or producing well should never be opened on a large choke instantaneously. Gradual choke

increases in 2/64 inch increments are recommended. If necessary, these increases should be spread out over

several days or weeks.

Stop flowback until full volume of fracturing fluid is retrieved or oil production is at acceptable level.

If no Coiled Tubing cleanout after the job will be performed (not recommended):If no Coiled Tubing cleanout after the job will be performed (not recommended):If no Coiled Tubing cleanout after the job will be performed (not recommended):If no Coiled Tubing cleanout after the job will be performed (not recommended):

The difference between conventional well and well with stage frac completion is that it would be best to be able

to flow the well back quickly, thus some of the balls should be returned to the surface.

• The ball catcher should be configured into the flow-back line to allow fluid recovery without shutting

down.

• Ball Catcher and flow back lines should already be rigged up

• Ensure the smallest ID through the wellhead, and flow line to the rock / ball catcher is LARGER than the

largest ball dropped during the stimulation.

• Downstream of Ball Catcher should be Service testing company flow back iron

• Schlumberger Well Services connections to tie on to a 3" 1502 Weco thread.

• Open Well, and Flow back at the smallest choke if well flows by itself, if not follow the CT Well Cleanout

and Lifting Procedure

• Monitor for any Hydrocarbons to surface

• Monitor Ball(s) returns.

• Stop flowback until full volume of fracturing fluid is retrieved or oil production is at acceptable level.


31

11.11.11.11. On Site QA/QC Lab Testing Procedure for ClearFRAC XT FluidOn Site QA/QC Lab Testing Procedure for ClearFRAC XT FluidOn Site QA/QC Lab Testing Procedure for ClearFRAC XT FluidOn Site QA/QC Lab Testing Procedure for ClearFRAC XT Fluid

11.1.11.1.11.1.11.1. Introduction Introduction Introduction Introduction ---- ClearFRAC XT Reference Rheolog ClearFRAC XT Reference Rheolog ClearFRAC XT Reference Rheolog ClearFRAC XT Reference Rheologyyyy

Example of typical rheological properties of ClearFRAC XT 60, 40 and 20 straight fluids with 2 galUS/1,000 galUS

L064 prepared in laboratory condition with fresh water:


32

Example of Example of Example of Example of Fann 50 viscosity vs. temperature of 45 galUS/1,000 galUS J59Fann 50 viscosity vs. temperature of 45 galUS/1,000 galUS J59Fann 50 viscosity vs. temperature of 45 galUS/1,000 galUS J59Fann 50 viscosity vs. temperature of 45 galUS/1,000 galUS J590 0 0 0


33

11.2.11.2.11.2.11.2. On Site Fracturing Fluid QA/QCOn Site Fracturing Fluid QA/QCOn Site Fracturing Fluid QA/QCOn Site Fracturing Fluid QA/QC

Sampling of water and additivesSampling of water and additivesSampling of water and additivesSampling of water and additives

Sampling of waterSampling of waterSampling of waterSampling of water

• Obtain a water sample of ~500 ml from each fracturing tank at the middle valve;

• Ensure the water samples are representative of the tank by draining a few liters before catching the

sample.

Sampling of additivesSampling of additivesSampling of additivesSampling of additives

• Get a sample of ~200 ml of both J590 and J589 from each lot on location and record the lot number;

• Circulation of J590 or J589 prior the job is not required.

Testing of waterTesting of waterTesting of waterTesting of water

• Record pH for each water sample;

• Record temperature from all tanks. It should be above 20ºC for each tank;

• If KCl is mixed in the water, test and record the KCl% for each water sample.

Fluid mixing and QA/QC testing proceduresFluid mixing and QA/QC testing proceduresFluid mixing and QA/QC testing proceduresFluid mixing and QA/QC testing procedures

• Add 200 ml fracturing tank water to a 1 liter Warring blender cup;

• Using syringes, measure out volumes of J590 and J589 necessary;

• Start blender spinning at low speed, add J590 and J589 **. Increase blender speed to 40% and blend for

2 minutes, increase blender speed to 70% and blend for 30 to 60 seconds;

• Stop blender, immediately start timer and slowly pour fluid between blender cup and sample cup.

Record the time it takes to form a lip. This time is the shear recovery time;

• The shear recovery time should be less than 10 sec;

• Report this time in the lab QA/QC report;

• Repeat for other water samples.

Note:Note:Note:Note: When adding the chemicals to the blender cup, one must ensure that chemicals do not contact the blender walls

or the center of the vortex. Chemicals contacting the blender cup wall and blade nut will not be completely mixed

into the solution and poor performance will result.

Proppant Settling Test ProcedureProppant Settling Test ProcedureProppant Settling Test ProcedureProppant Settling Test Procedure • Preheat a water bath to the minimum of BHST and 180 degF (82 degC). The water bath must be deep

enough to cover the 500 ml mark of a 500 ml graduated beaker;

• Prepare 500 ml of ClearFRAC XT fluid using the procedures outlined above;

• In separate containers, preheat the proppant and carrier fluid to the test temperature;

• Calculate the volume of RCP GV from equations below to make a total slurry volume of TV at a

proppant concentration of C PPA using the 500 ml of ClearFRAC XT fluid (carrier fluid);

( ) CSG

SGVV

G

GTCF +×

××=

34.8

34.8


34

( ) CSG

CVV

G

TG +×

××=

34.8

6667.1

Where:

CFV = Carrier fluid volume [ml];

GV = Bulk volume of proppant [ml];

TV = Total slurry volume [ml];

GSG = Specific gravity of proppant;

C = Proppant concentration [ppa].

• Add the proppant ( GV ) into the bottle containing the 500 ml of ClearFRAC XT fluid ( CFV );

• Cap the bottle and shake vigorously until the gravel is evenly dispersed;

• Pour the slurry into the graduated beaker to the 500 ml mark;

• Set the graduated beaker into the preheated water bath;

• Record the clear-fluid volume in ml in 1 to 5 minute intervals up to 60 minutes;

• After complete settling, remove the fluid (without proppant), cool to room temperature, and measure

shear recovery following the procedure below.

Shear Recovery Test ProcedureShear Recovery Test ProcedureShear Recovery Test ProcedureShear Recovery Test Procedure • Prepare of ClearFRAC XT fluid and expose to RCP as described above;

• Mix 200 ml of the remaining sample after rheology testing at 8000 rpm for 2 minutes;

• Stop mixing, and then pour the sheared fluid back and forth between the blender cup and a beaker. The

fluid should start regaining viscosity at around 10 to 15 seconds and recover completely (hang-lip) in

less than 25 seconds;

• If fluids take more than 25 seconds to recover completely (hang-lip) at room temperature, do not use the

fluid for treatment, it has failed the test.

ClearFRAC XT Crude Oil Compatibility Test ClearFRAC XT Crude Oil Compatibility Test ClearFRAC XT Crude Oil Compatibility Test ClearFRAC XT Crude Oil Compatibility Test When ClearFRAC XT fluids are mixed with some crude oils, an emulsion may form that can inhibit cleanup of the

formation and proppant pack. Therefore, before introducing ClearFRAC XT to a new field, compatibility testing

with a sample of the crude oil is essential.

Procedure to determine whether crude oil is compatible with ClearFRAC XTProcedure to determine whether crude oil is compatible with ClearFRAC XTProcedure to determine whether crude oil is compatible with ClearFRAC XTProcedure to determine whether crude oil is compatible with ClearFRAC XT

• Preheat the ClearFRAC XT fluid and crude oil in a water bath to the desired temperature;

• Mix 50 ml ClearFRAC XT fluid with 50 ml crude oil in a test bottle. Cap the bottle and shake vigorously for

30 seconds;

• Place the bottle in the preheated water bath and start the stopwatch;

• Record the volume of the bottom layer and the volume of emulsion at 5, 10, 15, 30, 45 and 60 minutes;

• Calculate the percentage of emulsion break using the following equation:

• 100____

_____% ×=

fluidXTClearFRACofVolume

layerbottomofVolumebreakEmulsion

• If the emulsion does not break (>90%) in 60 minutes, a pre-flush treatment using


35

• F105 or W054 is recommended.

Procedure to design treatment fluid composition and optimum crude oil/treatment fluid ratioProcedure to design treatment fluid composition and optimum crude oil/treatment fluid ratioProcedure to design treatment fluid composition and optimum crude oil/treatment fluid ratioProcedure to design treatment fluid composition and optimum crude oil/treatment fluid ratio

• Preheat ClearFRAC XT, crude oil and Pre-Flush fluid to the test temperature;

• Mix the crude and Pre-Flush fluid;

• Add ClearFRAC XT fluid;

• Place the mixture in a preheated water bath and watch for emulsion break;

• Record volume of bottom layer fluid at BHST:

100______

_____% ×

+=

fluidtreatmentofVolumeXTClearFRACofVolume

layerbottomofVolumebreakEmulsion

• The volume of treatment fluid required for the job can now be calculated. Select the most effective

crude oil/treatment fluid ratio (if, for example, the best Treatment Fluid Vol% is 20%, then the volume of

treatment fluid to be pumped during the job is 20% of the ClearFRAC XT pad volume).

ClearFRAC XT Fluid Viscosity Breaking Testing ProcedureClearFRAC XT Fluid Viscosity Breaking Testing ProcedureClearFRAC XT Fluid Viscosity Breaking Testing ProcedureClearFRAC XT Fluid Viscosity Breaking Testing Procedure The purpose of this test is to determine the effect of breaker on the viscosity of the carrying fluid with the focus

on the integrity of the coating. The procedure covers the preparation and viscosity measurement of the fluid with

and without breaker.

Procedure for FannProcedure for FannProcedure for FannProcedure for Fann 35 viscometer 35 viscometer 35 viscometer 35 viscometer

• Place the fluid in a capped bottle;

• Add the J567 breaker into the fluid and slowly shake and swirl until the breaker is evenly distributed in

the mixture;

• Place the capped bottle in a water bath at the BHST of the well to be treated. If the BHST is higher than

180 degF (82 degC), then 180 degF (82 degC) is the temperature used ;

• Wait for about 30 minutes and then measure the viscosity of the fluid with the Fann 35 at 100 rpm (170s-1

).


36

12.12.12.12. Screen Out Contingencies Screen Out Contingencies Screen Out Contingencies Screen Out Contingencies

The best preventative measure to avoid a screenout is to design the fracture stimulations treatments

conservatively. The flow chart below details the process in the event of a fracture stimulation treatment

screenout. A detailed summary is provided below of events (A) through (G) is provided on the following pages.


37

12.1.12.1.12.1.12.1. Frac Screens Out (A)Frac Screens Out (A)Frac Screens Out (A)Frac Screens Out (A)

In the event of a screenout, the immediate step is to flow the well back in a controlled environment (do not surge

the well). This will assist in immediately removing stimulation fluids from the formation, remove proppant from

the wellbore and remove the upper ball from the wellbore (if already dropped).

At this point either the well has cleaned up and removed the stimulation fluid and proppant from the wellbore or

the well has stopped flowing leaving some stimulation fluid and proppant in the wellbore.

12.2.12.2.12.2.12.2. Wellbore Free of Proppant (B)Wellbore Free of Proppant (B)Wellbore Free of Proppant (B)Wellbore Free of Proppant (B)

In this scenario the fracture stimulation treatment screens out and the well is immediately flowed back. The well

cleans up the proppant and stimulation fluid left in the wellbore leaving the well relatively full of hydrocarbons.

Even though the well cleans up, it is still possible for a solids bed of proppant to lie on the low side of the

wellbore in horizontal wells. This proppant may be enough to prevent the top ball from reaching the seat to shift

the FracPort open. In addition, even if we are able to pump the top ball to the seat and shift the FracPort open,

any proppant in the wellbore will be collected in the viscous pad fluid as we pump the pad down the wellbore.

All of this proppant will now reach the formation at the start of the pad stage. This could result in immediate

screenout and/or diversion of frac from best areas of reservoir. In the worst case, this stage of the wellbore will

not be fracture stimulated. Therefore, it is recommended to treat the wellbore as if proppant is still in the

wellbore.

However, there may be situations where considerable time, effort and cost (e.g. offshore rig) will be required to

mobilize a coiled tubing unit to clean the proppant out of the well. In these instances, the operator may prefer to

assume the wellbore is free of proppant and continue. If this is the case, the operator must be made aware of

the concerns noted above and that in the worst case the stage may not be fracture stimulated.

At this point a decision must be made to either move forward assuming there is no proppant in the wellbore or to

move forward assuming there is a proppant bed on the low side in the horizontal section of the wellbore.


38

12.3.12.3.12.3.12.3. Frac Next Stage (C)Frac Next Stage (C)Frac Next Stage (C)Frac Next Stage (C)

In this scenario the well is free of stimulation fluid and proppant. If the top ball either was not dropped when the

well screened out or flowed out of the well, there will be no top ball in the wellbore. If the top ball was dropped

prior to screen out, there is a possibility it may not come out while cleaning the well up. In either scenario, the

operations below are valid as having two top balls of the same size in the wellbore will not affect the operation.

• Drop another top ball required to open the desired FracPort regardless if the same sized ball is already

in the wellbore.

• Let the ball gravity drop into the horizontal section of the wellbore (minimum one hour).

• Start pumping pad fluid into the well at matrix rates (generally two to five BPM) displacing the ball to the

desired FracPort. Displacing the ball to the FracPort will require pushing fluids in the wellbore into the

previously fracture stimulated zone. Pumping at matrix rates will prevent the proppant in the previously

stimulated stage from moving.

• When the ball reaches the seat of the FracPort, pressure up and shift the sleeve open.

• Resume pumping the fracture stimulation treatment as per program.

12.4.12.4.12.4.12.4. Proppant in Wellbore (D)Proppant in Wellbore (D)Proppant in Wellbore (D)Proppant in Wellbore (D)

In this scenario there is proppant and/or stimulation fluid in the wellbore because either well stopped during

cleanup or there is a proppant bed on the low side in the horizontal section of the wellbore.

At this point either two scenarios are possible depending on whether the top ball is in the wellbore or not in the

wellbore. The top ball is in the wellbore if it was dropped prior to screenout and did not flow out of the well

during cleanup. The top ball is not in the wellbore if either the top ball was not dropped prior to screenout or

flowed out of the well during cleanup.


39

12.5.12.5.12.5.12.5. Push Top Ball to Seat (E)Push Top Ball to Seat (E)Push Top Ball to Seat (E)Push Top Ball to Seat (E)

In this scenario there is proppant and/or stimulation fluid in the wellbore and the top ball is also in the wellbore.

Coiled tubing is required to both clean the proppant and/or stimulation fluid out of the wellbore and push the ball

to the seat of the FracPort. The coiled tubing bottomhole assembly to both wash and push the top ball is found

under “Coiled Tubing Design – Push Top Ball to Seat”. Follow best practices for cleaning proppant out of the

wellbore.

12.6.12.6.12.6.12.6. FracPort Shifts Open (F)FracPort Shifts Open (F)FracPort Shifts Open (F)FracPort Shifts Open (F)

In this scenario coiled tubing has been used to wash proppant from the wellbore and push the top ball onto the

seat of the FracPort. The following steps are recommended to shift the FracPort open:

• With the top ball pushed to the desired seat ensure all remaining proppant is removed from the

wellbore.

• Pull up and re-tag the ball with the coiled tubing while pumping to ensure the restriction in the wellbore

is the seat of the FracPort and not a proppant bridge.

• Stop pumping down the coiled tubing and shut in the coiled tubing return line on surface in preparation

of pressuring up the wellbore.

• Push the top ball onto the seat of the FracPort and pump down the coiled tubing to pressure up the

wellbore and shift the FracPort open.

At this point we will either be able to pressure up and shift the FracPort open or we will not be able to pressure

up due to the integrity of the top ball being compromised. The integrity may be compromised while pushing and

washing the top ball to the seat of the FracPort.


40

12.7.12.7.12.7.12.7. FracPort Open, Frac Well (G)FracPort Open, Frac Well (G)FracPort Open, Frac Well (G)FracPort Open, Frac Well (G)

In this scenario the top ball has been pushed with coiled tubing to the seat of the FracPort. We have pressured

up on the wellbore and shifted the FracPort open. The following steps are now recommended:

• Perform an injection test into the formation to confirm that the FracPort is open.

• With the FracPort open, open the coiled tubing return line keeping the well in pressure balance.

• Displace the well to a relatively non-damaging low viscosity fluid (e.g. brine) and pull out of hole with

the coiled tubing. While pulling out of hole, ensure a slight overbalance is maintained to prevent solids

from entering the wellbore from the formation.

• With the coiled tubing on surface, start pumping pad into well and resume fracture stimulation

treatment operations.

12.8.12.8.12.8.12.8. Drop Another Top Ball (H)Drop Another Top Ball (H)Drop Another Top Ball (H)Drop Another Top Ball (H)

In this scenario the top ball has been pushed with coiled tubing to the seat of the FracPort. However, we are

unable to pressure up the wellbore and shift the FracPort open. The following steps are recommended if the

FracPort does not open:

• Pull up and re-tag the ball with the coiled tubing and attempt to pressure up and shift the FracPort open

again.

• If unable to pressure up and shift the FracPort open, open the coiled tubing return line keeping the well

in pressure balance.




• With the coiled tubing on surface, drop another top ball required to open the desired FracPort

regardless if the same sized ball is already in the wellbore.








• If we are unable to pressure up and shift the FracPort open there is likely ball debris lodged in the

FracPort preventing the ball from seating. In this case there are two options:

• Run in hole with coiled tubing and a motor mill bottomhole assembly to mill out the debris in the seat.

The entire bottomhole assembly must be able to pass through the seat.

• Skip this stage a drop the next ball to fracture stimulate the next stage.

12.9.12.9.12.9.12.9. Coiled Tubing Wash (I)Coiled Tubing Wash (I)Coiled Tubing Wash (I)Coiled Tubing Wash (I)

In this scenario there is proppant and/or stimulation fluid in the wellbore because either well stopped during

cleanup or there is a proppant bed on the low side in the horizontal section of the wellbore. In addition, the top


41

ball is not in the wellbore as either the top ball was not dropped prior to screenout or flowed out of the well

during cleanup.

Coiled tubing is required to clean the proppant and/or stimulation fluid out of the wellbore. The recommended

coiled tubing bottomhole assembly to wash is found under “Coiled Tubing Design – Coiled Tubing Cleanout”.

Follow best practices for cleaning proppant out of the wellbore.

The following steps are recommended to resume the fracture stimulation treatment:

• Run in with coiled tubing and remove the proppant from the wellbore. If possible, clean the tubulars to

the bottom of the well. At minimum, the well must be cleaned out to smallest FracPort seat possible.




• With the coiled tubing on surface, drop a top ball required to open the desired FracPort.









42

13.13.13.13. CT Cleanout ProgramCT Cleanout ProgramCT Cleanout ProgramCT Cleanout Program

Post Frac Well Cleanout using Coiled TubingPost Frac Well Cleanout using Coiled TubingPost Frac Well Cleanout using Coiled TubingPost Frac Well Cleanout using Coiled Tubing

OperatorOperatorOperatorOperator :::: PETROM S.APETROM S.APETROM S.APETROM S.A WellWellWellWell :::: LV03LV03LV03LV03

Country : Romania Field : Levada West

Location : Rig : Jupiter

Prepared forPrepared forPrepared forPrepared for : : : : LocationLocationLocationLocation ::::

Date : 18-Jun-2008 Phone: :

Prepared by : Antonio Cevallos (CT & N2 Engineer)

Reviewed by : Giuseppe Ambrosi (Technical Engineer CT)

Revision No. : A.0

Phone : +39 334 6401114

E-Mail : [email protected]

Reviewed by Matthias Heil (GMTE CTS NCE)

Revision No. : 3

Phone : +49 4441 9530

E-Mail : [email protected]


43

OBJECTIVEOBJECTIVEOBJECTIVEOBJECTIVE

� Post Frac well cleanout with Coiled Tubing using a jetting nozzle BHA for the proppant

cleanout and an Impact-Hammer assembly for removal of the StageFRAC balls if required.

SCOPESCOPESCOPESCOPE

� Client is fully aware of all the risk involved on this operation, a HARC with all prevention and

mitigation measures on place must be done and completely comprehended by the client.

� To avoid settling of the fill particles the fluid must be kept in movement at the designed pump

rates at all times during the cleanout.

� We will perform frequently pull tests for confirmation of free movement of the CT, and return

fluids at surface will be constantly monitored.

� Due to the higher rates which can be pumped through the jetting nozzle BHA Schlumberger

proposes to use this system as the main tool for the proppant cleanout. The Impact-Hammer

BHA will be prepared as a contingency in order to remove the StageFrac balls if required. The

plan is to clean out the well to the first StageFrac ball, then pull out of hole, change the BHA

and run in hole to destroy the first StageFrac ball. In order to avoid another BHA change back

to the PowerClean-Nozzle it can be evaluated if the Impact- Hammer BHA can be used to

clean out the well to the next StageFrac ball. Once the second ball is removed Schlumberger

proposed to change the BHA back to the Power Clean BHA to complete the cleanout if

necessary.

� Max CT depth is the 4 ½” Toe Circulating Sub with a 1” Seat for 1.25” Ceramic closing ball.

Depth: 2259 m MD

� As a contingency the well platform was checked to verify if CT can be rigged up on the

platform for a possible N2 lift job with CT in case the Jupiter Jack up needs to leave location

after the frac operation. The following is a summary of the findings:

a) The well is right on the edge of the platform. There is no way to tie down the

injector head at the back to provide stability for the CT rig up when the reel is

pulling during operation.

b)b)b)b) Only 1 crane can reach the wellhead. During the operation the crane can not be

unhooked. In case of contingency operations the crane can not be removed from

the injector head. The capacity of the crane is limited above the well. The capacity of the crane is limited above the well. The capacity of the crane is limited above the well. The capacity of the crane is limited above the well.

Minimum crane capacity required: 10 to for IH and BOP stack plus 5 to overpull

once the Injector Head is connected to countereffect the weight of the CT

hanging in the well to prevent the wellhead from buckling.Beacuse of the above

SLB suggests not to rig up CT on the platform. Total hookload required above Total hookload required above Total hookload required above Total hookload required above

Injector Head = 15 to!Injector Head = 15 to!Injector Head = 15 to!Injector Head = 15 to!


44

WELL INFORMATIONWELL INFORMATIONWELL INFORMATIONWELL INFORMATION

GENERAL INFORGENERAL INFORGENERAL INFORGENERAL INFORMATION ABOUT THE WELLMATION ABOUT THE WELLMATION ABOUT THE WELLMATION ABOUT THE WELL

Well: LV03LV03LV03LV03

Type of well Deviated producer wellDeviated producer wellDeviated producer wellDeviated producer well

Max. Deviation 87 deg87 deg87 deg87 deg

BHP 205 to 220 bar205 to 220 bar205 to 220 bar205 to 220 bar

BHST 90 deg C90 deg C90 deg C90 deg C

MPWP (Calculated) 180 bar/2570psi Category I (0 180 bar/2570psi Category I (0 180 bar/2570psi Category I (0 180 bar/2570psi Category I (0 –––– 3500 psi) 3500 psi) 3500 psi) 3500 psi)

Wellhead Work. Press 10,000 psi10,000 psi10,000 psi10,000 psi

Well Fluid Fluid after StageFrac (Brine , ClearFrac XT 4%)Fluid after StageFrac (Brine , ClearFrac XT 4%)Fluid after StageFrac (Brine , ClearFrac XT 4%)Fluid after StageFrac (Brine , ClearFrac XT 4%)

Minimum restriction 2.0” at FracPort Tool 22.0” at FracPort Tool 22.0” at FracPort Tool 22.0” at FracPort Tool 2

Deviated Hole YES

Treat Down TUBING

Tubing DataTubing DataTubing DataTubing Data

ODODODOD

(in)

WeightWeightWeightWeight

(lb/ft)

IDIDIDID

(in)

DepthDepthDepthDepth

(m)

3.500 13.0 2.750 1978.0

CasingCasingCasingCasing Data Data Data Data

ODODODOD

(in)

WeightWeightWeightWeight

(lb/ft)

IDIDIDID

(in)

DepthDepthDepthDepth

(m)

7.000 23.0 6.366 1978.0

4.500 11.6 4.000 2305.0


45

Hole SurveyHole SurveyHole SurveyHole Survey

MDMDMDMD

(m)

TVDTVDTVDTVD

(m)

Deviation Deviation Deviation Deviation

AngleAngleAngleAngle

(deg)

Deviation Deviation Deviation Deviation

Build RateBuild RateBuild RateBuild Rate

(deg/30m)

Azimuth Azimuth Azimuth Azimuth

AngleAngleAngleAngle

(deg)

Azimuth Azimuth Azimuth Azimuth

Build RateBuild RateBuild RateBuild Rate

(deg/30m)

Dogleg Dogleg Dogleg Dogleg

SeveritySeveritySeveritySeverity

(deg/30m)

0.0 0.0 0.0 0.0 41.0 0.0 0.0

450.0 450.0 0.0 0.0 41.0 0.0 0.0

500.0 500.0 0.0 0.0 41.0 0.0 0.0

510.0 510.0 1.2 3.5 41.0 0.0 3.5

540.0 540.0 4.7 3.5 41.0 0.0 3.5

570.0 569.8 8.2 3.5 41.0 0.0 3.5

600.0 599.3 11.7 3.5 41.0 0.0 3.5

630.0 628.5 15.2 3.5 41.0 0.0 3.5

660.0 657.2 18.7 3.5 41.0 0.0 3.5

690.0 685.3 22.2 3.5 41.0 0.0 3.5

702.5 696.8 23.6 3.5 41.0 0.0 3.5

924.3 900.0 23.6 0.0 41.0 0.0 0.0

1142.6 1100.0 23.6 0.0 41.0 0.0 0.0

1678.9 1591.5 23.6 0.0 41.0 0.0 0.0

1680.0 1592.4 23.8 3.7 41.0 -1.1 3.7

1710.0 1619.5 27.2 3.5 40.0 -1.0 3.5

1740.0 1645.7 30.7 3.5 39.3 -0.8 3.5

1770.0 1671.1 34.2 3.5 38.7 -0.6 3.5

1800.0 1695.3 37.7 3.5 38.1 -0.5 3.5

1830.0 1718.5 41.2 3.5 37.7 -0.4 3.5

1860.0 1740.5 44.7 3.5 37.3 -0.4 3.5

1890.0 1761.2 48.1 3.5 37.0 -0.3 3.5

1920.0 1780.5 51.6 3.5 36.7 -0.3 3.5

1928.0 1785.4 52.6 3.6 36.6 -0.3 3.6

1968.6 1810.0 52.6 0.0 36.6 0.0 0.0

1978.4 1816.0 52.6 0.0 36.6 0.0 0.0

1988.6 1822.2 52.6 0.0 36.6 0.0 0.0

2010.0 1834.9 54.9 3.2 35.9 -1.0 3.3

2040.0 1851.4 58.2 3.2 35.0 -0.9 3.3

2070.0 1866.5 61.4 3.2 34.1 -0.9 3.3

2099.9 1880.0 64.7 3.3 33.3 -0.8 3.3

2100.0 1880.1 64.7 3.0 33.3 0.0 3.0

2130.0 1892.1 67.9 3.3 33.3 0.0 3.3

2160.0 1902.6 71.2 3.3 33.3 0.0 3.3

2190.0 1911.4 74.5 3.3 33.3 0.0 3.3

2220.0 1918.7 77.7 3.3 33.3 0.0 3.3

2250.0 1924.2 81.0 3.3 33.3 -0.0 3.3

2280.0 1928.1 84.2 3.3 33.3 0.0 3.3

2305.8 1930.0 87.0 3.3 33.3 0.0 3.3


46

DESIGNDESIGNDESIGNDESIGN

TFM* (Tubing Forces Module)

The TFM analysis predicts the Coiled tubing stress behavior during the CT operation such us:

- Maximum allowed weight that can be applied to the BHA.

- CT Weight during the operation.

- Maximum stress in the CT during the operation.

13.1.13.1.13.1.13.1. Tubing Forces ResultsTubing Forces ResultsTubing Forces ResultsTubing Forces Results

Output Summary

Lockup Did Not OccurLockup Did Not OccurLockup Did Not OccurLockup Did Not Occur

Maximum Percent Yield = 25.29 %

Maximum Pickup Tension = 17335.93 lbf

Minimum Slackoff Tension = -2800.00 lbf

Maximum % Helical Buckling Load = 3.31 %

Available WOB Summary

Maximum Allowable WOB at TD = 2796.45 lbf

NOTE: Maximum Allowable WOB represents maximum WOB

before lockup occurs at TD of 2300m.

Maximum Allowable Pull = 30977.83 lbf

NOTE: Maximum Allowable Pull represents maximum pull before

reaching yield ratio of 80% with the BHA at TD of 2300m

Coiled Tubing DataCoiled Tubing DataCoiled Tubing DataCoiled Tubing Data

Length ft O.D. in

Thickness

in I.D. in

Wt/Length

lb/ft Volume bbl

Weight

lb

10901.80 1.50 0.175 1.15 2.48 14.01 27021.49

2735.00 1.50 0.194 1.12 2.66 3.33 7276.78


47

Fluid DataFluid DataFluid DataFluid Data

No flowing fluid effects.

Density of Fluid in CT = 8.5300 lb/gal

Density of Fluid in Well = 8.5300 lb/gal

Fluid Level in Well = 0.0000 ft

Well Head Pressure = 0.0000 psi

Coiled Tubing Circ. Pressure = 4000.0000 psi

0 250 500 750 1000 1250 1500 1750 2000 2250 2500

Measured Depth of Tool String - m

-5000

-2500

0

2500

5000

7500

10000

12500

15000

17500

20000

We

ight

In

dic

ato

r L

oa

d -

lbf

Pickup

Slackoff

Stripper Friction Load - 2500 lbfWell Head Pressure - 0 barsCoiled Tubing Circ. Pressure - 276 barsTensile Load on Tool at Max Depth - 0 lbfCompressiv e Load on Tool at Max Depth - 0 lbf

CoilCADE*

*Mark of Schlumberger

Coiled Tubing Weight Indicator Load

PETROM

LVO3

Cleanout_1_5inCT_SW_PC

05-10-2008

Figure 1. CT weight indicator load during the operationFigure 1. CT weight indicator load during the operationFigure 1. CT weight indicator load during the operationFigure 1. CT weight indicator load during the operation

The plot No. 1 shows the expected weight during the CT trip into the hole. The results show a weight of 17500 lbs

while the CT is pulled up from bottom depth (2300m). With CT at max depth a maximum of 2800lbf WOB can be

achieved and a total overpull at the tool of 31000lbf with a maximum yield of 80%.


48

Liquid CirculationLiquid CirculationLiquid CirculationLiquid Circulation

20 40 60 80 100 120 140 160 180 200 220 240 260

Liquid Rate - l/min

0

25

50

75

100

125

150

175

200

225

250

275

300

325

350

375

400

Circ

ula

tion

Pre

ssu

re -

ba

rs

1 Seawater

2 8.53

3 0.5

4 1.0%

Well Name - LVO3WHP - 27.58 barsCT Tool MD - 2000.00 mCT OD - 1.500 inCT Total Length - 4156.498 m

This plot can be used to determine the maximum circulation ratef or each liquid in order to remain within pressure limits of the CTand other equipment. Also, f or a giv en circulation rate, the liquidscan be compared to see which one giv es the lowest pressure.

*** To edit/erase text, double click on text to bring up edit box*** To mov e text box, drag with mouse

CoilCADE*


Design Aids - Liquid Circulation - Circulation Pres sure vs Liquid Rate for various Liquids

PETROM

LVO3

Cleanout_1_5inCT_SW_PC

05-10-2008

Figure 2. Circulation presFigure 2. Circulation presFigure 2. Circulation presFigure 2. Circulation pressure for different treatment fluidssure for different treatment fluidssure for different treatment fluidssure for different treatment fluids


Maximum recommended Pumping rate through the selected 1.5” CT string = 180 l/min at 300bar with Maximum recommended Pumping rate through the selected 1.5” CT string = 180 l/min at 300bar with Maximum recommended Pumping rate through the selected 1.5” CT string = 180 l/min at 300bar with Maximum recommended Pumping rate through the selected 1.5” CT string = 180 l/min at 300bar with

seawater.seawater.seawater.seawater.

PowerCLEAN* and Wellbore Simulator DesignPowerCLEAN* and Wellbore Simulator DesignPowerCLEAN* and Wellbore Simulator DesignPowerCLEAN* and Wellbore Simulator Design

Fill Properties:

20/40 or 16/20 Carbolite with tail of 16/2020/40 or 16/20 Carbolite with tail of 16/2020/40 or 16/20 Carbolite with tail of 16/2020/40 or 16/20 Carbolite with tail of 16/20 resin coated Carbolite; NOTE: The larger and heavier resin coated Carbolite; NOTE: The larger and heavier resin coated Carbolite; NOTE: The larger and heavier resin coated Carbolite; NOTE: The larger and heavier

16/20 proppant has been used for the simulations as worst case scenario.16/20 proppant has been used for the simulations as worst case scenario.16/20 proppant has been used for the simulations as worst case scenario.16/20 proppant has been used for the simulations as worst case scenario.

Particle Size..................................... 0.041 in

Particle specific gravity......................... 2.73

Fill top MD....................................... 1810.0 m

Fill bottom MD.................................... 2000.0 m

Job Design Parameters:

Wellhead Pressure During Cleanout................. 3.0 bars

Maximum CT Cleanout Speed......................... 15.0 m/min

Minimum CT Cleanout Speed......................... 1.5 m/min

Maximum Circulation Pressure...................... 300.0 bars

Maximum Bottom Hole Pressure...................... 220.0 bars

Max Solids Pick-up Concentration.................. 3.0 %


49

Fluid SelectionFluid SelectionFluid SelectionFluid Selection

The fluids selected for the cleanout are either KCl 2% or 3% or treated Seawater and ClearFrac gel at low

concentration ( 1%) as a viscous pill in order to keep the solids in suspension.

0 60 120 180 240 300 360 420 480

Treatment T ime - min

0

10

20

30

40

50

60

70

80

90

100

Per

cen

t - %

Percent Solids to Surface

Return Fluid Quality

Liquid Interface(s)

CoilCADE*


Wellbore Simulator - Percent Solids to Surface; Cle anout w ith Seawater and sweeps of 1% ClearFrac gel

PETROM

LVO3

Cleanout_1_5inCT_Clearfrac

05-10-2008

Figure 3. Percentage of solids at surface during cleanoutFigure 3. Percentage of solids at surface during cleanoutFigure 3. Percentage of solids at surface during cleanoutFigure 3. Percentage of solids at surface during cleanout


50

13.2.13.2.13.2.13.2. ProcedureProcedureProcedureProcedure

WELLBORE CLEANOUT WITH JETTING NOZZLE

1. Perform permit to work and hold a pre rig up safety meeting with C-man, CT crew and third party

companies. Discuss risks of the operation and review risks.

2. Spot surface equipment (CT unit, CT string 1 ½”).

3. Connect well adaptor 3 1/16” 10,000 psi x 4 1/16” 10k on frac-head and install Well Controll Stack for CAT

I Operations for returns taken through the wellhead. Note: Note: Note: Note: Verify the handling of the return fluids during

the cleanout (Seawater mixed with Clearfrac gel and proppant). The following options have been

discussed during the pre job planning:

a) Use the production piping connected to the side outlet on the wellhead, then flow the returns to the

production facility. (Normal procedure as during normal flowback)

b) Connect High Pressure Return line from side outlet on frac-head to rig choke. Then flow the returns

over the shaker into the rig tanks.

c) Connect High Pressure Return line from side outlet on frac-head to rig choke. Then flow the returns

over the shaker overboard

4. Function Test BOP rams (Test tobe monitored and authorized by Supervisor).

5. Perform function test injector head (chain movement and stripper).

6. Make sure the entire CTSI network is properly connected according to the layout in the cabin and

check if the acquisition is ok for all the sensors, including pump rate for fluid pump. Verify that load cell

locking nuts have been released and that the load cell is working properly.

7. Stab pipe and examine the first 5 - 10 feet of coiled tubing for distortion or damage. Cut off the offending

length and make up internal connector with 1-11/16” OD.

8. Install Pull/Pressure test plate at CT connector.

9. Pull test CT-Connector to 15,000 lbs.

Note: Check for moCheck for moCheck for moCheck for movement of CTC using a light file mark. Revement of CTC using a light file mark. Revement of CTC using a light file mark. Revement of CTC using a light file mark. Re----Tighten CTC.Tighten CTC.Tighten CTC.Tighten CTC.

10. Flush treating lines, well control stack and CT string with water and perform Line Pressure Test & PT1

as listed below under OOOOOOOOppppppppeeeeeeeerrrrrrrraaaaaaaatttttttt iiiiiiiinnnnnnnngggggggg PPPPPPPPrrrrrrrreeeeeeeessssssssssssssssuuuuuuuurrrrrrrreeeeeeee PPPPPPPPllllllllaaaaaaaannnnnnnnnnnnnnnniiiiiiiinnnnnnnngggggggg (as per WS Safety Standards 5 & 22).(as per WS Safety Standards 5 & 22).(as per WS Safety Standards 5 & 22).(as per WS Safety Standards 5 & 22). Test CT

string against CTC with Line Pressure Test Pressure. NOTE:NOTE:NOTE:NOTE: Check pressure test for installation of Frac-

Head. If pressure test against wellhead can be verified we test our stack against top valve on frac head.

If no pressure test for frac-head and riser connection can be verified we test against wellhead master

valve during PT1 (CT BOP Blind rams closed against close master valve, pumping through kill port on CT

BOP). NOTE: Check pressure test of return lines from wellhead to choke. If no pressure test to a min. of

expected MPWHP can be verified, include pressure test of these lines in Line Pressure Test.

OOOOOOOOppppppppeeeeeeeerrrrrrrraaaaaaaatttttttt iiiiiiiinnnnnnnngggggggg PPPPPPPPrrrrrrrreeeeeeeessssssssssssssssuuuuuuuurrrrrrrreeeeeeee PPPPPPPPllllllllaaaaaaaannnnnnnnnnnnnnnniiiiiiiinnnnnnnngggggggg (as per WS Safety Standards 5 & 22)(as per WS Safety Standards 5 & 22)(as per WS Safety Standards 5 & 22)(as per WS Safety Standards 5 & 22)

1.1.1.1. Line Pressure Test (Reel, Treating Line, CTC etc.): Line Pressure Test (Reel, Treating Line, CTC etc.): Line Pressure Test (Reel, Treating Line, CTC etc.): Line Pressure Test (Reel, Treating Line, CTC etc.): 400 bar400 bar400 bar400 bar

2.2.2.2. Maximum Potential Wellhead PresMaximum Potential Wellhead PresMaximum Potential Wellhead PresMaximum Potential Wellhead Pressure (MPWHP)sure (MPWHP)sure (MPWHP)sure (MPWHP) :::: 180 bar (2570psi)180 bar (2570psi)180 bar (2570psi)180 bar (2570psi)

3.3.3.3. CoilLimit Operating Pressure (collapse):CoilLimit Operating Pressure (collapse):CoilLimit Operating Pressure (collapse):CoilLimit Operating Pressure (collapse): 1100 bar1100 bar1100 bar1100 bar

4.4.4.4. Equipment Working Pressure (Wellhead/BOP):Equipment Working Pressure (Wellhead/BOP):Equipment Working Pressure (Wellhead/BOP):Equipment Working Pressure (Wellhead/BOP): 690 bar690 bar690 bar690 bar


51

5.5.5.5. Maximum Well Control Pressure (MWCP):Maximum Well Control Pressure (MWCP):Maximum Well Control Pressure (MWCP):Maximum Well Control Pressure (MWCP): 270 bar (3900 psi)270 bar (3900 psi)270 bar (3900 psi)270 bar (3900 psi)

6.6.6.6. Pressure Test for PT 1 (Blinds/BOP Body/Wellhead):Pressure Test for PT 1 (Blinds/BOP Body/Wellhead):Pressure Test for PT 1 (Blinds/BOP Body/Wellhead):Pressure Test for PT 1 (Blinds/BOP Body/Wellhead): 270 bar (270 bar (270 bar (270 bar (3900 psi)3900 psi)3900 psi)3900 psi)

7.7.7.7. Pressure Test for PT2 (Pipe’s, Check valve, Stripper):Pressure Test for PT2 (Pipe’s, Check valve, Stripper):Pressure Test for PT2 (Pipe’s, Check valve, Stripper):Pressure Test for PT2 (Pipe’s, Check valve, Stripper): 270 bar (3900 psi)270 bar (3900 psi)270 bar (3900 psi)270 bar (3900 psi)

Term Term Term Term DefinitionDefinitionDefinitionDefinition

Line Pressure Test All treating lines including the CT-Reel (CT string against

connector and pressure test plate and return lines.

Maximum Potential Highest wellhead pressure possible, given the

Wellhead Pressure reservoir pressure. This is reservoir pressure

(MPWHP) less the hydrostatic head of the reservoir

fluid, extending from the reservoir to the wellhead.

Maximum Well Control Maximum pressure for well control only.

Pressure (MWCP) This must be determined in advance, and may NOTNOTNOTNOT exceed

any of these thresholds:

• Category pressure limit + 1,500 psi

• PT-2 test pressure

• Working pressure of any equipment item

Low-Pressure Test (LPT) 300 psi to 500 psi applied pressure to verify correct

equipment assembly.

Pressure Test One (PT-1) Lesser of 1.5 times the MPWHP or the working

pressure of the lowest-rated component. (Lines, Body,

Blinds)

Pressure Test Two (PT-2): Lesser of PT-1 pressure, Coil LIMIT pipe-collapse

(Stripper, Pipes, CT, DFCV)

11. Release the pressure and make up CT BHA for Proppant Cleanout: 1 11/16” EZ connector, 1 11/16” MHA

and 1 11/16” jetting nozzle.

12. Lift the stack and connect to the BOP.

13. Correlate deth. NOTE:NOTE:NOTE:NOTE: Do not tag tDo not tag tDo not tag tDo not tag the stripper with the slim BHA.he stripper with the slim BHA.he stripper with the slim BHA.he stripper with the slim BHA. Apply paint mark on CT to prevent

pulling through stripper when coming out of hole. Have second mechnical counter set as another

reference to verify CT is above wellhead master valve. If in doubt follow MLA Procedure to POOH with

Slimline BHA which involves closing the master valve carefully to verify that the CT is above the valve.

14. Flush well control stack with water and perform pressure test PT-2 as listed above under OOOOOOOOppppppppeeeeeeeerrrrrrrraaaaaaaatttttttt iiiiiiiinnnnnnnngggggggg

PPPPPPPPrrrrrrrreeeeeeeessssssssssssssssuuuuuuuurrrrrrrreeeeeeee PPPPPPPPllllllllaaaaaaaannnnnnnnnnnnnnnniiiiiiiinnnnnnnngggggggg (as per WS Safety Standards 5(as per WS Safety Standards 5(as per WS Safety Standards 5(as per WS Safety Standards 5 & 22) & 22) & 22) & 22) ........ NNNNNNNNOOOOOOOOTTTTTTTTEEEEEEEE:: VVeerriiffyy tthhaatt wwee hhaavvee eennoouugghh rroooomm

bbeettwweeeenn cclloosseedd vvaallvvee oonn ffrraacc--hheeaadd aanndd PPiippee//SSlliipp rraammss ttoo aaccccoommmmooddaattee tthhee BBHHAA ffoorr PPTT 22.. DDoo nnoott ttaagg

tthhee vvaallvvee aanndd ddoo nnoott cclloossee tthhee BBOOPP aaccrroossss tthhee BBHHAA..

15. Equalize the pressure, open master and wing valve, start running in hole at 6 m/min until 50 mts (170 ft),

always pay attention to the weight indicator, then RIH maximum 20 m/min pumping brine at minimum

rate 50 l/min reducing RIH speed to 6m/min when going through restrictions. Perform pull test every 500

m for the first run. Verify that the well is full by monitoring the returns while RIH.

Note:::::::: EEEEEEEEsssssssstttttttt iiiiiiiimmmmmmmmaaaaaaaatttttttteeeeeeee TTTTTTTToooooooopppppppp ooooooooffffffff SSSSSSSSaaaaaaaannnnnnnndddddddd ((((((((TTTTTTTTOOOOOOOOSSSSSSSS)))))))) pppppppprrrrrrrr iiiiiiiioooooooorrrrrrrr ttttttttoooooooo rrrrrrrruuuuuuuunnnnnnnnnnnnnnnniiiiiiiinnnnnnnngggggggg iiiiiiiinnnnnnnn hhhhhhhhoooooooolllllllleeeeeeee ((((((((RRRRRRRRIIIIIIIIHHHHHHHH)))))))) ........ SSSSSSSSttttttttoooooooopppppppp CCCCCCCCTTTTTTTT aaaaaaaannnnnnnndddddddd ssssssssttttttttaaaaaaaarrrrrrrrtttttttt CCCCCCCClllllllleeeeeeeeaaaaaaaannnnnnnnoooooooouuuuuuuutttttttt aaaaaaaabbbbbbbboooooooouuuuuuuutttttttt

3333333300000000mmmmmmmm ((((((((111111110000000000000000fffffffftttttttt )))))))) aaaaaaaabbbbbbbboooooooovvvvvvvveeeeeeee TTTTTTTTOOOOOOOOSSSSSSSS........ DDDDDDDDoooooooo nnnnnnnnooooooootttttttt ttttttttaaaaaaaagggggggg tttttttthhhhhhhheeeeeeee ssssssssaaaaaaaannnnnnnndddddddd wwwwwwwwiiiiiiii tttttttthhhhhhhh tttttttthhhhhhhheeeeeeee nnnnnnnnoooooooozzzzzzzzzzzzzzzz lllllllleeeeeeee wwwwwwwwiiiiiiii tttttttthhhhhhhhoooooooouuuuuuuutttttttt ppppppppuuuuuuuu mmmmmmmmppppppppiiiiiiiinnnnnnnngggggggg........ ........


52

16. Once the CT is at 30m above TOS the pumping schedule below should be followed for the proppant

cleanout:

a. Penetrate Fill with maximum 2 m/min for 25m (75ft) pumping Seawater @ 180 l/min or max. 350

bar.

b. Stop CT and Circulate @ 180 l/min for 15 min

c. Contine to penetrate fill for the next bite of 25m with a maximum speed of 2m/min puming at

cleanout rate.

NOTE Important Considerations for Cleanout:NOTE Important Considerations for Cleanout:NOTE Important Considerations for Cleanout:NOTE Important Considerations for Cleanout:

• Never exceed cleanout speed of 2m/min while penetrating fillNever exceed cleanout speed of 2m/min while penetrating fillNever exceed cleanout speed of 2m/min while penetrating fillNever exceed cleanout speed of 2m/min while penetrating fill

• Never stop pumping during cleanoutNever stop pumping during cleanoutNever stop pumping during cleanoutNever stop pumping during cleanout

•• PPPPPPPPOOOOOOOOOOOOOOOOHHHHHHHH iiiiiiiimmmmmmmmmmmmmmmmeeeeeeeeddddddddiiiiiiiiaaaaaaaatttttttteeeeeeeellllllllyyyyyyyy iiiiiiiiffffffff cccccccclllllllleeeeeeeeaaaaaaaannnnnnnnoooooooouuuuuuuutttttttt ppppppppuuuuuuuummmmmmmmpppppppp rrrrrrrraaaaaaaa tttttttteeeeeeee ccccccccaaaaaaaannnnnnnn nnnnnnnnooooooootttttttt bbbbbbbbeeeeeeee mmmmmmmmaaaaaaaaiiiiiiiinnnnnnnnttttttttaaaaaaaaiiiiiiiinnnnnnnneeeeeeeedddddddd

• Max pump pressure 350 barMax pump pressure 350 barMax pump pressure 350 barMax pump pressure 350 bar

• Perform pull test at intervals of 100m during cleanoutPerform pull test at intervals of 100m during cleanoutPerform pull test at intervals of 100m during cleanoutPerform pull test at intervals of 100m during cleanout

• Have gel pills as per mixing instructions below ready in case the proppant does not Have gel pills as per mixing instructions below ready in case the proppant does not Have gel pills as per mixing instructions below ready in case the proppant does not Have gel pills as per mixing instructions below ready in case the proppant does not

return as expected.return as expected.return as expected.return as expected.

• Mix 1% (10gpt) Clearfrac Gel forMix 1% (10gpt) Clearfrac Gel forMix 1% (10gpt) Clearfrac Gel forMix 1% (10gpt) Clearfrac Gel for gel pills. Volume per pill = 10bbl (1.6m gel pills. Volume per pill = 10bbl (1.6m gel pills. Volume per pill = 10bbl (1.6m gel pills. Volume per pill = 10bbl (1.6m3333). The volume ). The volume ). The volume ). The volume

of J 590 and J589 need to be as per the table below.of J 590 and J589 need to be as per the table below.of J 590 and J589 need to be as per the table below.of J 590 and J589 need to be as per the table below.

i.i.i.i. 10 gal J 590/1000gal >> 4.2 gal J590/10bbl (16 liter J590/1.6m10 gal J 590/1000gal >> 4.2 gal J590/10bbl (16 liter J590/1.6m10 gal J 590/1000gal >> 4.2 gal J590/10bbl (16 liter J590/1.6m10 gal J 590/1000gal >> 4.2 gal J590/10bbl (16 liter J590/1.6m3333))))

ii.ii.ii.ii. 7.5 gal J589/1000gal >> 3.15 gal J589/10bbl (12 liter J589/1.6m7.5 gal J589/1000gal >> 3.15 gal J589/10bbl (12 liter J589/1.6m7.5 gal J589/1000gal >> 3.15 gal J589/10bbl (12 liter J589/1.6m7.5 gal J589/1000gal >> 3.15 gal J589/10bbl (12 liter J589/1.6m3333))))

17. Contine cleanout until hard tag on top StageFrac ball is reached.


53

18. Mark CT with paint at tagging depth.

19. POOH with a maximum of 10m/min until 1200m pumping @ 180 l/min or maximum of 350 bar.

20. At depth of 1200m stop CT, maintain cleanout rate and check that returns are free from solids before

continuing with next step.

21. Once returns are solid free reduce pumprate to 50 l/min and POOH with a safe speed. Ensure that the

well is kept full of fluid.

22. Once the CT is on surface shut in the well. NOTE:NOTE:NOTE:NOTE: Do not tag the stripper with the internall 1.69” OD

connector. Follow safe procedure to correlate depth and close wellhead.

23. Rig down Injector head and prepare BHA change.

WELLBORE CLEANOUT WITH Impact Hammer BHA (Removal of StageFrac Balls)WELLBORE CLEANOUT WITH Impact Hammer BHA (Removal of StageFrac Balls)WELLBORE CLEANOUT WITH Impact Hammer BHA (Removal of StageFrac Balls)WELLBORE CLEANOUT WITH Impact Hammer BHA (Removal of StageFrac Balls)

24. Perform permit to work and hold a safety meeting with C-man, CT crew and third party companies.

Discuss risks of the operation and review HARC. Document Safety Meeting on cabin report. Include

BHA function test in Safety Meeting.

25. Verify that CTC has not moved and is still in good condition. Check for abrasion on the CT string (to

about 10m above CTC).

26. Make up Impact Hammer BHA.

27. Perform and record pre job safety meeting for BHA test.

28. Function Test BHA (Set down BHA on wooden board and pump to activate the tool)

29.29.29.29. Make up IH and pressure test the broken connection at PT 2 test pressure against the closed master

valve on the wellhead by pumping through the reel as listed above under Operating Pressure Planning Operating Pressure Planning Operating Pressure Planning Operating Pressure Planning

(as per WS Safety Standards 5 & 22).(as per WS Safety Standards 5 & 22).(as per WS Safety Standards 5 & 22).(as per WS Safety Standards 5 & 22).

30. Correlate depth and update CCAT with new BHA length. NOTNOTNOTNOTE:E:E:E: Do not tag the stripper with the internal

1.69” OD connector.

31. Equalize pressure, open wellhead and RIH to tagging depth while pumping at minimum rate.. Reduce

speed at all restrictions. Monitor Returns and check for paint mark on CT. Note:Note:Note:Note: BHA length has

changed!

32. Once tagging depth has been reached increase pump rate to 160 l/min (max rate through 1.69” Roto

Hammer) and tag obstruction to activate hammer and remove the StageFrac balls.

Note: Adjust set down weight as per table below. Do not exceed 1500 Note: Adjust set down weight as per table below. Do not exceed 1500 Note: Adjust set down weight as per table below. Do not exceed 1500 Note: Adjust set down weight as per table below. Do not exceed 1500 lbs at the tool (WOB) lbs at the tool (WOB) lbs at the tool (WOB) lbs at the tool (WOB)

without checking with the office. The max set down at the BHA (WOB) is 1800lbs for the Roto without checking with the office. The max set down at the BHA (WOB) is 1800lbs for the Roto without checking with the office. The max set down at the BHA (WOB) is 1800lbs for the Roto without checking with the office. The max set down at the BHA (WOB) is 1800lbs for the Roto

Hammer Tool.Hammer Tool.Hammer Tool.Hammer Tool.


54

CT CT CT CT

depthdepthdepthdepth

Set Set Set Set

down down down down

weight weight weight weight

at at at at

depth. depth. depth. depth.

WOBWOBWOBWOB

Set down Set down Set down Set down

weigh at weigh at weigh at weigh at

surface. surface. surface. surface.

(Delta (Delta (Delta (Delta

Weight)Weight)Weight)Weight)

mmmm lbflbflbflbf lbflbflbflbf

2000 500 500

2000 1000 1000

2000 1500 1500

2000*2000*2000*2000* 1800180018001800 1800180018001800

2000 4000 7500

* Max

for tool

33. Work the Impact BHA on the obstruction as per the limits above and CoilLimit until the obstruction has

been removed. Check with office if no progress after a max of 10 attempts or 1 hr of working the

obstruction.

34. Once obstruction has been removed do not go deeper in the well! Pick up immediately and perform pull

test with CT with pumprate of 160 l/min and cirulate a gel pill (1% Clear Frac gel, Pill Volume 1m3).

35. Pass through obstruction several times after pulltest while the pill is circulated to surface

36. Review next step of the operation with company man and SLB engineering. Depending on the cleanout

performance the cleanout can be continued with the impact hammer BHA until the next StageFrac ball

is reached.

37. If sand cleanout is continued with Impact BHA the below pumping schedule should be followed for the

proppant cleanout:

a. Penetrate Fill with maximum 1.5 m/min for 15m (45ft) pumping Seawater or KCL brine @ 160

l/min or max. 350 bar.

b. Stop CT and Circulate 1.5m3 gel pill (1% ClearFrac) @ 160 l/min.

c. Continue to Circulate @ 160 l/min until gel has exited the nozzle (Reelvolume 2.8m3, Pill Volume

1.5m3, Total pump volume = 4.3m3, 27 min duration @ 160 l/min)

d. Contine to penetrate fill for the next bite of 15m with a maximum speed of 1.5m/min.

e. Check for hard tag on FracPort Tool at Stage 2.

NNNNNNNNOOOOOOOOTTTTTTTTEEEEEEEE IIIIIIIImmmmmmmmppppppppoooooooorrrrrrrrttttttttaaaaaaaannnnnnnntttttttt CCCCCCCCoooooooonnnnnnnnssssssssiiiiiiiiddddddddeeeeeeeerrrrrrrraaaaaaaatttttttt iiiiiiiioooooooonnnnnnnnssssssss ffffffffoooooooorrrrrrrr CCCCCCCClllllllleeeeeeeeaaaaaaaannnnnnnnoooooooouuuuuuuutttttttt ::::::::

•• NNNNNNNNeeeeeeeevvvvvvvveeeeeeeerrrrrrrr eeeeeeeexxxxxxxxcccccccceeeeeeeeeeeeeeeedddddddd cccccccclllllllleeeeeeeeaaaaaaaannnnnnnnoooooooouuuuuuuutttttttt ssssssssppppppppeeeeeeeeeeeeeeeedddddddd ooooooooffffffff 11111111........55555555 mmmmmmmm////////mmmmmmmmiiiiiiiinnnnnnnn wwwwwwwwiiiiiiii tttttttthhhhhhhh IIIIIIIImmmmmmmmppppppppaaaaaaaacccccccctttttttt HHHHHHHHaaaaaaaammmmmmmmmmmmmmmmeeeeeeeerrrrrrrr BBBBBBBBHHHHHHHHAAAAAAAA

•• NNNNNNNNeeeeeeeevvvvvvvveeeeeeeerrrrrrrr ssssssssttttttttoooooooopppppppp ppppppppuuuuuuuummmmmmmmppppppppiiiiiiiinnnnnnnngggggggg dddddddduuuuuuuurrrrrrrr iiiiiiiinnnnnnnngggggggg cccccccclllllllleeeeeeeeaaaaaaaannnnnnnnoooooooouuuuuuuutttttttt

•• PPPPPPPPOOOOOOOOOOOOOOOOHHHHHHHH iiiiiiiimmmmmmmmmmmmmmmmeeeeeeeeddddddddiiiiiiiiaaaaaaaatttttttteeeeeeeellllllllyyyyyyyy iiiiiiiiffffffff cccccccclllllllleeeeeeeeaaaaaaaannnnnnnnoooooooouuuuuuuutttttttt ppppppppuuuuuuuummmmmmmmpppppppp rrrrrrrraaaaaaaa tttttttteeeeeeee ccccccccaaaaaaaannnnnnnn nnnnnnnnooooooootttttttt bbbbbbbbeeeeeeee mmmmmmmmaaaaaaaaiiiiiiiinnnnnnnnttttttttaaaaaaaaiiiiiiiinnnnnnnneeeeeeeedddddddd


55

•• MMMMMMMMaaaaaaaaxxxxxxxx ppppppppuuuuuuuummmmmmmmpppppppp pppppppprrrrrrrreeeeeeeessssssssssssssssuuuuuuuurrrrrrrreeeeeeee 333333335555555500000000 bbbbbbbbaaaaaaaarrrrrrrr

•• PPPPPPPPeeeeeeeerrrrrrrrffffffffoooooooorrrrrrrrmmmmmmmm ppppppppuuuuuuuullllllll llllllll tttttttteeeeeeeesssssssstttttttt aaaaaaaatttttttt iiiiiiiinnnnnnnntttttttteeeeeeeerrrrrrrrvvvvvvvvaaaaaaaallllllllssssssss ooooooooffffffff 5555555500000000mmmmmmmm dddddddduuuuuuuurrrrrrrr iiiiiiiinnnnnnnngggggggg cccccccclllllllleeeeeeeeaaaaaaaannnnnnnnoooooooouuuuuuuutttttttt wwwwwwwwiiiiiiii tttttttthhhhhhhh IIIIIIIImmmmmmmmppppppppaaaaaaaacccccccctttttttt HHHHHHHHaaaaaaaammmmmmmmmmmmmmmmeeeeeeeerrrrrrrr BBBBBBBBHHHHHHHHAAAAAAAA

38. Remove Obstruction at FracPort Tool at Stage 2 using Impact Hammer operating procedure as listed

above.

39. Once Obstruction is removed check with company man and SLB engineering about next steps. Options

are to continue the cleanout with the Impact Hammer BHA or POOH and perform a finall sweep of the

well with the power clean BHA. NOTE:NOTE:NOTE:NOTE: Do not tag the stripper with the internal 1.69” OD connector.


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13.3.13.3.13.3.13.3. EquipmentEquipmentEquipmentEquipment

CT SURFACE EQUIPMENT

CLIENT:CLIENT:CLIENT:CLIENT: Petrom S.A WELL : LV03

DATE:DATE:DATE:DATE: 08-June-2008

COILED TUBING UNIT COILED TUBING UNIT COILED TUBING UNIT COILED TUBING UNIT DETAILSDETAILSDETAILSDETAILS UNIT NUMBERUNIT NUMBERUNIT NUMBERUNIT NUMBER

CT UNIT/ POWER PACK High Pressure Open Loop

INJECTOR HEAD 560,Max Pull: 60000 lb,

Max Snub: 20,000lb

BOP/Stripper Combi BOP 4 1/16 : 10000 psi Max,

Side Door Stripper

REEL/CT STRING

String 1.5” Tapered, HS 90; String # 15_13314;

4150m (0.175/0.190 WT) Transport from Vechta

(Germany)

TUS 07360

CONTROL CABIN

Pump Unit

Cement pump with two fluid ends. One with 5”

plungers (5000psi) and one with 3 ¾” plungers

(10000psi). Use 3 ¾” plungers for cleanout.

Second fluid end only suitable as contingency

in order to pull ct out of the well during

cleanout.

Wellhead Adapter 3 1/16” 10k x 4 1/16” 10k

Jetting BHA 1.69” OD

Impact Hammer BHA 1.69” Tool OD with 1.75” max bit OD


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13.4.13.4.13.4.13.4. Prevention and Mitigation Measures on LocationPrevention and Mitigation Measures on LocationPrevention and Mitigation Measures on LocationPrevention and Mitigation Measures on Location

Before handling chemicals, review the appropriate Material Safety Data Sheets (MSDS) regarding Personal

Protective Equipment (PPE) and handling procedures.

It is vital to have a good working knowledge of the following safety standards:

� Well Services Safety Standard 5 – Pressure Pumping

� Standard 18 – Chemical Hazard Communication (HAZCOM) and Material Handling

� Schlumberger Contingency Procedures for Coiled Tubing Operations (Appendix C), located in Well

Services Safety Standard 22 Coiled Tubing Safety Standard

� Well Services Safety Standard 22 Coiled Tubing Safety Standard Level One Training

Personnel SafetyPersonnel SafetyPersonnel SafetyPersonnel Safety

To ensure personnel safety:

• Follow the Schlumberger Well Services Safety Standard 22 Coiled Tubing Safety Standard

• Exercise proper stepping, handling, and lifting techniques to ensure personnel safety according to:

o OFS QHSE 17, Injury Prevention Standard

o OFS QHSE 13, Mechanical Lifting Standard

• Wear proper personal protective equipment (PPE), including safety glasses.

• For the personnel in charge of returnings, adecuate training, certifications and special PPE guidelines

should be followed

Environmental ConcernsEnvironmental ConcernsEnvironmental ConcernsEnvironmental Concerns

Refer to the appropriate Material Safety Data Sheets (MSDS) regarding the handling of chemicals and

their environmental impact.

Any chemical spill must be contained, cleaned up, and reported according to local procedures.

Dispose of chemical waste in an environmentally acceptable way and in accordance with local

regulations (the client in this case will decide how to dispose the fluids)


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14.14.14.14. Decision TreeDecision TreeDecision TreeDecision Tree In order to manage the changes and be prepared for any deviation from the initial program, a decision tree was

adopted that cover most of the possible incident and the different alternative.


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15.15.15.15. Appendix 1 Appendix 1 Appendix 1 Appendix 1 ---- Lab Testing Report Lab Testing Report Lab Testing Report Lab Testing Report

16.16.16.16. Appendix 2 Appendix 2 Appendix 2 Appendix 2 ---- Frac Design Stage 1 Frac Design Stage 1 Frac Design Stage 1 Frac Design Stage 1



StageFRAC With ClearFRAC XT - LV03 Operating Procedure 4544619 01[1]

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