ads 11h completion program rev-0

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ADS 11H COMPLETION PROGRAM

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Addax Petroleum Development (Nigeria) Ltd

ADS – 11H Completion Program

OML 123

0 July 24, 07 Draft Copy For Review EEI DS N/aRev Date Reason for Issue Orig. Chkd. Appr.

REVISION HISTORY

Prepared By: Ifediora Emmanuel

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TABLE OF CONTENTS

REVISION DETAIL TABLE..........................................................................................2

1.0 SIGNATURE/APPROVAL PAGE......................................................................3

2.0 INTRODUCTION...............................................................................................4

2.1 PREAMBLE..............................................................................................................4

2.2 PURPOSE................................................................................................................4

2.3 OBJECTIVE.............................................................................................................4

2.4 GENERAL INFORMATION......................................................................................5

3.0 CASING & CEMENTING INFORMATION.........................................................5

4.0 PROPOSED PRODUCTION INTERVAL..........................................................5

5.0 GENERAL OPERATIONAL INSTRUCTIONS...................................................6

6.0 PIPE RABITTING..............................................................................................7

7.0 GASLIFT MANDREL PLACEMENT..................................................................7

8.0 TUBULAR SPECIFICATIONS...........................................................................8

9.0 ON SITE OPERATIONAL RESPONSIBILITIES................................................8

10.0 HOLE CONDITIONING.....................................................................................9

11.0 7” LINER ASSEMBLY.....................................................................................10

12.0 3½” COMPLETION ASSEMBLY.....................................................................17

13.0 REFERENCE..................................................................................................25

14.0 ATTACHMENT................................................................................................26

REVISION DETAIL TABLERev. Details of Changes

0 Initial draft copy.


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1.0 SIGNATURE/APPROVAL PAGE

Action Name Area of Responsibility

Signature Date

Prepared By:Ifediora Emmanuel

Snr. Completion Engineer

Reviewed By:

Guus NobbenhuisJohn Lowder

Drilling Superintendents

Richard KnoxHead, Drilling Engineering

Approved By:

Amarquaye Martey Deputy Asset Manager, OML 123

Horace B. Awi Drilling Manager

Emmanuel Ukegbu Production Manager

Monday OtaborDeputy GM Asset Management


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2.0 INTRODUCTION

2.1 PREAMBLE

The well Adanga South 11H was spudded from slot “B1a” in EBUGHU North East PP with the 36” conductor pipe driven to 384 ft md. The ADS 11H producer is contingent on the ADS 11P1 appraisal result. It is planned to produce oil from the P5.2 reservoir in the southern part of Adanga South Block A structure. A dual bore (splitter) starter head technology will be used. The wellhead consists of Drill-Quip Dual Bore Starter Head and Unitized 13⅝” 5M, 2 step wellhead housing for landing 9⅝” casing and the 3½” tubing hangers.

2.2 PURPOSE

The purpose of this document is to present a detailed procedure for completing Adanga South 11H well to achieve its primary objective.

2.3 OBJECTIVE

The objective of this proposal is to optimally complete ADS-11H as a single string oil producer in the P-5.2 reservoir of the Adanga South A block and to complete the horizontal section with minimum formation damage.

A 7" pre-drilled liner assembly will be run in the open hole section and blank liner overlapping inside 9⅝” casing to about 55 degrees (6,400ft md) using Baker model “SC-1R” packer assembly. The blank sections of the liner will equally overlapped into the open hole with at least 40 ft. The lateral section will be cleaned with Organic solvents via the wash pipe to remove filter cakes.

In the event of a geological compartmentalization resulting in gas or water being traversed, zonal isolation would be required. The pre-drilled and blank 7” liner assembly will be run in the open hole section with Swell packer(s) placed for the zonal isolations. The assembly will be run with blank liner overlapping inside 9⅝” casing to about 55 degrees using Baker model “SC-1R” packer assembly.

After recovering SBM and displacing hole to Seawater, the lateral section will be displaced to organic (cal) acid and then the 9-5/8” casing section circulated clean with detergent.

The tubing string will be 3½” 9.3 ppf N-80 EUE tubing equipped with Baker Model TE-5 sub-surface safety valve (TE-5 SCSSSV), gas lift mandrels, Locator seal assembly and other well completion accessories. The end of the tubing (EOT) would be positioned between 2-5ft above the KOIV depth after landing the string. The knock out isolation valve will be broken with slick line tool afterwards.


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2.4 GENERAL INFORMATION

Well Name: Adanga South 11HTarget Name: ADS P-5.2 ReservoirTarget TVD: 6,175 ft-tvd Total Depth (MD): 9,193 ft Maximum Inclination: 90 deg Water Depth: 53 ft MSLRKB-MSL Elevation: 104 ftRKB-WH Elevation: 69.87 ft

3.0 CASING & CEMENTING INFORMATION

A 36” conductor pipe was driven from a slot B-1a, Ebughu East production platform to 433 ft-md. A 16” surface hole section was directionally drilled to 2,718ft-md (2,596 ft-tvd). The 13 ⅜” 68ppf N-80, BTC casing was cemented in place with 15.8ppg cement slurry.

The 12¼” build section was drilled horizontally and landed in the P-5.2 reservoir at 7,779ft-md (6,175 ft-tvd). A 9⅝” 47ppf N-80 BTC casing will be set at TD and cemented inside 13⅜” casing with 11.8ppg lead and 15.8ppg tail cement slurries.

From the 9⅝” casing shoe, an 8½” hole will be drilled with about 1,417 ft of lateral to TD at 9,193 ft-md maintaining TVD of 6,175 ft-tvd) in the P-5.2 reservoir.

The 7" 23ppf K-55 BTC pre-drilled liner will be run in the open hole section to TD with 7" 29ppf K-55 BTC blank liner overlapped in the 9⅝” casing to at most 74 degrees. The liner assembly will be hung off using Baker model “SC-1R” packer assembly. As a contingency, the 7” pre-drilled/blank liners and Swell Packer(s) will be spaced out such as to provide required isolation in the 8½” hole.

Note: - The blank liner in the 9-⅝” casing section will be overlapped into the open hole section with a minimum of 1 joint to reduce shock around the casing shoe due to production.- Final liners (pre-drilled & Blank) and Swell Packer (if required) placements will be determined after drilling the lateral section.

4.0 PROPOSED PRODUCTION INTERVAL

Reservoir: P-5.2Interval: 7,776 – 9,193 ft-md (1,417 ft)TVD-RKB: 6,175 ftBHP: 2,200psia (0.3563psi/ft)BHT: 188degF


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5.0 GENERAL OPERATIONAL INSTRUCTIONS

NOTE: - This program is a work instruction. The line of COMMUNICATION with the rig will be via the Drilling Superintendent. The Drilling Manager and/or OML-123/124 Asset Manager shall approve any fundamental change prior to implementation.

Meetings should be conducted with relevant personnel considering following:

Introduction of key personnel.

Highlight every critical stage of the job.

Identify areas of possible failure and ensure adequate preventative steps

are taken.

Discuss on known hole conditions such as doglegs, tight spots, hole

angle, high drilling torques and any problems encountered while drilling.

Highlight consequences of any failure.

Ensure that all relevant personnel understand all processes / steps

required for each stage of the job.

Assign responsibility where possible and stress on accountability.

Ensure teamwork principle.

Establish and Pick up the required HWDP to provide enough weight to push the

liner to bottom. The DC and HWDP should be positioned immediately in the

vertical section of the hole at about 44 deg.

Rabbit all drill pipes on wiper trip before running liner. Prior to pulling out of the

hole on the last wiper trip, if a special wiper trip is made, i.e. hole opener/bull

nose run, drop 2.5” OD rabbit with 100ft of wire attached to enhance recovery

should it stick in a restricted joint.

Avoid drifting completion tubing while RIH, but where not avoidable, ensure one

drift is used at a time and should be seen prior to making up and running in hole

with any of the drifted joints – Do not use Teflon drifts. Use API steel drifts.

It is recommended that all the Liner joints, Tubing joints and completion

equipment be cleaned and drifted on the deck.

Ensure Addax Drilling Supervisor/Completion Engineer witness all drifting.


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All drift sizes used should be recorded and reported in the Daily completion

report.

Keep an accurate tubing tally. All lengths, IDs, coupling OD's and thread types

of all down hole completion items must be known and recorded. It is critical that

the tally is as accurate as possible.

Ensure hole is covered all the time to avoid working tools or any other item

dropping in the hole. In the event working tools or any other items drop in hole,

report type of fish that is lost in hole to the Addax Drilling Supervisor/Completion

Engineer

Ensure availability of equipment back-ups.

Ensure availability of completed and signed-off QA/QC data sheet and

checklists.

6.0 PIPE RABITTING

The purpose of this is to ensure that possible rust; debris is cleared off the pipe and to determine the minimum acceptable passage required for each pipe or assembly. The following pipes / tubing joints should be drifted with the minimum corresponding drift size.

Liner/DP/Tbg Minimum Drift Size Requirement7” Liner 6.059”Swell Packer 5.50”5” Drill pipe / HWDP 2.50”3½” Tubing 2.867”3⅛” Tubing Hanger 2.867”2⅞” Tubing (Wash pipe) 2.165”

Table: 17.0 GASLIFT MANDREL PLACEMENT

The Gas Lift Mandrels will be run with pre-installed Live and orifice valves as shown in the table below. The plan is to make up the mandrels onto pup joints and pressure test in town. Ensure that each GLM has been tested to at least 5,000psi before running in hole. This is to be confirmed with pressure test charts.

The Gas Lift Mandrels will be labeled at Weatherford with #1 mandrel as the first to run and #3 mandrel the last in hole. The Drilling Supervisor should check and ensure that mandrel labeling is correct and run accordingly. Also, the mandrels should carry the test values and dates of test.


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Number as Stenciled on GLM

MD (ft) TVD (ft) Inclination (deg)

Dummy

GLM #3 1,429 1,420 10 LiveGLM #2 2,184 2,144 25.52 LiveGLM #1 2,522 2,437 35.04 ORIFICE

Table: 2

8.0 TUBULAR SPECIFICATIONS

Size (in)

Wt (ppf)

Grade Thrd ID (in)

Drift (in)

Cap (bpf)

Coll (psi)

Burst (psi)

Yield (kips)

Coupl OD (in)

Recommended Make-up

2⅞ 8.7 N-80 PH-6

2.259 2.165 0.0058 15300 15000 180.3 3.500 3,000 ft-lb

3½ 9.3 N-80 EUE 2.992 2.867 0.0087 10530 10160 207 4.250 3,200 ft-lb

7

23 K-55 BTC 6.366 6.241 0.0394 3270 4360 366 7.656 Base of Triangle

29 N-80 BTC 6.184 6.059 0.0371 7020 8160 676 7.656 Base of Triangle

9⅝ 47 N-80 BTC 8.681 8.525 0.0732 4760 6870 1085 10.625Table: 3

9.0 ON SITE OPERATIONAL RESPONSIBILITIES

In the execution process of this program, responsibilities have been assigned as follows to avoid possible operational conflict:

Drilling Supervisor: Is the overall boss in-charge of the overall operation throughout the execution of this program. He oversees every aspect of this operation and supervises all the sub-supervisors. He will call for toolbox meeting on each of operational stage by involving every relevant personnel and delegate responsibility to sub-supervisors after clear understanding of the operation by all involved. He ensures that operators are working according to approved checklist.

Toolpusher / Driller: Running of the rig and completion tools as per instruction of the Drilling Supervisor and Sub-operational supervisors.

Baker Engineer: Is one of the main Sub-operational supervisors. He will supervise and be responsible for the making up and running of the Liner and Upper completion assemblies.


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He should ensure that the tallies and every other measurement are properly taken and recorded. At the end of well completion, he should ensure that a complete, correct and detailed well completion schematic (Field Copy) is delivered to the Drilling Supervisor before leaving the rig.

Baker Systems Engineer: Is also one of the Sub-operational supervisors

responsible for SCSSSV running and control line. He should inspect and report any damage on the control line while running. He should be present throughout the periods of running, and operating of the SCSSSV (closing and opening of the valve).

DrillQuip Engineer: Is another Sub-operational supervisor responsible for the making up of tubing hanger, landing hanger, landing off Xmas tree and testing same. He will be in-charge of running and pulling of Two-way check valve, and wear bushing. He will also work with the safety systems engineer in termination of the control line on the wellhead.

Geoservice’s Supervisor: Sub-operational supervisor responsible for slick line activities in testing the string integrity.

Mud Engineer: Is a Sub-operational supervisor responsible for proper preparation and composition of casing cleanout detergent and the packer fluid. He should ensure that pumping procedure is established.

Note: It is obligatory for all service providers to ensure that a copy of QA/QC data sheet and checklist signed-off with Addax QA/QC personnel in town is presented to the Drilling Supervisor prior to commencement of operation. Sections of the checklist that require further completion on the rig site will be signed off by the Drilling supervisor thereafter.

10.0 HOLE CONDITIONING

10.1 MU/RIH with hole clean out assembly (8½” hole opener / bull nose and 9⅝” casing scraper) in tandem.


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Note: ◙ Ensure the assembly is spaced out such that the casing scraper will run down about 85 degrees when the hole opener assembly would be at TD.

10.2 Condition mud (9.0-10.0ppg)/hole and scrape casing with the assembly and ascertain hole condition. Ensure that hole is adequately clean (circulate minimum 2.5 bottoms up). Report any losses in BPH and Total in the morning report.

10.3 POOH to 9-⅝” casing shoe. Pump sweep and circulate bottoms up at the shoe.Note: ◙ Ensure hole is cleaned of cuttings.

10.4 Continue POOH (without pumping).

10.5 L/D 8½” hole opener / 9⅝” casing scraper assembly.

10.6 Prepare to run Liner assembly. Rig up elevators and tongs.

11.0 7” LINER ASSEMBLY

11.1: PRIMARY CONCEPT

The plan in this concept is to run the pre-drilled liner in the lateral section with blank overlapping inside the 9-⅝” casing and hanging off with Baker model “SC-1R” packer assembly at about 74 degrees. A 1-7/16” Stainless Steel ball will be dropped and allowed to gravitate down to the ball seat at the bottom of the liner running tool. There will be 3 pressure setting stages, 1,800psi, 2,200psi and 2,500psi to set the packer. The ball seat will be sheared with + 15% of 3,872psi.

11.2 SECONDARY CONCEPT

This is a contingent approach to the above concept whereby zonal isolation will be required in the lateral section. In this case, one or two 6⅝” 24ppf L80 13% Cr base pipe Swell packer(s) spaced out with blank liners as required to provide isolation in the lateral open hole section will be run as part of the liner assembly. The assembly will be run and hung off inside 9⅝” casing with an overlap to about 74 degrees inclination using Baker model “SC-1R” packer assembly.

11.3 GENERAL OVERVIEW

In both scenarios, Baker model SC-1R type packer will be used to anchor the open hole assembly. SC-1R packer is a fully retrievable retainer production packer with a rotationally locked setting mechanism. Although this packer is primarily used for gravel pack applications, it may also be used as a standard completions packer where a retrievable retainer production packer is required. This will be run with an “SC” hydraulic setting tool. The purpose is to provide an effective sealing in the 9 ⅝” casing


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annulus and anchor the liner string in the hole. A 1-7/16” Stainless Steel ball will be dropped and allowed to gravitate down to the ball seat at the bottom of the liner running tool. There will be 3 pressure setting stages, 1800psi, 2200psi and 2500psi to set the packer. The ball seat will be sheared with + 15% of 3,872psi.

Note: ◙ In the event of losses, prior to setting the SC-1R packer, the ball seat with max. 8 shear screws rated at 484psi/screw for a shear value of 3,872psi may shear out at 3,491psi + 15%, i.e. between minimum of 2,967psi and maximum of 4,015psi. This is as a result of the overbalance of 381psi, created by the hydrostatic head of 10.0ppg drilling fluid over the reservoir pressure.

◙A back-up 1.75” Bakerlite ball is available in case the setting sequence of the packer is not completed with the primary ball. The backup ball seat cannot be sheared out and circulation can only be regained after reversing out the ball. Extra caution is necessary in reversing out the backup ball since reversing pressure can adversely affect the reservoir stability. PLEASE REVIEW SITUATION WITH TOWN (Drilling Superintendent) BEFORE DROPPING BACK UP BALL.

The Swell Packer is based on the swelling properties of rubber in hydrocarbons. Thermodynamic absorption expansion is continuous. The Swell Packer will swell to expand and seal the annulus around a pipe. It can be used in open or cased holes.

Special Note:

1. Remove Lamiflex protection without touching the rubber with knife rather

remove protection by pulling tape off by hand.

2. Drift the OD of the packer(s) with and OD gauge.

3. Avoid prolonged contact with base oil, diesel or other oil-based fluids. If packer

is exposed to any of the above fluids, wipe off with a cloth.

4. Make up with crossover pup joint for handling in town.

5. Swell packer start setting by swelling after 3 days in contact with SBM or diesel.


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11.4 7” LINER ASSEMBLY SCHEMATIC


PROPOSED WELL SCHEMATIC

2,200 psi 188deg F

9,193 6,175'

90 90 N/A

Addax 8.6ppg Inhibited Sea Water7" Pre-Drilled Liner

Emmanuel Ifediora 8-1/2" Open Hole 7,776' - 9,193' (1,417')

ADS 11 H CASING 9-5/8" 47 ppf N-80 BTC

Offshore NigeriaPRE-DRILLEDLINER

7" 23 ppf K-55 BTC

Tommy Craighead BLANK LINER 7" 26 PPFN-80 BTC

26-Jul-07 1 TUBING 2-7/8" 8.7 ppf N-80 PH-6

Ogbeide John

No. Depth LengthO.D. I.D. Description

17,200.0 5.08.4404.750Model SC-1R Packer, Size 96A4-47, with 7" BTC BoxDown

27,205.020.07.6256.184Retrieving Extension, Size 7" x 25 ft., with 7" BTC Pin x Pin37,225.0 1.57.6565.000Size 7" KnockOut Isolation Valve w/7" New Vam Box X Pin

47,226.5589.57.6566.276Blank Liner, Size 7", with 7" Buttress Box x Pin57,816.01361.07.6566.276Pre-Drilled Liner, Size 7", with (114) 3/8" Holes Per Foot, with 7"

Buttress Box x Pin69,177.015.07.6562.875Casing Pup, Size 7" w/ Insert Drillable Packoff Bushing f/

2.875" Polished Slick Stinger, BTC Box x Pin79,192.0 1.07.656 - - -Baker Cement filled Shoe, Size 7", with 7" Buttress Box Up9,193.0 End of Assembly

A 3.07.1302.500Model "SC" Hydraulic Setting Tool, Size 86, with 3-1/2" IF Box xB 3.06.0002.441 Hydro-Set Adapter Kit C 0.93.9002.441Crossover 3-1/2 CSHydril Box X 2-7/8 EU 8rd PinD 1.53.5002.441 Swivel Sub with 2-7/8 EU 8rd Box X PinE 1.03.3652.441X-Over 2-7/8 EU 8rd Box X 2-7/8 CS Hydril PinF 6.03.3652.441Pup Joint, Size 2-7/8" x 6 ft., with 2-7/8" Hydril CS Box x PinG As Required3.3652.4412-7/8 Pup Joints w/2-7/8 CS Hydril Box X PinH 1.03.9102.441Crossover 2-7/8" Hydril CS Box x 2-7/8 Hydril PH-6 PinI As Required3.3652.441Tubing, Size 2-7/8", with 2-7/8" PH-6 Box x PinJ 1.03.3652.441X-Over 2-7/8 Hydril PH-6 Box X 2-7/8 CS Hydril PinK 10.03.5002.441Polished Stinger, Size 2-7/8", 14 ft. Long, with 2-7/8 CS Hydril

Box Up

NOTES:

1)

2)3)

Address:6 Fatai Durosinmi Etti StreetVictoria Island AnnexLagos, Nigeria

SC-1R Packer and Pre-Drilled Liner Assembly

Rental Tool Assembly

MAX. DEVIATION ZONE DEVIATIONSAND SIZE

MD TVD INHIBITOR

BHP BHT

COMPLETION FLUID (WEIGHT AND TYPE) SCREEN SIZE

PERFORATIONS

SIZE WEIGHT GRADE THREAD

OPERATOR

COMPANY REP.

FIELD

RIG NAME

DATE

PREPARED BY

WELL NO.

COUNTRY

REVISionION NO.

SCREEN SIZE

PERFORATIONS

SCREEN SIZE

PERFORATIONS

SCREEN SIZE

PERFORATIONS

SCREEN SIZE

PERFORATIONS

Baker Nigeria Limited

6

7

H

I

J

K

A

1

2

B

3

C

D

4

5

E

F

G

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11.5 SUMMARY OF 7” LINER ASSEMBLY MAKE-UP

Assembly No.

No. In Drawing

Description

1 Figure-A(Items: 9 –

5)

Baker Size 7” Shoe with 7” Buttress Box up. Casing Pup Joint, Size 7” x 15 ft with 7” BTC Box x Pin. Size 7” x 2.875”, Drillable Pack-off Bushing. About 887 ft of 7” 29ppf N-80 BTC Predrilled Liner, with 7” BTC

Box x Pin. Optional: 6⅝” 24ppf 13% Cr BTC Swell Packer assembly* About 1,426 ft, 7” 29ppf N-80 BTC Blank Liner, with 7” BTC Box x

Pin.2 Figure-A

(Items: J – G)

Polished Slick Stinger, Size 2⅞” OD with 2⅞” CSH Box up. X-Over sub, size 2-7/8” PH-6 Hydrill Box x CSH pin. About 2500 ft of 2⅞” Wash Pipe, with 2⅞” 8.7ppf PH-6 Hydrill

Box x Pin. X-Over sub, size 2-7/8” CSH Box x PH-6 Hydrill pin Pup joints (as required to space out), 2⅞” CSH box x Pin.

3 Figure-A(Items: 4– 1)

Crossover sub, 5-1/2” LTC box x 7” BTC pin. Model “C” KOIV, size 7” LTC Box x Pin

4

(Items: F–A)

Crossover sub, 7-⅝” BTC box x 7” BTC pin. Mill out extension sub Size 7-⅝” x 20ft with 7-⅝” BTC box x Pin. Model “SC-1R” Gravel pack Packer assembly, size 96A4-60, max

O.D. of 8.44” with 6” bore for 9⅝” 43.5 - 47ppf casing. (Following sub-assemblies already made-up with packer in town);

Pup joint, size 2-7/8” CSH Box x pin. X-Over sub, size 2-7/8” EU 8rd box x 2-7/8” CSH pin. Swivel Sub, Size 4.5”, with 2⅞” EU 8rd Box x Pin. Model “BSCR” Hydro-Set Adapter kit, size 190-60, with 2-⅞”

EUE pin down. Model SC Hydraulic Setting Tool, size 86, w/3-½” IF Box up. Crossover Sub, with 4-½” IF Box x 3-½” IF Pin. 5” Drill Pipe pup joint with 4-½” IF Box x pin.

11.6 DETAILED PROCEDURE FOR RUNNING 7” LINER ASSEMBLY

11.6.1. Rig Up 7” liner running tools.

11.6.2. Hold pre-job safety meeting.

11.6.3. Pick up the Assembly No. 1 (Open Hole pre-drilled Liner) as per attached schematic.


Figure-A

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Note: *The swell packer is not part of the schematic, but will only be run should zonal isolation will be required, otherwise skip item. Swell packer placement will be advised by the Completion Engineer / Drilling Superintendent.

11.6.4. With the Open Hole 7" liner assembly (Assembly No.1) hanging in the rotary, rig up and run Assembly No. 2 (inner string concentric/wash pipe assembly) inside the liner assembly and sting into the drillable pack-off bushing.

Note: ◙ Make up the KOIV below the SC-1R packer assembly on the rig before running it because of the possibility of damaging the flapper with the inner string while transporting.

◙ ALL wash pipe connections across and below the KOIV sub MUST be either 2-⅞” CSH or PH-6.

◙ Set the concentric/wash pipe string in a 2⅞” Bowl and Slips on the false rotary table.

◙ Space out the wash pipe string so that the polish stinger is stung into the Drillable pack off bushing.

11.6.5. Pick up Assembly No. 3 (pre-assembled “SC-1R” packer assembly with the service tools already installed). The KOIV should have been made up to the packer assembly.

11.6.6. Make up the inner string to the pup joint stick out. Then make up the 7” Liner assembly to the “SC-1R” packer assembly. Break circulation and do not exceed 800psi.

11.6.7. After assembling the above horizontal liner assembly, pick up and RIH with 5” drill pipe, space out HWDPs at an inclination of 44 degrees to maximize the benefit of the HWDP continue RIH joints of 5’’ DPs to surface, and run in hole to TD at a rate of 1.5 minutes per 90’ stand. Dope slightly pin ends only.

Monitor the running (S/O) and pulling (P/U) weights and compare trend with the attached Multiple Drag Analysis. In case of rapid change to the predicted weights, work pipe by reciprocating gently while circulating bottoms up prior to landing assembly in the slips for connection (to free the friction).

The Drag analysis will be finalized after drilling the lateral section to TD and the result compared with the attached planned report. In case of any significant variance to the attached, a revised analysis report will therefore be forwarded to the rig.


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Note: ◙ Fill up drill pipe on the slips with fill-up hose. DO NOT fill pipe with TDS.◙ At the casing shoe, break circulation.◙ Prior to entering the open hole, record the BHA P/U & S/O weights.◙ During circulation, do not exceed 800psi surface pump pressure.◙ In case of restriction or tight spot, wash through restriction CBU, and

continue RIH. ◙ At TD record P/U and S/O weight.

11.6.8. Once at TD, RU surface equipment and test all lines to 5,000psi.

11.6.9. Space out with drill pipe pup joints if required to have surface connections close to rig floor.

11.6.10. Drop 1-7/16” Stainless Steel setting ball and allow about 30 minutes for ball to gravitate to seat.

11.6.11. With the ball seated on the ball seat, set Model “SC-1R” Gravel Pack Packer using the following steps:

A. Slowly pressure up to 1,800psi. Hold for 5 minutes and then bleed to 100psi.

B. Slowly pressure up to 2,200psi. Hold for 5 minutes and then bleed to 100psi

C. Slowly pressure up to 2,500psi. Hold for 5 minutes and then bleed to 100psi

◙ Please refer to notes under Section 11.3.

11.6.12. Verify Packer setting by pulling 30,000 lbs over pick-up. Set down 5,000 lbs, close the pipe rams and apply 1,500psi to annulus (backside) for 5 minutes. Bleed pressure to 0psi. If this test fails, repeat step 11.6.11 with 200psi pressure increments to 3100psi max.

Note: ◙ In case SC-1R packer test fails, Baker model ‘FH’ packer, for 9-5/8” 43.5 – 47ppf casing size on standby will be run as part of the 3-½” completion string.

11.6.13. As back up to release, holding slight up strain, rotate 12-15 turns to the right at the tool in order to release the service tools from the Liner assembly.

11.6.14. Slowly pick at the tool 2-3 ft to verify that the service tool has released from the packer.

11.6.15. With the seals off the sealing bore, pressure the work string +3,872psi to shear ball seat.


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Note: ◙ If a back-up ball was used to set the “SC-1R” Packer, PU service tools until the polished stinger is out of the pack off bushing to reverse out the ball.

Hole Cleaning and Lateral Section Displacement

11.6.16. Circulate bottoms up.

Note: ◙ Prior to displacement ensure preparations are made to achieve a continuous displacement process.

HSE ISSUES:◙ Chemicals should be handled carefully and safely. ◙ The appropriate personal protective equipment should be used to

prevent the probability of exposure to these solvents.◙ Perform safety meeting and ensure proper understanding of all

required safety procedures in handling the above solvents.◙ WW4002 is inflammable, please ensure application of inflammable

chemicals procedure handling.

11.6.17. With the slick stinger inside the pack-off bushing, pump 35bbls spacer, followed with 65bbls of Organic Solvent (WW4002) and 5bbls spacer behind. Prepare Spacer with HEC and CaCO3 to 0.5ppg above the density of the SBM.

11.6.18. Displace entire hole to 8.6ppg Seawater and recover SBM and Organic Solvent (WW4002). Monitor losses for 30mins and fill hole with Seawater as may require.

Note: ◙ Driller to make use of pump stroke count to estimate the time HEC pill will be on surface. Mud engineer to station at the flow line 30 minutes prior to the expected time verifying fluid rheology and provide adequate advise to the Driller.

11.6.19. Pump about 100bbls of Organic acid and displace to the lateral section with 8.6ppg Seawater. The acid is required to dissolve the calcium carbonate filter cake in the lateral section.

Note: ◙ Over displace acid as may be required ensuring that it contacted the heel section.◙ Be sure that there is adequate Seawater reserve prior to pumping organic acid.◙ Displace organic acid at maximum pump rate.◙ WW4002 and Organic acid will be pumped from a rented tank. ◙ Recalculate the volume of Organic acid based on run-in tally.


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11.6.20. Once displacement is completed, pull out of hole slowly with the service tools until they are completely out of the Liner assembly to avoid swabbing.

11.6.21. POOH with wash pipe (service tool) to about 2 joints below the KOIV at 1.5- 2mins per stand while monitoring losses and adequately filling up hole. Record rate of losses and cumulative in the report.

Casing Cleaning & Displacement to Packer Fluid (INHIBITED Seawater)

11.6.22. With work string about 2 joints below KOIV, kick-off pump and circulate below KOIV at 4bpm thoroughly before picking up pipe slowly through the KOIV. Stop 5 ft above the KOIV and observe well for losses. Start the pump and pick up string above the SC-1R packer.

Note: ◙ DO NOT tag KOIV with work string to avoid damage.

11.6.23. Pump 141bls of hole cleaning detergent solution (Seawater with 1% Dirt Magnet volume concentration).

11.6.24. Displace hole to 8.6ppg Inhibited Seawater (Packer Fluid).

Note: ◙ Seawater to be treated with 10 gals Tetra-Hib (corrosion inhibitor) per 100bbls and 5gals No-Oxygen (Oxygen Scavenger) per 100bbls.

◙ Observe the well for losses.

11.6.25. POOH and rack drill pipes, DCs, HWDPs. LD wash pipe and Baker service tools.

11.6.26. RU to run 3-½” tubing (upper completion string).

12.0 3½” COMPLETION ASSEMBLY

12.1 OVERVIEW

The well will be completed with 3½” 9.3ppf N-80 EUE 8rd tubing with tubing retrievable safety valve, Gas lift mandrels, Locator seal assembly and nipples installed.

12.2 SUMMARY OF 3 ½” TUBING UPPER COMPLETION ASSEMBLY MAKE-UP

Assembly No.

Nos. In Drawings

Description


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IFigure-B

(Items: 36 - 31)

Model A ratcheting mule shoe, size 190-47 with 3-1/2” EU 8rd Box up

Baker model “R” Seating Nipple, Size 3½” x 2.75 x 2.697”btm No-Go

Baker Flow Coupling 3½” 9.3ppf EUE 8rd Box x Pin. Baker model “S-22” Locator Seal, Size 190-60 with 10 ft seals

with 3½” 9.3ppf EUE 8rd Box x Pin. Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin.

II Figure-B(Items: 29 –

25)

Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin. Baker Flow Coupling 3½” 9.3ppf EUE 8rd. Baker model “F” Top No-Go Seating Nipple, Size 3½” x 2.75”. Baker Flow Coupling 3½” 9.3ppf EUE 8rd. Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin.

IIIFigure-B

(Items: 23 – 21)

Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin. GLM #1 with ORIFICE 3½” 9.3ppf EUE 8rd Box x Pin. Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin.

IVFigure-B

(Items: 19 – 17)

Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin. GLM #2 with LIVE 3½” 9.3ppf EUE 8rd Box x Pin. Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin.

VFigure-B

(Items: 15 – 13)

Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin. GLM #3 with LIVE 3½” 9.3ppf EUE 8rd Box x Pin. Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin.

VIFigure-B

(Items: 7 – 3)

Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin. Baker Flow Coupling 3½” 9.3ppf CSH Box x EUE 8rd Pin. Baker model “TE-5” Surface Controlled Subsurface Safety

Valve, 3½” x 2.81”with 3½” 9.3ppf CSH Box x Pin. Baker Flow Coupling 3½” 9.3ppf 3½” 9.3ppf CSH Pin x EUE 8rd

Box Pup joint of 3½” 9.3ppf EUE 8rd Box x Pin.

VII Figure-B(Items: 1)

Tubing Hanger


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12.3 UPPER COMPLETION SCHEMATIC


P R O P O S E D W E L L S C H E M A T I C

2 , 2 0 0 p s i 1 8 8 d e g F

9 , 1 9 3 f t 6 , 1 7 5 f t

9 0 d e g 9 0 d e g

A d d a x P e t D e v . N i g e r i a L t d 8 . 6 p p g I n h i b i t e d C a c l 2 7 " P r e - D r i l l e d L i n e r

E m m a I f e d i o r a 8 - 1 / 2 " O p e n H o l e 7 , 7 7 6 ' - 9 , 1 9 3 ' ( 1 , 4 1 7 f t )

A D S 1 1 H C A S I N G 9 - 5 / 8 " 4 7 p p f N - 8 0 B T C

N i g e r i a P R E - D R I L L E D 7 " 2 3 p p f N - 8 0 B T C

N o b l e T o m m y C r a i g h e a d B L A N K L I N E R 7 " 2 6 p p f N - 8 0 B T C

2 6 t h J u l y 2 0 0 7 1 T U B I N G 3 - 1 / 2 " 9 . 3 p p f N - 8 0 E U 8 r d

J o h n O g b e i d e S H T . S T R I N G

N o . D e p t h L e n g t h O . D . I . D . D e s c r i p t i o n

9 - 5 / 8 " x 3 - 1 / 2 " P r o d u c t i o n T u b i n g A s s e m b l y

0 . 0 0 0 6 9 . 9 E l e v a t i o n

1 6 9 . 9 2 . 0 2 . 9 9 2 T u b i n g H a n g e r , S i z e 3 - 1 / 2 " , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d P i n D o w n

2 7 1 . 9 2 1 7 . 2 4 . 5 0 0 2 . 9 9 2 7 J t s o f T u b i n g , S i z e 3 - 1 / 2 " , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n

3 2 8 9 . 1 6 . 0 4 . 5 0 0 2 . 9 9 2 P u p J o i n t , S i z e 3 - 1 / 2 " x 6 f t . , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n

4 2 9 5 . 1 6 . 0 4 . 5 0 0 2 . 9 9 2 F l o w C o u p l i n g , S i z e 3 - 1 / 2 " x 6 f t . , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x

3 - 1 / 2 " 9 . 3 p p f H y d r i l C S P i n

5 3 0 1 . 1 6 . 0 5 . 3 8 0 2 . 8 1 2 M o d e l " T E - 5 " S u r f a c e C o n t r o l l e d S u b s u r f a c e S a f e t y V a l v e , S i z e

3 - 1 / 2 " x 2 . 8 1 2 , w i t h 3 - 1 / 2 " 9 . 3 p p f H y d r i l C S B o x x P i n

6 3 0 7 . 1 6 . 0 4 . 5 0 0 2 . 9 9 2 F l o w C o u p l i n g , S i z e 3 - 1 / 2 " x 6 f t . , w i t h 3 - 1 / 2 " 9 . 3 p p f H y d r i l C S B o x x

3 - 1 / 2 " 9 . 3 p p f E U 8 r d P i n

7 3 1 3 . 1 6 . 0 4 . 5 0 0 2 . 9 9 2 P u p J o i n t , S i z e 3 - 1 / 2 " x 6 f t . , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n

8 3 1 9 . 1 1 1 0 3 . 9 4 . 5 0 0 2 . 9 9 2 3 5 J t s o f T u b i n g , S i z e 3 - 1 / 2 " , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n

9 1 4 2 3 . 0 6 . 0 4 . 5 0 0 2 . 9 9 2 P u p J o i n t , S i z e 3 - 1 / 2 " x 6 f t . , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n

1 0 1 4 2 9 . 0 4 . 0 5 . 5 0 0 2 . 9 3 7 S i d e P o c k e t G a s L i f t M a n d r e l , S i z e 3 - 1 / 2 " , # 1 w i t h L i v e V a l v e , w i t h

3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n ( # 3 L i v e )

1 1 1 4 3 3 . 0 6 . 0 4 . 5 0 0 2 . 9 9 2 P u p J o i n t , S i z e 3 - 1 / 2 " x 6 f t . , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n

1 2 1 4 3 9 . 0 7 3 9 . 0 4 . 5 0 0 2 . 9 9 2 2 4 J t s o f T u b i n g , S i z e 3 - 1 / 2 " , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n



3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n ( # 2 L i v e )


1 6 2 1 9 4 . 0 3 2 2 . 0 4 . 5 0 0 2 . 9 9 2 1 0 J t s o f T u b i n g , S i z e 3 - 1 / 2 " , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n



3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n ( # 1 O r i f i c e )


2 0 2 5 3 2 . 0 3 3 5 6 . 0 4 . 5 0 0 2 . 9 9 2 1 J t s o f T u b i n g , S i z e 3 - 1 / 2 " , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n


2 2 5 8 9 4 . 0 6 . 0 4 . 5 0 0 2 . 9 9 2 F l o w C o u p l i n g S i z e 3 - 1 / 2 X 6 ' w / 3 - 1 / 2 E U 8 r d B o x X P i n

2 3 5 9 0 0 . 0 2 . 0 4 . 5 0 0 2 . 7 5 0 M o d e l " F " T o p N o - G o S e a t i n g N i p p l e , S i z e 3 - 1 / 2 " x 2 . 7 5 0 , w i t h 3 - 1 / 2 "

9 . 3 p p f E U 8 r d B o x x P i n



2 6 5 9 1 4 . 0 1 2 7 9 . 0 4 . 5 0 0 2 . 9 9 2 4 1 J t s o f T u b i n g , S i z e 3 - 1 / 2 " , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n


2 8 7 1 9 9 . 0 1 . 0 6 . 2 5 0 3 . 0 0 0 M o d e l " S - 2 2 " L o c a t o r S e a l S u b , S i z e 1 9 0 - 6 0 , w i t h 3 - 1 / 2 " 9 . 3 p p f E U

8 r d B o x U p

2 9 7 2 0 0 . 0 1 3 . 0 6 . 0 0 0 3 . 0 0 0 M o d e l " S - 2 2 " S e a l A s s e m b l y , S i z e 1 9 0 - 6 0 , w i t h 1 0 f e e t o f S e a l s ,

w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d P i n D o w n

N O T E S :

1 )

2 )

3 )

A d d r e s s :P l o t 6 F a t a i D u r o s i n m i E t t i S tL a g o s N i g e r i aP h o n e : 4 6 1 9 0 8 1 - 5 M A X . D E V I A T I O N Z O N E D E V I A T I O N S A N D S I Z E

M D T V D I N H I B I T O R

B H P B H T

C O M P L E T I O N F L U I D ( W E I G H T A N D T Y P E ) S C R E E N S I Z E

P E R F O R A T I O N S

S I Z E W E I G H T G R A D E T H R E A D

O P E R A T O R

C O M P A N Y R E P .

F I E L D

S T A T E

R I G N A M E

D A T E

P R E P A R E D B Y

W E L L N O .

C O U N T R Y

R E V I S I O N N O .

S C R E E N S I Z E


S C R E E N S I Z E


S C R E E N S I Z E


S C R E E N S I Z E


B a k e r N i g e r i a L i m i t e d

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2 , 2 0 0 p s i 1 8 8 d e g F

9 , 1 9 3 f t 6 , 1 7 5 f t

9 0 d e g 9 0 d e g

A d d a x P e t D e v . N i g e r i a L t d 8 . 6 p p g I n h i b i t e d C a c l 2 7 " P r e - D r i l l e d L i n e r

E m m a I f e d i o r a 8 - 1 / 2 " O p e n H o l e 7 , 7 7 6 ' - 9 , 1 9 3 ' ( 1 , 4 1 7 f t )

A D S 1 1 H C A S I N G 9 - 5 / 8 " 4 7 p p f N - 8 0 B T C

L I N E R 7 " 2 3 p p f N - 8 0 B T C

N o b l e T o m m y C r a i g h e a d L G . S T R I N G 7 " 2 6 p p f N - 8 0 B T C

2 6 t h J u l y 2 0 0 7 1 C O N C . S T R I N G 3 - 1 / 2 " 9 . 3 p p f N - 8 0 E U 8 r d

J o h n O g b e i d e S H T . S T R I N G

N o . D e p t h L e n g t h O . D . I . D . D e s c r i p t i o n


3 1 7 2 1 7 . 8 1 . 3 4 . 5 0 0 2 . 6 9 7 M o d e l " R " B o t t o m N o - G o S e a t i n g N i p p l e , S i z e 3 - 1 / 2 " x 2 . 7 5 0 , w i t h

2 . 6 9 7 " N o - G o I D , w i t h 3 - 1 / 2 " 9 . 3 p p f E U 8 r d B o x x P i n


3 3 7 2 2 3 . 1 2 . 3 4 . 7 3 0 3 . 0 0 0 M o d e l " A " R a t c h e t i n g M u l e s h o e , S i z e 1 9 0 - 4 7 , w i t h 3 - 1 / 2 " 9 . 3 p p f E U

8 r d B o x U p x 1 / 2 M u l e s h o e

7 2 2 5 . 4 E O T

N O T E S :

1 )

2 )

3 )

A d d r e s s :P l o t 1 6 7 6 O l a d e l e O l a s h o r e S t .V i c t o r i a I s l a n d , L a g o s , N i g e r i a

P h o n e : 2 3 4 - 1 - 2 6 2 - 2 1 2 1M A X . D E V I A T I O N Z O N E D E V I A T I O N S A N D S I Z E

M D T V D I N H I B I T O R

B H P B H T

C O M P L E T I O N F L U I D ( W E I G H T A N D T Y P E ) S C R E E N S I Z E


S I Z E W E I G H T G R A D E T H R E A D

O P E R A T O R

C O M P A N Y R E P .

F I E L D

S T A T E

R I G N A M E

D A T E

P R E P A R E D B Y

W E L L N O .

C O U N T R Y

R E V I S I O N N O .

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12.4 UPPER COMPLETION RUNNING PROCEDURE

12.4.1. RU and recover Wear bushing

12.4.2. RU 3½” completion running tools.

12.4.3. Hold pre-job safety meeting

12.4.4. Pick up Assembly No. I (Guide shoe, Model “R” Seating Nipple and Locator Seal assembly) already made up in town.

Note: ◙ Ensure the length of the tailpipe measured from the Locator to EOT is 2-3ft less than that measured from SC-1R packer top to the KOIV flapper.

CONTINGENT: In case SC-1R packer was not positively tested, the contingent packer 9-⅝” x 3-½ ” “FH” packer will be made to the string at this point.

12.4.5. Continue running in hole with 3½” 9.3ppf EUE 8rd Tubing until sufficient depth has been reached to ensure the Baker Model “F” Seating Nipple set about 5,900 ft when landed.

12.4.6. Pick up and RIH with Assembly No. II (Model “F” Nipple assembly).

Tubing Integrity Test

12.4.7. RU slick line unit and pressure test lubricator to 2,500psi

12.4.8. Make a 2.72” gauge cutter run to the R-nipple. POOH with gauge cutter.

12.4.9. MU Tee connection on the tubing hanger landing joint with TIW valve installed.

12.4.10. RU surface lines to the tubing and annulus. Test lines to 2,500psi.

12.4.11. RU slick line unit and pressure test lubricator to 2,500psi.

12.4.12. Make up and RIH with RB-2 equalizing plug on slick line to test the string. Set plug in “R” seating nipple. Pressure test internally to 2,000psi for 30 minutes. Chart pressure reading. Bleed off pressure.

Note: ◙If the pressure drop is not more than 5% within 30 minutes (100psi) the test is then acceptable. If final test pressure is 1900psi, test is ok.


Figure-B

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12.4.13. Pick up on plug to shear the equalizing shear pins. Wait for 1-2 minutes for pressure to equalize across the valve before pulling free the RB-2 equalizing check valve.

12.4.14. POOH with RB-2 equalizing valve. RD slick line.

12.4.15. If leak is observed while performing step 12.4.12, POOH and fix leak, otherwise skip to step 12.4.16.

Gas Lift Mandrels Placement

12.4.16. Continue run 3½” 9.3ppf EUE 8rd Tubing until sufficient depth has been reached to ensure the Gas Lift Mandrel at depth as per engineering design.

12.4.17. RIH with Gas lift mandrels (Assembly Nos. III – VI) as per engineering design with 3½” 9.3ppf EUE 8rd Tubing joints as specified in Gas lift Mandrel section above. Set mandrels at the depths from rotary table as shown in table 2 (page 8) spacing out with tubing joints.

Surface Control Sub-Surface Safety Valve

12.4.18. Run 3½” 9.3ppf EUE 8rd Tubing until sufficient depth has been reached to ensure the Safety valve at depth +300’.

12.4.19. RU slick line unit and lubricator.

12.4.20. Make a 2.83” gauge cutter run to the F-nipple. POOH with gauge cutter. RD slickline and lubricator.

Note: ◙ The No go on the FB-2 is 2.802’’, therefore the tubing should be drifted with a gauge cutter higher than the no go. However, the 2.83’’ GC is bigger than the 2.81’’ Safety valve profile, hence the two-step drifting.

12.4.21. Pick up Assembly No. VII (Tubing Retrievable Safety Valve assembly) and make up control Line connection.

Note: ◙ Record the SCSSSV part number, nipple profile and confirm the valve is a TE-5 model. The part number of Baker “TE-5 SCSSSV is H824-83-2810.

12.4.22. Function test Safety valve 3 times and monitor Control Line returns.

Note: ◙ Control line must not have intermediate connections (DO NOT Splice Control line).


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12.4.23. RIH with Safety Valve assembly and maintain 5,000psi on Control Line to keep valve in the open position.

Note: ◙ Strap control line at three places on each joint (one below the box, one above and one halfway) with Baker safety system plastic straps.

◙ Ensure control line pressure is monitored on the SCSSSV while strapping and running in. Report number of straps installed.

◙ Position slips carefully to avoid crushing SCSSSV control line. Prior to running in hole after making-up, PU string and inspect control line for possible damage. In case of any observed damage control line, please pull and replace control line.

String Spacing out

12.4.24. Continue RIH with 3½” 9.3ppf EUE 8rd Tubing and locate into the SC-1R packer bore with Locator seal assembly

Note: ◙ The loss in string weight and flicking of the weight indicator is a good indication of the seals’ entrance into the packer Seal Bore.

◙ Ensure that the seals are actually inside the packer bore with the locator sub properly landed on top of the “SC-1R” Packer prior to spacing out of the tubing.

12.4.25. Space out string by calculating required pipe + length below Tubing Hanger for space out at Landing such that the locator will be placed about 1 ft above the packer. POOH excessive joints, install Space out joints (pup joints).

12.4.26. Prepare to MU tubing hanger.

Landing String Hanger in Unitized Wellhead after Spacing Out

12.4.27. P/U Assembly No. VIII (tubing hanger) and make up to string.

Note: ◙ Drill Quip Engineer to supervise Tubing Hanger operations according to Drill Quip procedures.

12.4.28. Wrap control line around hanger neck four times. Bleed off from control line. Connect ¼” NPT nipple with control line extension on top of hanger control line port. Flush port and connect control line below hanger. Pressure up to 5,000psi to open valve and to test connection for leaks. Keep SCSSSV open.

12.4.29. MU tubing hanger running tool and landing joint


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12.4.30. RIH to about 3’ below rotary table. Drain Stack. Land hanger and Lock hanger in place.

Tubing and Annulus Integrity Test

12.4.31. MU Tee connection on the tubing hanger landing joint with TIW valve installed.

12.4.32. RU surface lines to the tubing and annulus. Test lines to 2,500psi.

12.4.33. RU slick line unit and pressure test lubricator to 2,500psi.

12.4.34. Make a 2.83” drift cutter run to the Safety Valve. POOH with gauge cutter.

12.4.35. Make up and RIH with FB-2 equalizing plug on slick line to test the string. Set plug in “F” seating nipple. Pressure test internally to 2,000psi and hold pressure for 30 minutes. Chart pressure reading. Bleed off pressure.

Note: ◙If the pressure drop is less than 5% within 30 minutes the test is then acceptable.

12.4.36. While holding 2,000psi in the tubing, pressure up annulus and test, packer/seal assembly and hanger seals to 1,500psi. Hold pressure for 30 minutes. Monitor tubing pressure during test. Chart pressure readings. Bleed off pressure from annulus recording volume returned.

12.4.37. Pick up on plug to shear the equalizing shear pins. Wait for 1-2 minutes for pressure to equalize across the valve before pulling free the FB-2 equalizing check valve.

12.4.38. If leak is observed while pressure testing, check hanger seals and possibly POOH with tubing to Seal Assembly and fix leak, otherwise, skip and continue with step 12.4.39.

12.4.39. POOH with FB-2 plug and running tool. RD slick line.

Wellhead Handling (BOPs & Xmas Tree)

12.4.40. Close Sub surface safety valve (SCSSSV).

12.4.41. Remove the tubing hanger landing joint and lay down landing joint.

12.4.42. Install Two Way Check Valve on the hanger.

12.4.43. Nipple Down BOPs.


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12.4.44. Install single Drill-Quip Xmas tree - consisting of 2 master valves, 1 swab valve, 1 wing valve, actuated safety valve on the wing and choke box.

12.4.45. Test the tree void to 3,000psi and function test all the tree valves.

Note: ◙ Ensure that production representative witnesses all the tree tests.

12.4.46. Retrieve Two Way Check Valve.

12.4.47. Open SCSSSV and observe tubing pressure (if any). Close in well on X-mas tree master valves – open SCSSSV with 5,000psi, bled down pressure and maintain at 3,000psi.

Breaking of KOIV

12.4.48. Apply a pressure of 3,000psi in the completion string to break the KOIV. This would rupture the disc. The KOIV is at a high deviation.

Note: ◙ This should be performed with coil tubing in hole. If the KOIV cannot be broken by pressure as a result of sand on top the KOIV, CT should be run to wash off sand from the top of KOIV, then the KOIV would be broken with Hammer.

12.4.49. RU 1.5” CT and test CT. RIH to wash sand on top the KOIV. POOH.

12.4.50. MU 2.25” OD Tapered disc breaker x 2-1/8” Rotor Hammer, 2-1/8” Intensifier and Motor head assembly on CT.

12.4.51. Open well on X-mas tree and ensure that the SCSSSV is in Open position.

12.4.52. RIH with the Hammer BHA and tag the KOIV flapper recording drag every 1,000 ft.

12.4.53. Hammer down and break flapper of top KOIV. Tag bottom KOIV and break flapper.

12.4.54. POOH with hammer BHA and prepare to perform well cleanup.

12.4.55. Secure well on the X-mas tree.

12.4.56. Perform well clean up in line with clean up program.

Note: ◙The clean up program for this well will be provided by Production Technology and would be supervised by the Drilling Supervisor.


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12.4.57. Handover well to Production Department.

Note: ◙Ensure well is signed off to Production and copies of signed-off form sent to Drilling Superintendent, Asset team leader and completion Engineer.

12.4.58. Rig down and prepare to skid rig.

13.0 REFERENCE ADS 11H Drilling Program. ADS 11H Application to Drill Addax Drilling Manual.

14.0 ATTACHMENT

ADS 11H Liner Multiple Drag Analysis

Slack-Off Pick-UP

BHADepth

(Ft)

100 66147 67,750500 73,916 75,5781000 83,328 85,5451500 92,728 96,0462000 102,603 107,6832500 111,736 119,3923000 119,668 130,5533500 128,098 143,4704000 136,097 157,2054500 143,587 171,2845000 151,024 185,9045500 158,059 200,6266000 164,212 214,6706500 181,084 239,2677000 174,982 257,6097500 192,144 263,0928000 186,090 265,6438500 180,504 266,5629000 172,784 268,513


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9193 170,138 270,254

Torque and drag Analysis Chart. It shows Assembly was successfully run to bottom with an open hole friction factor of 0.25. There was no Buckling and lockup. This result will be verified with the actual pick up and slack off weights after the hole is drilled and during deployment


Axial

Sin

Hlx

S-O W/O Rotation Axial Drag

Axial Drag (lbf)

M.D. (ft)

0

-5000

-10000

-15000

0 50000 100000-50000-100000-150000-200000-250000

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API Tubing Running and Handling Procedure

NOTE: Addax recommends API modified thread compound for all 8 round connections like Weatherford Lube Seal.

1. The DSV to ensure that the tong operator use the correct make up torque before commencing the job.

2. All tubular connections shall be thoroughly cleaned and dried at the rig prior to running or inspection.

3. Drift the pipe with a clean, properly sized mandrel. If pipe is dirty inside, clean before drifting.

4. Thread protectors should always remain in place when moving or handling tubular.

5. By visual inspection ensure that all running equipment are available and in good condition.

6. Use slip type elevators. Ensure that the slips are of correct size to accommodate the size, weight and length of the tube.

7. Ensure that the safety clamp is of the correct size and in serviceable condition.NOTE: The safety clamp should be used above the table slips for the first 20 joints.

8. Check for traveling block alignment and rotary hole alignment.9. Ensure that the power tong snub line is at 90o and level with the tong.NOTE: Ensure that an accurate torque monitoring device (Martin-Decker torque gauge) is available, the load cell is for use in the require torque range, and the load cell has been calibrated within the past four (4) months.

10.Joints should be moved to the V-door via a crane.

11.Drift the pipe with a clean, properly sized mandrel. Use Elevators, single joint elevator to lift the joint up in the Derrick.

12.As each length is suspended vertically, remove the thread protectors and the drift, clean both pin and box connectors to be made-up.

13.Visually inspect to assure no damage to either connector has occurred.


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14.After the connection is clean and dry, apply a light, even coating of the thread compound to the pin connector.

15.Stab the pin connector into the box connector carefully to avoid damage to the connectors.

16. Back-up tongs should be placed below the coupling.

17.Position the power tongs approximately 7" above the coupling.

18.Before making up, back out the tubing until the threads jumps and are aligned. Make up the connection power-tight using a make-up speed between 5 and 14 RPM.

ADS 11H Well Completion Equipment List

Item No.

Descriptions Quantity Supplier Location Remarks

RIG1 5" DP (19.2 ppf, 5" OD, 4-1/2" IF connection) 135 joints HI9 rig On board HI92 5" HWDP (5" OD, with 4-1/2" IF Connection) 48 joints HI9 rig On board HI93 6 ¾” DC N/A HI9 rig On board HI93 4-1/2" IF box x 4-1/2" Reg. pin 1 HI9 rig On board HI94 4-1/2" IF pin x 4-1/2" Reg. pin 1 HI9 rig On board HI9

OTHERS1 7" Predrilled Liner 29# N-80 BTC 1,500 ft Addax Port Harcourt 400 ft excess2 7" Blank Liner, 29# N-80 BTC 1,000 ft Addax Calabar 1000 ft excess3 3-1/2" 9.3# EUE 8-rd Tubing 7,500 ft Addax Calabar 300 ft excess4 Tetra Hib (Corrosion Inhibitor) 135 gals BHI Port Harcourt 50% excess5 No-Oxygen (Oxygen Scavenger) 65 gals BHI Port Harcourt 50% excess6 Dirt Magnet 5 drums BHI Port Harcourt 50% excess7 8-1/2" Hole Opener with bull nose 1 AOS/Orwell Port Harcourt8 WW4002 (Organic Solvent) 80bbls Water wells Warri 20% excess9 Organic Acid 140bbls MI Port Harcourt 20% excess

10 Calcium Chloride (CaCl2) BHI Port Harcourt11 2-7/8" N-80 PH Tubing (Wash String) 2,900 ft Addax Calabar 150 ft excess12 9-5/8" Casing Scraper 1 Baker Port Harcourt13 8-1/2" PDC bit RR. 1 Addax On board TC

XMAS TREE1 Tubing Hanger: 13-5/8" x 11" x 3-1/2" EUE 2 Addax/DQ Calabar / Port Harcourt2 Tubing bonnet 2 Addax/DQ Calabar / Port Harcourt


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3 Complete Xmas Tree: 3-18" 5M Xmas tree made up of four (4) 3-1/2" 5M gate valves with two on the tree stem as lower and upper master valves, top valve acting as swab valve and one as wing valve, 3-1/8" 5M pneumatic actuated gate valve, 3-1/8" positive choke

2 Addax/DQ Calabar/Port Harcourt

Backup inclusive

4 Two Way check valve for 3-1/8" Hanger. 2 DQ Port Harcourt Backup inclusive5 BPV for 3-1/8" Hanger. 2 DQ Port Harcourt Backup inclusive6 Running Tools 2 DQ Port Harcourt Backup inclusive

9-5/8" Packer, Predrilled Liner and Wash pipe Assembly

1 Size 7” x 2.875”, Drillable Pack-off Bushing. 2 Baker Port Harcourt Backup inclusive

2 Size 9-5/8" x 6" Model "SC-1R" Packer with retrieving extension.

2 Baker Port Harcourt Backup inclusive

3 Blank Liner Pup Joint, Size 7" x 10 ft, with 7" BTC Box x Pin

2 Addax Port Harcourt Backup inclusive

4 KOIV size 7” x 5.0” ID with BTC conn. 2 Baker Port Harcourt 1 Backup inclusive

5 Baker Size 7" Shoe with 7" BTC Box 2 Baker Port Harcourt Backup inclusive6 Crossover Sub w/2-7/8" PH-6 Box x 2-7/8" CSH

Pin.2 Baker Port Harcourt Backup inclusive

7 Swivel with 2-⅞” with crossover, 2-⅞” EUE 8rd Box x CSH Pin

1 Baker Port Harcourt

8 Baker model BSCR Hydro-Set Adapter kit, size 190-60


9 Size 7" Model "SC" Setting Tool, size 86 2 Baker Port Harcourt Backup inclusive10 Spacer Joint (Mill out extension) 2 Baker Port Harcourt Backup inclusive11 SC-1R Packer retrieving tool 1 Baker Port Harcourt Contingent12 5" IF x 15' Drill Pipe Pup with Junk Bonnet 2 Baker Port Harcourt Backup inclusive13 Pup Joint, Size 2-⅞” with 2-⅞” CSH Box x Pin,

to extend below the packer.2 Baker Port Harcourt Backup inclusive

14 Set of Pup Joints, Size 2-⅞”, 2', 4', 6', 8', 10' Lengths, with 2-⅞” CSH Box x Pin, to space out inner string (with thread protectors)


15 Size 2-⅞” Slick stinger with 2-⅞” Hydril CS Box up


16 Primary Setting Ball, Size 1-7/16”, Stainless Steel


17 Back Up Setting Ball, Size 1-3/4", Bakelite 2 Baker Port Harcourt Backup inclusive18 Bowl and Slips, for 2-⅞” 1 Baker Port Harcourt19 Stripping Plate, for 7" Collar and 2-⅞” CSH "

Inner String1 Baker Port Harcourt

20 Metal Drift, Size 7", for 7" 29 ppf 1 BJ Port Harcourt21 Teflon Drift, Size 2-⅞” for 2-⅞” 8.7 ppf 1 BJ Port Harcourt

3-1/2" Completion Assembly

1 Baker model “S-22” Locator Seal, Size 190-47 with 10 ft seals with 3½” 9.3ppf EUE 8rd.



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2 Baker model "FH" Double grip single string hydrostatic set production packer, with 3-1/2" 9.3ppf EU 8rd Box x Pin

1 Baker Port Harcourt Contingent

3 Model "R" Bottom No-Go Seating Nipple, Size 3-1/2" x 2.750, with 2.697" No-Go ID, with 3-1/2" 9.3 ppf EU 8rd Box x Pin


4 Flow Coupling, Size 3-1/2" x 6 ft., with 3-1/2" 9.3 ppf EU 8rd Box x Pin (across Nipples)


5 Model "F" Top No-Go Seating Nipple, Size 3-1/2" x 2.750, with 3-1/2" 9.3 ppf EU 8rd Box x Pin


6 Flow Coupling, Size 3-1/2" x 6 ft., with 3-1/2" 9.3 ppf Hydril CS Box x 3-1/2" 9.3 ppf EU 8rd Pin


7 Model "TE-5" Surface Controlled Subsurface Safety Valve, Size 3-1/2" x 2.812, with 3-1/2" 9.3 ppf Hydril CS Box x Pin


8 Flow Coupling, Size 3-1/2" x 6 ft., with 3-1/2" 9.3 ppf EU 8rd Box x 3-1/2" 9.3ppf Hydril CS Pin


9 6 ft Pup Joint, Size 3-1/2", with 3-1/2" EUE 8rd Box x Pin, (for GLMs)

4 Addax Check stock

10 6 ft Pup Joint, Size 3-1/2", with 3-1/2" EUE 8rd Box x Pin, (for SCSSV, seal assy, R & F-Nipples)

6 Addax Check stock

11 Set of Pup Joints, Size 3-1/2", 2', 4', 6', 8', 10' Lengths, with 3-1/2" EUE Box x Pin, (for tubing space out)

1 Addax Check stock

12 Model A ratcheting mule shoe, size 190-47 with 3-1/2” EU 8rd Box up


12 Control Line, Size 1/4" x .049, 316L Stainless Steel, Spool of 400 ft.


13 Setting Ball, Size 2-1/2", Kirksite 2 Baker Port Harcourt Backup inclusive14 Control Line Stand 1 Baker Port Harcourt15 3-1/2" Teflon/steel drift 1 Baker Port Harcourt

7" Liner, 3-1/2" & 2-7/8" Tubular Running Equipment

1 7-5/8" Hydraulic Power Tongs complete with ancillary equipment and integrated hydraulic backup.

2 BJ Port Harcourt Backup inclusive

2 Hydraulic power units complete ancillary equipment

1 BJ Port Harcourt

3 350 Ton Varco spider complete 2 BJ Port Harcourt Backup inclusive4 Jaws & Dies for 7-5/8", 6-5/8’’ 5-1/2", 5", 4" & 2-

7/8"2 BJ Port Harcourt -Do-

5 Jaws & Dies for 7", 6-5/8’’, 3-1/2" & 2-7/8" 2 BJ Port Harcourt -Do-6 Lifting slings 2 sets BJ Port Harcourt -Do-7 Type J single Joint elevator for 3-1/2" tubing 1 BJ Port Harcourt8 Type J single Joint elevator for 6-5/8’’ & 7"

tubing2 BJ Port Harcourt Backup inclusive

9 150 Ton Side door elevator 2 BJ Port Harcourt -Do-


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10 75 Ton YC/YT Elevators 2 BJ Port Harcourt -Do-11 500T flush mounted spider 1 BJ Port Harcourt12 500T slip assembly and top guide for 7" 1 Set BJ Port Harcourt13 YC/MYC Slip assembly and top guide for 3-1/2" 1 Set BJ Port Harcourt14 Rotary hand Slip for 6-5/8’’ & 7" Liner 1 BJ Port Harcourt15 Rotary hand Slip for 3-1/2" Tubing 1 BJ Port Harcourt16 Safety Clamp for 7" Liner 2 BJ Port Harcourt Backup inclusive17 Safety Clamp for 3-1/2" Tubing 2 BJ Port Harcourt Backup inclusive18 Klepo Gun for 7" 6 BJ Port Harcourt19 Stabbing Guide for 3-1/2" 1 BJ Port Harcourt20 Metal Drift, Size 6-5/8’ 24# & 7", for 7" 29 ppf 1 BJ Port Harcourt21 Teflon Drift, Size 2-⅞” for 2-⅞” 8.7 ppf 1 BJ Port Harcourt22 7" Thread Protectors 6 BJ Port Harcourt

GASLIFT MANDREL1 Gas lift Mandrels with pre-installed Dummy

valves4 Weatherford Port Harcourt

SLICKLINE EQUIPMENT1 Slick line Unit 2 Geoservices Back-up inclusive2 Gauge Cutters (2.44” 2.50”, 2.72”, 2.76”, 2.83’’,

2.86’’)2 Geoservices Back-up inclusive

3 2.2” Tapered Tool 2 Geoservices Back-up inclusive

4 2.75” RB-2 Plug 2 Geoservices4 2.75” FB-2 Plug 2 Geoservices

5 2.75” plug redressing seals 1 Geoservices

6 Knuckle joints 2 Geoservices Back-up inclusive

7 1-7/8” Sinker Bars/Stems (2ft, 3ft, 5ft) 4 Geoservices Back-up inclusive

8 Jars 2 Geoservices Back-up inclusive

9 BOPs and Lubricator 1 Geoservices

CONTENGENT 1 6 ft 6-⅝” BTC box x 7” BTC box crossover pup 1 Addax Calabar Usage to be

advised2 6 ft 6-⅝” BTC box x 7” BTC pin crossover pup 1 Addax Calabar Usage to be

advised3 6-⅝” 24ppf 13% Cr BTC Swell Packer 1 Addax Calabar Usage to be

advised


ads 11h completion program rev-0

Documents