ALMagd C-86-C Drilling Program v1

Badr Petroleum Company

Well Engineering Department

AL Magd-C86-C Deviated/Appraisal -Development/Oil Producer Well

Drilling Program

APPROVALS

Indicator Signature

Prepared ODD/311

Reviewed ODD/2

Supported OD/1

DBE

BE

OD

Approved BO/1

BO

Distribution List:

Field: DSV EDC Rig 72, Tool Pusher EDC Rig 72, ODF

Cairo: ODD/2 Team, Sitra Team (2 x), Exploration (2 x), EGPC, Rig Manager EDC Rig 72

AL- Maged Drilling Program

Contents

1.0 Well Program Objectives....................................................................................4

1.1 WELL OBJECTIVE.................................................................................................................................. 41.2 BACKGROUND....................................................................................................................................... 41.3 GEOLOGICAL RISKS............................................................................................................................... 4

2.0 Well Design and Cost........................................................................................... 4

2.1 Well summary sheet…………………………………………………………………………………6

3.0 Well Engineering Technical Details....................................................................7

3.1 WELL ELEVATION................................................................................................................................. 73.2 OFFSET WELLS, TARGET DATA AND TD CRITERIA.................................................................................73.3 DRILLING RISKS.................................................................................................................................... 83.4 SURVEYING........................................................................................................................................... 93.5 CASING................................................................................................................................................. 93.6 WELL HEAD – WOOD GROUP (3-1/8” OIL SOLID BLOCK SYSTEM).......................................................103.7 BITS AND HYDRAULICS....................................................................................................................... 103.8 WELL EVALUATION / LOGGING........................................................................................................... 103.9 GEOLOGICAL SAMPLING...................................................................................................................... 103.10 FORMATION TOPS AND PRESSURES......................................................................................................11

4.0 Reporting and Documentation..........................................................................13

4.1 REPORTING......................................................................................................................................... 134.2 DOCUMENTATION................................................................................................................................ 13

5.0 HSE..................................................................................................................... 15

5.1 HEALTH.............................................................................................................................................. 155.2 SAFETY............................................................................................................................................... 155.3 ENVIRONMENT.................................................................................................................................... 15

6.0 Well Control Equipment and Procedures........................................................16

7.0 General Drilling Notes.......................................................................................17

8.0 Well Program Details........................................................................................19

8.1 17-½” SURFACE HOLE SECTION TO 1136 M AHBDF (TVDBDF).........................................................198.1.1 General....................................................................................................................................... 198.1.2 Drilling 17-½” Hole Section.......................................................................................................208.1.3 13-3/8” Casing Running & Cementing........................................................................................23

8.2 12-¼” INTERMEDIATE HOLE SECTION FROM 1136 TO 2506 M AHBDF.................................................278.2.1 General....................................................................................................................................... 278.2.2 Drilling 12-¼” Hole Section.......................................................................................................288.2.3 9-5/8” Casing Running & Cementing..........................................................................................30

8.3 8-½” MAIN HOLE (RESERVOIR) SECTION FROM 2506 M TO 3456 M AHBDF........................................348.3.1 General....................................................................................................................................... 348.3.2 Drilling 8-½” Hole Section......................................................................................................... 358.3.3 Log 8-½” Hole Section............................................................................................................... 378.3.4 7” Liner Running & Cementing..................................................................................................38

8.4 COMPLETIONS PROGRAM..................................................................................................................... 45

9.0 Risk Assessment.................................................................................................. 46

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This Page Intentionally Left Blank

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1Well Program Objectives

1.1 Well Objective

Appraise the lateral reservoir extension of the Abu Roash and Bahariya to the SE at up dip position.Test for a possible hydrocarbon accumulation in the Kharita up dip of the discovery well.Provide an oil drainage point for the Abu Roash & Bahariya for primary depletion & water flooding.

1.2 Background

The AESW C86 discovery lies in the Al Magd Development Lease on the middle margin of the central Abu Gharadig basin, 2.5 km to the east of the Al Magd field (( see Fig.1).

Al Magd C86-1 was drilled down to Kharita formation. The log evaluation showed that the penetrated reservoir ((A/R “C”, A/R “E”) were found water bearing with virgin pressure which proves no communication with either ALMagd or Bahga fields.

The Al Magd Development Lease is part of the Alam el Shawish concession which was previously operated by PetroAlam on behalf of VEGAS, GDF Suez and EGPC. SENV acquired part of the concession in 2009 and Bapetco was awarded operatorship early 2010.

The Al Magd field is in close proximity to the discovery and five wells have been drilled to date in that field. The field produces from relatively thinly developed sand units of the Upper Abu Roash “G” sequence.

The discovery well AL Magd C86-1 will be tested starting June2012 and is expected to be online from July

2012.

1.3 Geological Risks

The main uncertainties are the following:

• Fluid contacts/pressure in all reservoirs.

• Losses in Apollonia and Khoman formation.

• Depth uncertainty ranging between +/- 50 m and +/- 100 m.

2- Well Design and Cost

The well is proposed to be drilled as deviated well to T.D, 50 m below the top Kharita formation leaving sufficient space for the shoe track & rate hole. In case of the well will be oil producer it will be completed by 3 ½” CS tubing with SSD for Jet pump & seating Nipple for Sucker Rod pump.

Shallow gas is not expected (not seen in offset wells)

17-½" surface hole section will be drilled to 1126 mTVDBDF vertically with 13-3/8’’ shoe set 20 m into Apollonia formation. Spud mud will be used to drill Moghra formation. KCL / SS polymer mud will be used to drill Dabaa formation.

The 12-1/4” intermediate section will be drilled with water based mud (KCl poly mud) to 2562mTVDBDF vertically with 9-5/8” shoe is to be set +/- 1 50 mTVD into A/R “A” FM

Partial losses (if any) in the Apollonia and Khoman will cured by reduced pump rate and LCM pills.

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The 8-1/2” reservoir section will be drilled with WBM (HYDRO GUARD system) in case of Diesel shortage. TD will be at 3578 m AHDBDF. TD criteria are 50m below the top Kharita formation leaving sufficient space for the shoetrack & rate hole.

7” liner casing will be set from TD to inside 9-5/8” casing with a minimum of 100 m overlap using a rotating liner hanger.

The success case is programmed to take 35.6 days (including 5 days for rig move) at a cost of $ 3.247 MM (including completions).

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Summery sheet Well

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3- Well Engineering Technical Details

• Appraise the lateral reservoir extension of the Abu Roash & Bahariya • Test for a possible hydrocarbon accumulation in the Kharita up dip of the discovery well.• Provide an oil drainage point for the Abu Roash and Bahariya for primary depletion and water flooding.

3.1 Well Elevation.

Elevations Depth

Rig Floor Elevation to Ground Floor + 9.00 meter

MSL to Ground Elevation + 37.79 meter

Rig Floor correction to MSL + 46.79 meter

3.2 Offset Wells, Target Data and TD Criteria

Offset Wells Al MAGD C 86-1 and other Al MAGD wells.

Surface Coordinates

E = 330791.31 m (Red Belt) LAT. = 29°40'08.483''N

N = 776916.38 m (Red Belt) LONG.= 28°03'53.262''E

Provisional Land Elevation = 37.79m

SubSurface Coordinates

A/R”G” Depth 2915m Tvdss

E = 330,737.7 m (Red Belt)

N = 776821.05 m (Red Belt)

Top Intra Bahariya L.S. Depth 3115m Tvdss

E = 330687.12 m (Red Belt)

N = 776821.05 m (Red Belt)

Target Tolerance

Target AR/G tolerance will be rectangular 150m width for each side from the central and length will 200m with 100m for each side from the central.

Target for intra Bahariya L.S Circle with 75 a radius.

TD Criteria:

TD criteria are 50m below the top Kharita formation leaving sufficient space for the shoetrack & rate hole.

Approximate TD Depth = 3420 m AHDBDF (3310 mTVDSS)

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3.3 Drilling Risks

The drilling risks from Sitra offset wells are:

17 ½” HOLE SECTION

Partial Losses in Moghra sands

Bit and stabilizer balling in bottom clay in Moghra and Dabaa shale.

Swelling of Dabaa shale

Over pull and back reaming required while POOH.

Caving shale

Problems circulating cuttings out of hole at TD prior to POOH at TD.

Action taken to manage risks:

Use spud mud to drill Moghra sand

Low gpm first 150 m (400-600 gpm) then start to increase gpm gradually

KCl / SS mud to reduce bit balling in Dabaa formation

High flow rates (gpm) while drilling Dabaa (+/- 1100 GPM) and RPM >100.

12 ¼” HOLE SECTION

Chert in Apollonia (up to 10% - 60%)

Heavy back reaming required all way through Khoman and Apollonia (wiper trip required) however this phenomena decreases last drilled wells and only small interval require heavy back ream.

Partial losses in Apollonia and Khoman.

High drilling torque. Potential drill string vibration.

Possible hole kick off in Apollonia while drilling the chert.

Foaming due to CO2 in Khoman formation.

Bit balling of PDC bit after drilling out shoe track in Apollonia.


Increase water loss to +/- 15 with max gpm then cut to 10.

Losses can be cured by reducing pumping rate, sweeping hole with LCM pill ( Sitra 8-5, Sitra 8-6, Sitra 8-9 well)

Reduce WOB and increase RPM (fanning) to bring hole back to vertical.

Use KCL polymer mud.

Mud chemicals pre-treated CO2 scavenger and deformer.(also use fresh water in preparation for fresh mud).

Pump salt saturated mud if needed.

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8 ½” HOLE SECTION

Caving shale in A/R formation

Slow ROP especially in sliding

Over Pulls while POOH.

Problems while run W/L logging.

Direction problems out of target tolerance.


Use HYDRO GUARD system WBM.

Using conventional rotary BHA to improve ROP.

Perform short trip before pooh to run W/L logging.

Use motor to turn well and pooh.

3.4 Surveying

Quality control of well bore surveying will be according to the “Borehole Surveying Manual EP59-1000”. Survey methods will be as follows:

Hole Method Casing

17 ½” Gyro (No TOTCO required) 13 3/8”

12 ¼” MWD 9 5/8”

8 ½” MWD 7”

3.5 Casing

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FormationDepth,

mbdf

Hole

Size

(in)

Casing

Size

(in)

Weight

(lb/ft)Type Thread

Apollonia(20mintoApollonia) + 1126 17 1/2 13 3/8 68 CSG BTC

AR/A(150m into AR/A) + 2562 12 1/4" 9 5/8 47 CSG VAM TOP

TD + 3420 8 1/2" 7" 29 liner VAM TOP


The above casing design is based on no losses in the depleted zones. As a contingency, in case of losses occurs, the hole will be cased off by 7" liner and the rest of the well drilled as 6" hole with the condition of no more losses. To date this case has not materialised in any of the wells in Al MAGD

3.6 Well Head – Wood Group (3-1/8” 5K solid block)

13-3/8” x 13-5/8” 5K BTC CHH

13-5/8” x 9-5/8” VAM TOP Casing (Mandrel) Hanger

13-5/8” 5K x 11” 5K THS

11" x 3-1/2" 5 K Tubing Hanger

3-1/8" 5K solid block X-mas Tree

3.7 Bits and Hydraulics

This table gives an overview of the bit types required to drill the well.

IADC CODE

Bit Type FormationWOB (Klb)

Flow rate (GPM)

Surface RPM

17 ½” 1.1.5 TBA Moghra/Daaba 25-65 700-1200 80-140

12 1/4” PDC TBA Apollonia Khoman 20-45 700-850 80-120

8 ½” PDC TBAA/R “

Bahariya, kharita25-40 450-550 80-120

3.8 Well Evaluation / Logging

12-1/4” Hole Section (depending on hole conditions)

No Logs are required (only in case of strong H.C shows)

8-1/2” Hole Reservoir Section

LWD will be required in case of using water base mud to drill the 8.5’’ section to overcome bad hole conditions.

• GR /Resistivity /Neutron/Density.

• LWD GeoTap pressure points (optional in case of using LWD instead of W/L).

W/L Logging will be conducted as follow:

• GR /Resistivity /Neutron/Density.

• GR/RDT (Samples are optional).

• GR/Image. (Optional).

• Sonic (Optional).

• Check shots (Optional)

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Notes:

The above logging sequence might be changed depending on the hole conditions and firstrun results. The final logging program will include the final log arrangements.Check shot is optional in case of having formation tops off prognosis.Sonic is optional in case of check shot.In case of thick >10m sand image will be required.

3.9 Geological Sampling

17.5” Hole: Every 10 m (from surface to top Apollonia formation).

12 ¼” Hole: Every 5 m (from top Apollonia formation to top A/R “A” Mbr).

8.5” Hole: Every 2 m (from top A/R “A” Mbr to well TD).

3.10 Formation Tops and Pressures

Formation TopsDepth (m)

mTVDssUncert. Pressure (psia) Fluid Gradients (psi/ft)

Moghra Surface Hydro.

Hydro. Hydro. Hydro. Hydro. Hydro.

Dabaa -670 +/-50 1004 1026 1070 0.45 0.46 0.48

Top Apollonia A -1059 +/-50 1578 1613 1682 0.45 0.46 0.48

Khoman-A -1580 +/-50 2347 2399 2503 0.45 0.46 0.48

Khoman-B -2150 +/-50 3189 3260 3401 0.45 0.46 0.48

Fault -1971 +/-50 0.45 0.46 0.48

AR/A -2365 +/-50 3507 3584 3739 0.45 0.46 0.48

AR/ B -2620 +/-50 3883 3969 4141 0.45 0.46 0.48

Top AR/ C -2723 +/-50 4035 4124 4303 0.45 0.46 0.48

AR/D Fault -2730 +/-50 4045 4135 4314 0.45 0.46 0.48

AR/E -2750 +/-50 4075 4165 4346 0.45 0.46 0.48

AR/F -2875 +/-50 4259 4354 4542 0.45 0.46 0.48

Top AR/G S1”A” -2915 +/-50 4319 4410 4605 0.45 0.28 0.48

Top AR/G S1”B” -2923 +/-50 4330 4417 4618 0.45 0.28 0.48

Top AR/G S2 2935 +/-50 4348 4428 4637 0.45 0.28 0.48

Top Intra AR/G L.S -2978 +/-50 4412 4509 4705 0.45 0.46 0.48

Top M AR/G Sand -2990 +/-50 4429 4478 4724 0.45 0.28 0.48

Base M AR/G Sand -3000 +/-50 4444 4488 4739 0.45 0.28 0.48

Top Lower AR/G Sand

-3030 +/-50 4488 4562 4787 0.45 0.28 0.48

Base Lower AR/G Sand

-3035 +/-50 4496 4567 4794 0.45 0.28 0.48

Top Bahariya -3045 +/-50 4510 4610 4810 0.45 0.46 0.48

Top U. Bah. sand res.

-3070 +/-50 4547 4708 4850 0.45 0.3 0.48

Top int. Bahariya L.S

-3115 +/-50 4614 4716 4920 0.45 0.46 0.48

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Top L.Bah.sand1 res.

-3220 +/-50 4769 4860 5086 0.45 0.3 0.48

Top Kharita -3260 +/-50 4828 4888 5149 0.45 0.46 0.48

TD -3310 4902 5010 5228 0.45 0.46 0.48

Notes:

A/R ”D” expected pressure is analogue from Sit C4-1.The pore pressure prediction in the non-hydrocarbon zones is based on the uncertainty of the water gradient,which are 0.45, 0.46, and 0.48 psi/ft.The uncertainty in the formation tops is not considered in the pore pressure calculations.Uncertainty of the equivalent mud weight depending on the above pressure prognosis table without any safety margins

MUD WT SELECTION

17 ½” HOLE

FROM 0.46 to 0.52 Psi/ft (INCREASE MUD WT TO 10 PPG AT TD). TO SUPPORT DABAA SHALE.

12 ¼” HOLE

FROM 0.48 to 0.50. Psi/ft THIS IS BASED ON THE EXPECTED PORE PRESSURE PLUS 200 PSI OVER BALANCE.

8 ½” HOLE

FROM 0.48 to 0.53 Psi/ft THIS IS BASED ON THE EXPECTED PORE PRESSURE PLUS 200 PSI OVER BALANCE. Please ensure that you monitor for any connection gas, in particular through objective sections. If there are any indications of higher pressure then weight up to reduce these back to background. Also if any concern towards the higher end of the pressure range, then a 10 stand wiper trip to check for trip gas prior to POOH for casing should be considered.From experience with hydro guard in the last two wells we should increase mud weight to 10 PPG prior enter A/R G formation and increase up to 10.4 PPG prior enter baharyia.Make sure that mud WT is not increased by low gravity solids in mud and maintain within the range not to deteriorate the mud.

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4 Reporting and Documentation

4.2 Reporting

1 The daily drilling report is the main vehicle for capturing data and learning’s. The report should be as comprehensive as possible and include, for example; clear descriptions of hole condition while tripping, accurate details of drilling parameters and rotating hours, percentage of caving, accurate mud specification etc. The correct code phasing is also extremely important as this will determine the amount of NPT and help to identify ILT (invisible lost time).

2 DSV’s to maintain an on-going record of learning’s from the well, which will be included complete or in part, in the Final Well Review (FWR). This needs to be done accurately and consistently.

3 The well site drilling engineer must maintain the “Data Tracker”. This information is important and is used for Plan v Actual reports, NPT data, AAR, etc.

4 When a new technology is used or a technical failure occurs a separate report should be sent to ODD/2 and ODD/22, copy OD, OD/1.

5 When LTOBM is used, the oil-on-cuttings measurement needs to be reported daily in g/kg. Glycol WBM needs to have the cloud point reported in degrees Celsius.

6 Tool Rental inventories must be current and available on the rig site.

7 The latest mud log, survey data and logging data to be sent to OD2 each morning.

8 A “look ahead” plan for the well must be prepared and updated at least twice weekly.

9 Ensure that an Environmental Impact Assessment (EIA) is in place or approval to drill under a nearby EIA is approved.

10 Well Cost Monitoring and reporting should be carried out diligently. Costs reported in the DDR are used to monitor actual v planned and reported to management. Notification of cost overruns and subsequent variations to the AFE shall be initiated from such information. The attached well AFE should be used as a basis for such cost comparison/monitoring.

11 The material control sheet must be completed and at the end of the well, sent to the SAP technical assistants who will reconcile the quantities in SAP in line with the material consumed on the well. Material transfers, either back to material yard or to the next location must be completed.

12 All requested work must be accompanied with a SAP number.

13 Make sure all drilling manuals on site.

4.3 Documentation

The documents described below should be available on the rig site;

Signed Drilling Program: This is the approved document to be followed with respect to all rig activities associated with the well. A copy must be available on the rig site.

Drilling Engineering Operations Manual: The aim of this document is to improve the efficiency and safety of our Drilling Operations by giving the benefit of past experience. This manual is advisory except for the first part of Section 3 (“Mandatory Safety Policies and Procedures”).

End of Well Reports: Reports from previous wells showing offset data and learning’s.

ABC of Stuck Pipe together with Supplement 1 (Borehole Stability) and Supplement 2 (Hole Cleaning): These documents are educational guides on stuck pipe.

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Pressure Control Manual for Drilling and Work over Operations (EP 2002-1500): This is the Shell well control policy and should be used as a reference document which overrides all other well control documents. Deviation from this policy requires OD, OD/1 approval.

Bapetco Environmental Procedures for Onshore Drilling Operations: This document describes operational procedures for environmental protection during drilling operations onshore.

EP Safety Manual - SHOC: All chemicals used during Bapetco operations must have the associated SHOC card available for reference on the rig. Each provides specific HSE data.

SMS Manual Part 1: This manual defines the complete Bapetco system of safety management.

Drilling Department - Field Emergency Procedure Guide: This manual has been written for field use on operations controlled by the DSV. It covers various emergency scenarios and a set of checklists, which have been written for each of these.

Shell HSE Control Framework – EP2005-0100: The manual provides obligatory safety recommendations. Any deviation from this manual needs to be approved by OD and OD/1.

Environmental Impact assessment: A full EIA has been produced and this should be referred to for all environmental considerations.

Updated copies of all relevant contracts.

Bapetco & EDC Western Desert Operations HSE Case, Doc No. S10-01-R-01 Issue 1, 18th Dec 97.

Bapetco Well Hand over Procedure: This procedure was introduced in August 2001 and should be adhered to at all times.

Bapetco Barrier Policy: This document describes barrier required when completing the well and before rig entry.

Emergency and Contingency Planning: Field Emergency Procedures Manual should be used in case an emergency takes place. The relevant parts of the manual should be presented to the rig site personnel as part of the weekly safety meetings and appropriate drills should be organized such that everyone knows their responsibilities in the event of an incident and what steps to take in an emergency.

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5 HSERefer to the D.O.M. Section 3.1 for additional details. Reference should also be made to the recently updated HSE Case for EDC’s and BAPETCO’ S drilling activity in the Western Desert. Particular attention should be made to the Safety Critical Task assigned to the respective personnel associated with the operation.

5.2 Health

The rig site EDC medic is responsible for proper health care and ensuring hygienic conditions at the camp site, inclusive of supervision of health considerations in the kitchen and dining room, overseeing the catering contractor and regular checking of potable water supplied. At the rig site the EDC Senior Tool pusher is responsible for a healthy work environment by ensuring that the appropriate PPE (Personal Protective Equipment) is worn at all times for tasks such as handling of chemicals, working in high noise areas etc.

5.3 Safety

Regular drills must be performed to prepare rig crews and equipment for potential emergencies. A strip drill must be carried out before drilling out the 9 5/8” casing shoe. BOP testing is to be done at least at three-week intervals. A weekly safety meeting will be held with all crews. Toolbox talks (TBT) must be held for all operations, (the more complex the operation the more detailed the TBT).

A clear written procedure must be available on the rig floor before conducting any drills.

An extract of the weekly meetings must be sent OD & OD/1 highlighting attendees, topics discussed, outstanding actions, and “Unsafe Acts” observed. LTI's (Lost Time Incidents), RWC's (Restricted Work Cases), MTC's (Medical Treatment Cases) and NII's (Non Injurious Incidents) should be reported immediately when they occur and a cumulative data reported in the Monthly Safety Report (daily occurrences to be reported statistically in the DDR).

The only access road used to the location must be the Bapetco constructed access or other authorized tracks, short cut tracks are not to be used. Dedicated parking areas should be assigned to both main-camp and rig site camps and reverse parking rule enforced. Service company personnel driving to the rig must complete a journey management plan before they depart Cairo, and night driving requires BO and BO/1 approval.

All breathing equipment sets available on the well site to be re-tested prior to drilling of the objective, and site evacuation drills to be held at regular intervals. Where H2S is a potential occurrence, carry out awareness training and more frequent drills.

5.4 Environment

Every effort must be made by rig site personnel to execute operations in such a way as to minimize adverse impact on the environment. Every well must have an Environmental Impact Assessment (EIA) or be drilled under the EIA of an adjoining area. Waste bins/skips are to be placed in the camp area(s) and should be regularly emptied (at least once a week). Monthly camp inspections are to be held by EDC & Bapetco senior representatives, both from the rig site and from Cairo. All operations such as waste management, collection and disposal, including location clean-up (after drilling operations), should be executed in compliance with the Bapetco Environmental Procedures Manual. Should EDC’s procedures be more stringent, then these should be applied.

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6 Well Control Equipment and Procedures

Refer to the BAPETCO Drilling Manual, Section 3, pages 10-12 and EP2002-1500 for more details.

Be familiar with the Shallow Gas Procedures (EP 88-1000).

Hold a trip drill followed by a flow check every time the drilling assembly is pulled into the casing shoe when tripping out, and ensure trip-sheets are diligently used.

Hold regular pit drills with each crew.

Perform a strip drill after cementing the 9 5/8” casing, with each crew if possible, and an H2S drill every second week. Drills are to be noted on the IADC and daily reports.

“Formation Integrity tests” or “Limit tests” will be required on most wells and are specified in the drilling programme summary sheet.

Test pressures for casings, wellheads and BOP equipment are specified on the program summary sheet.

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7 General Drilling Notes1 All Breathing Apparatus (BA) equipment to be tested prior to drilling the objective and crews are

to be familiar with its use. Safety meetings on rig evacuation are to be held at regular intervals.

2 To minimize casing wear all drill pipe will have “Soft Smooth” hard facing which is flush with the tool joint; grind down if necessary.

3 A magnet will be placed in the flow line ditch, and monitored to provide an indication of excessive casing wear. Ditch magnet recovery is to be reported daily; in kg for the previous day and total kg for the whole section. Also refer to the D.O.M. Section 3.2.10 for detailed procedures. Note: Should new pipe be utilized on this well, additional precautions shall be necessary as to ensure that not only the tool joints are broken-in correctly, but also that pipe with new hard facing is placed in open hole.

4 Drawings showing all dimensions of the tools and equipment run in the hole are to be made. Ensure that fishing tools are available to recover all down hole equipment.

5 Drilling assemblies need to be laid down and inspected every 200 operating hours. Jars to be changed out after 250 circulating hours. The jars need to be supplied to the rig site with a full and detailed inspection report. Back-up sets need to be available on location and reported in the DDR Also ensure DP/DC are rotated at each trip to reduce chances of building up fatigue in the same set of DP/DC over time.

6 Below are minimum stocks to be kept on the rig site;

50 ton barite

500sxs LCM (different grain sizes)

500sxs CaCO3

50,000L diesel

40,000 BBL water

7 Have 100% excess cement chemicals to be on site prior each casing cement job. Check quality of chemicals prior the job.

8 The DSV and/or EDC Tool pusher should be on the rig floor during tripping in open hole to ensure that correct actions are being taken during hole problems. Ensure that trip-sheets are correctly and diligently used.

9 The DSV should issue daily instructions for each job and discuss these with rig team members.

10 Separate Halliburton cementing programs will be provided by the cementing contractor via the Cairo office before each casing or liner job. Refer to the Bapetco Drilling Manual for likely Centralizer requirements. Samples from drill water and onsite cement have to be supplied well in advance to the cementing contractor laboratory for testing. Check maximum measured static bottom hole temperature from logging tools against the cement recipe temperature.

11 A selection of bits will be made available by the OD2 team after evaluating offset data. The majority of bits will be on a purchase consignment. New bit types may be run on a performance agreement.

12 For roller cone bits the total revolutions are to be recorded and reported. Bit supplier will advise on maximum revolutions for each bit type. Regular drill-off tests are to be conducted to find optimum parameters.

13 Each rig to have 250m of 3½” steel cement stinger (c/w with x-over and handling tools) on site for setting cement plugs.

14 The mud logging unit shall in principle be operated “ON LINE”. The gas detector must be operational from surface onwards. The gas detector should be tested and functioning correctly. Regular testing and calibration of the unit to take place throughout the drilling phase. Besides the daily geological reporting, the updated contractor Master Log showing, amongst other data, drilling rates, cutting lithology , ditch gas (PPM), percentage of caving and remarks needs to be

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transmitted to Cairo (ODD/2, ODD/21 and OD/X) on a daily basis.

15 Drill water supply will be either by tanker or from nearby water well via a plastic water line. Water wells up to 2km from the rig site can be used, beyond this distance there are problems with line pressure, leaks etc. If the drill water is trucked to the location the trucks need to be ordered early, comply with Bapetco standards and the unloading point at the rig site must be adequate for the water trucks.

16 All water pits must have barrier tape around the pit to warn people of the risk.

17 Critical material should be close to the security / guard check post in order to guard it against theft.

18 Any disturbance from any outsider in the area should be reported immediately to the control security of Bed-3 and Cairo office.

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8 Well Program Details

2.1 17-½” Surface Hole Section to 1126 m AHBDF (TVDBDF)

2.1.1General

o Drilling and Tripping for Dabaa formation you can get it from R drive under R/ Drilling Best Practices/ Bapetco Best Practice Guide

1 Hold a pre-spud meeting on the rig lead by DSV. All relevant EDC, Bapetco and service company personnel to attend. A second pre-spud should be held to ensure that the night crews are fully briefed on the well plan.

2 Ensure that the approved drilling program including mud and cement programs are received and reviewed before spud.

3 Fresh water should be ready on location for building up the spud mud/KCL mud.

4 The 17-½” section will be drilled without BOP protection as no hydrocarbons have been seen in offset wells.

5 17-½” hole will be drilled to section TD in one pass.

6 Section TD will be at least 20 mTVD in the Apollonia formation. Section TD should be accurately calculated from the measured 13-3/8” running length (allow for a 3-5 m pocket).

7 The 13-3/8” casing will be set at +/-1126 m AHBDF to isolate the unstable loose Moghra sand formations and reactive Daaba shale with section TD at least 20 m in the Apollonia formation.

8 There is no shallow gas expected but a ported float must be run in the drill string.

9 No gas is expected in the first 30 meters of the Apollonia formation.

10 Losses are expected in this section - ensure LCM recipes and procedures are in place.

11 The 20” conductor will be set during construction of the cellar. The top of the CHH should be level with the top of the cellar.

12 Ensure water pits are full & waste pit is 20-30% full before spud.

13 Ensure that all drilling tools and equipment are available on site and in a serviceable condition prior to operations.

14 All drill string components should be inspected before use - check the ID of all down hole equipment for the passage of an FPI tool and fishing tools.

15 Ensure wherever possible that the neutral point of all BHA's is not in a jar / accelerator etc. and is preferably in drill collars.

16 Make sure cellar jet is functioning & working properly.

17 Ensure drill pipe is accurately strapped, drifted and tally is up to date.

18 Geological Sampling Programme:

Samples to be collected every 10 m (from surface to top Apollonia).

3 sets of unwashed wet and 2 sets of washed & dried cutting samples

Representative mud samples

Page 19 of 47


Potential Problems and Drilling Issues for 17 ½” Section

Partial/Total losses in Moghra (30 – 60 bbl's/hr)

Heaving / swelling clay in bottom of Moghra.

Bit and Stab balling up. Slow ROP due to Bit Balling

Unstable shale in Dabaa (caving shale), possible stuck pipe and high tendency of hole pack off – water loss to be controlled +/-5.

Hole filling by accumulation of the drilled cuttings

Losses with cement displacement during 13-3/8” cement job. No cement to surface.

Drill cuttings not circulated to surface at TD after bottoms up

To avoid the problem of all above mentioned

Utilize proper flow rates to match ROP to clean hole properly.

Use only KCL/PLY mud with 7% KCL and tight control on fluid loss to +/- 3 cc/30 min.

Switch to KCL at least 100 m before Dabaa formation.

Wash while running casing repeatedly.

Top hole cement fill in case of drop in annulus cement level

No Glycol to be used on this well as this will not add any improvement on the hole condition as seen in Sitra 8-9.

NO Condit pill will be pumped in this well (it gives us no benefit).only circulate hole clean while pooh at bottom Moghra)

2.1.2 Drilling 17-½” Hole Section

1 Hold a toolbox talk / safety meeting and ensure all personnel are aware of operations.

2 Nipple up riser on Conductor.

3 Test circulation system at maximum expected flow rate of about 1100-1200 GPM. Drill ahead reaming each connection and add BHA items.

4 Spud well with 17-½” section hole with spud mud using the proposed BHA given below:

BHA #1 17-½” Assembly

17-½” Rock bit (Mill Tooth 1-1-5) – (3 x 18, 1x 16 centre jet) 1 x 9-½’’ Bit Sub (with float)1 x 9-½” shock sub17-1/2” String Stab 2 x 9-½” DC

X.O9 x 8-¼” Drill Collars1 x 8-¼” Jar 2 X 8-¼” DC

X/O15 X 5” HWDP

Page 20 of 47


Note:

The BHA’s mentioned above are advisory but can be changed for good reason in liaison with Sr. Drilling Engineer or Drilling Engineer.

A ported float should be run at all times (backflow mitigation)

Refer to Dabaa best practise drilling procedure.

No TOTCO sub should be included in the BHA

5 Use 9-½” DC’s in a pendulum assembly. The amount of 9-½” DCs used above the stabiliser may be optimised taking into account that extra 9-½” DCs are not generally required to drill a straight hole in the Dabaa.

6 Choose nozzles carefully to maximize HSI. With typical maximum flow rates using 16/32" nozzles as well as a centre jet the standpipe pressure has been observed to be in the region of +/-2700 psi when the mud weight was raised to 9.8-10.2 ppg (0.51-0.53 psi/ft) (probably will be 1*16 C.J + 3*18).

7 Spud 17-½” hole section with spud mud.

8 Recommended drilling parameter 30-65 klbs WOB and 130-140 RPM with maximum possible GPM. (shock sub will reduce vibration and allow the use of high WOB).

9 Drill the first 150 m with reduced ROP and flow rates so that the formation underneath the cement pad is not washed out. ROPs and flow rates should be increased in steps.

Consider 400 – 500 gpm flow rate for first 150 m with restricted ROP. Then gradually increase ROP and flow rate to 800 – 1200 gpm depending on the losses and the capacity of the shakers. Dress shakers with 80/100 mesh screen.

Maximum flow rates should always be used through the Moghra. Ensure rig is using 6-3/4” or bigger liners for 17-½” hole. Try to find best performance while drilling Moghra formation with maximum possible parameter.

Drill with spud mud to about 150 meters above the top of Dabaa formation

This is based on prognosed Dabaa depth, otherwise if we see that samples are showing characteristic of Dabaa, start switching the mud.

10 Start switching over to KCl mud 150 meters before reaching the Daaba formation (need to control ROP while the switch over as possible to help shearing the mud). This mud switch has the following effects:

helps stop swelling of Moghra clay at bottom Moghra.

prevents / minimizes bit and stabilizer balling and over pulls during POOH due to Moghra clay.

Helps early shale inhibition in Daaba. This can be problematic if mud not switched early enough.

Losses may start or increases (around +/-30 bbl/hr) due to higher mud weight of salt saturated mud. These losses are cured by once the bottom clay in Daba has been drilled.

IT WAS NOTICED in some sitra WELL OVERFLOW OVER THE SHAKERS AFTER THE SWITCH OVER SO IT IS RECOMMENDED TO START WITH LOW VIS MUD 40 FUNNEL VISCOSITY AND INCREASE IT WITH TIME.

11 Pump viscous pills as necessary. Keep tight control of mud weight and rheology. Ensure drill crews are briefed to minimize Surge and Swab pressures when tripping or starting up pumps after connections.

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12 At section TD (provisionally at 1126 m) sweep hole with 100 bbl high viscosity pill. Ensure the hole is clean.

TD will be picked on cuttings sample.

Increase mud weight to 0.53 before POOH to stabilize Daaba shale if required (based on cuttings – if caving are observed).

13 When circulating clean makes sure that the shakers are clean before tripping. It may take a while for hole enlargement to stop.

Rotate at 100+ RPM and 800+ gpm when circulating clean. If anything is loose in the hole it has to come out before tripping.

14 Spot 100 bbls of Hi-vis on bottom before pulling out of hole to suspend and hold any cuttings / caving minimising possible fill buying you time to get the casing in the ground. Note: it happened that you got overpull first two stands. Commence pump ooh and back ream if necessary.

15 POOH whilst continuing to circulate at reduced rate to ensure string is kept full.

16 When pulling out of the hole use ½ BHA weight as a maximum before you go back down away from the tight spot.

17 If any signs of packing off are observed, overpulls are taken and string cannot pass upwards – RIH (if necessary go down 2 or more stands), increase the pumps slowly and rotate at 100 rpm+. Make sure that the hole is cleaned up before attempting POOH.

Note:

Only sweep a hi-vis pill if the pressure and torque are normal otherwise you may cause another pack-off.

The hydraulic effect of pressure when pumping is started is quite pronounced and can push the string further into a sticky area if you created a temporary pack-off. Therefore it is important that

18 Pump out of hole with 700+ gpm if necessary (if any signs of pack off are observed).

19 When pumping out of hole, same guidelines should be applied as regular POOH. Back ream out with great care; do not take any overpull, Monitor torque and pressures for signs of pack off. DSV/STP to be on rig floor while POOH if back reaming is required.

20 If there is excessive caving while pumping/back reaming out, the hole should be cleaned before resuming POOH and getting into any additional tight spots.

21 If hole condition is good on the trip out, do not make a wiper trip. Wiper trip only if hole condition dictates. Inform Sr. Drilling Engineer if wiper trip is required.

22 Circulate hole clean @ BTM moghra

23 Prepare and Rig up to run 13-3/8” casing.

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2.1.313-3/8” Casing Running & Cementing

The 13-3/8” casing shoe is to be set at approximately ± 1126 m and cemented using a standard 13-3/8” top & bottom plug system.

A single joint shoe-track will be utilized.

Send cement and water sample to SHELMBERGER in advance.

The Drilling Supervisor shall verify pump volumes with cementing company prior to pumping.

The 13-3/8” casing will be cemented back to surface with at least 50% excess on open hole using a 12 ppg lead slurry followed by 150 m of 15.8 ppg tail slurry. Excess to be confirmed with office before cementing.

A top up job will be performed if cement does not reach surface.

Swab / surge calculations should be performed to ensure that the planned running speed does not result in formation breakdown (by Halliburton / WSDE / ECS unit).

13.3/8” Casing Specifications

Weight Grade Coupling Burst Collapse Yield Torque ID Drift Capacity

68 lb/ft K 55 BTC 3450 psi 1943 psi 1040 Klbs 7180 lb/ft 12.415” 12.259”0.14972

bbl/ft

Casing Test Pressure 2000 psi At plug Bump

CHH Test Pressure 2000 psi Between welds & side outlets

Preparation

1 Ensure all 13-3/8” casing running and handling equipment is present and has been checked before start of job.

2 Call SAPESCO and Weatherford 48 hours before the job as per contract.

3 Remove thread protectors on casing and inspect all connectors for damage.

4 Clean all connectors using non-metallic brush and solvent or high pressure steam gun. If this is done more than 48 hours prior to running the casing, threads should be lightly oiled to prevent corrosion.

5 Drift and tally casing (drifted to 12.259”). Calliper a minimum of 10-15% of the ID of the casing. Produce independent casing running tallies (WSDE / EDC checked by the DSV). Send final tally for Ops Engineer to check and confirm.

6 Suitable pup joints should be available on site ready for levelling the top flange of the CHH.

7 Visually check the float shoe and float collar joints to ensure no debris inside. Ensure backup is on location if required.

8 Float should be a non-rotating type

9 Visually check the condition of cement plugs ensuring that they are in good condition.

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10 Bapetco and SHELMBERGER to independently perform cementing calculations and compare. When calculating displacement volumes, take volumetric efficiency of mud pumps into account.

11 Confirm volumetric efficiency of rig and cementing unit pumps (also refer back to previous cement jobs for estimates of mud pump efficiency - typically of the order of 97% for 13-3/8” displacements) – report volumetric efficiency results in the DDR.

12 M/U float shoe and float collar joint on ground, baker lock same.

13-3/8” Casing Running

1 Hold toolbox talk / safety meeting prior to running casing.

2 DSV / WSDE to be witness entire casing running / cementing operating.

3 Cut 20" conductor and line up and test cellar jet to take returns into the cellar.

4 The 13-3/8” casing will be run with single joint shoe track.

NOTE: No centralizers are to be installed (TBA by OD/2)

5 The Buttress casing should be made up to base triangle (marked on pin connector).

Optimum torque should be determined by averaging make-up torque required for first six joints. Average make-up torque should be in the region of 7180 ft/lbs.

6 After the float collar joint has been made up, check the float equipment is clear by flushing through. Test floats and confirm float equipment is functioning. Bakerlock float equipment.

7 Continue running in with 13-3/8” casing as per tally, monitoring drag and casing running speeds. Ensure that the speed does not exceed the maximum value calculated by surge calculations.

Note:

Ensure string is filled every five joints (or as required - more often initially) to avoid casing ‘floating’ in elevators and to ensure an adequate overbalance is maintained

8 Casing running speed (jt/hr) to be recorded in DDR.

9 Performance drive: Aim for running speed > 12 jts/hr (Check last well)?

10 Wash down the last three casings joints.

11 Install CHH after last casing joint has been run.

12 Install landing joint. Land casing.

13 After casing has landed break circulation to ensure float shoe is clear. Circulate at least one complete circulation (or more if required).

Page 24 of 47


13-3/8” Casing Cementing

The return and displacing tank arrangements are to be planned before cement mixing commences. Pump strokes alone are not accepted as sufficiently accurate to be used as the sole method of displacement volume measurement

Ensure that good communication exists throughout the cement job.

All preflush, spacer, cement and displacement volumes should be independently monitored by the mud logging / cement unit and the drill floor.

Hold JSA for cementing operations. Ensure all personnel understand their roles and responsibilities during the job.

1 Rig up cementing equipment and cementing lines while circulating.

2 Inspect plug loading head prior to loading plug.

3 Pick up and install plug loading head prior to loading plug (SCHLUMBERGER rep to supervise).

4 Load top and bottom plugs in cement plug loading head. DSV to witness and verify loading of plugs.

5 Pressure test cement head and lines to 3000 psi.

6 Zero rig and SCHLUMBERGER cementing unit pump strokes.

7 Pump preflush as per SCHLUMBERGER Cementing programme.

8 Mix and pump lead and tail cement slurries as per SCHLUMBERGER recipe. Casing will be cemented with at least 50 % excess cement (to be confirmed with the final RCP).

9 Cement samples should be collected during the execution of the job.

10 Once the cement has been pumped release the top plug (DSV / WSDE to witness).

11 Displace at maximum possible rate possible so as not to induce losses.

Note:

The displacement volume should also be measured from the mud pits (or cement tanks if cement unit is being used).

The return and displacing tank arrangements are to be planned before cement mixing commences. Pump strokes alone are not accepted as sufficiently accurate to be used as the sole method of displacement volume measurement.

Frequent checks must be made on the tanks throughout the displacement to ensure that the volume being used compares with the rate of displacement.

Ensure the mud-logging unit monitors and records all displacement volumes and pressures.

12 Slow the pumps down immediately prior to bumping the plug (recommend slowing down at theoretical plug bump assuming 100% volumetric efficiency) and record static differential pressure. If the cement thickening time is approaching, ignore the above and continue displacement until the plug bumps.

13 Bump the plugs at slow pump rate. If plug does not bump when expected, limit over displacement to ½ shoe track volume (~2.2 bbls for 9 m shoe-track). Inform Cairo office if plug does not bump.

Note:

Note final differential pressure at end of displacement, report TTOC estimate, cement returns, pump rates etc. on the DDR.

Make sure volumetric efficiency of pumps is taken into account in calculation of theoretical displacement volumes.

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14 If the plugs bumps, pressure up and test casing to 2000 psi (i.e. 2000 psi absolute pressure, not 2000 psi over plug bump pressure). Note and record volume required to reach test pressure.

15 Bleed off pressure and check operation of float equipment. Re-bump plugs if float valves fail to hold. Maintain static differential pressure until the cement sets sufficiently to prevent backflow, or until the surface samples set.

16 If no cement is seen at surface inform Cairo office and prepare to perform a top-up job.

17 After landing the casing on the casing clamp, remove the CHH Landing joint and the cementing sleeve.

18 In the event that the casing cannot be run to bottom, use an emergency weld on or slip lock casing head housing if available. Otherwise set casing one casing joint off bottom.

Ensure a cold cutter is available in case a slip lock CHH is required.

19 Height of the CHH should be such that the bottom of THS is level with the top of the cellar at ground level.

20 The orientation of the wellhead should be checked and confirmed with the operations team in the field – report in DDR.

21 Nipple up 13 5/8" 5K BOP stack and pressure test BOP and wellhead as per BAPETCO policy. (be active and work on BOP studs loosening from stump bolts during cementing)

Rams 500 / 5000 psi

Annular 500 / 3000 psi

Note:

This is the first time that the new remote control panel will be used. Ensure all involved is aware about the set up and drills and procedures should be in place. Perform acceptance test as required.

22 R/U Gyro and conduct survey inside the casing.

23 Set the wear bushing and the lock the hold down flange lock down screws if required.

24 Check the bowl for the correct size to avoid casing hanger metal seal area damage and use DSAF with tie bolts to hold the wear bushing if required.

25 Lay down components from the 17-½” BHA that will not be required for the next BHA.

26 Install two gate valves on the C.H.H side outlets on each side.

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2.2 12-¼” Intermediate Hole Section from 1126 to 2562 m AHBDF

2.2.1General

1 The 12-¼” section will be drilled through Apollonia and Khoman to 2562 m AHBDF.

2 Section TD will be minimum 50 m into Abu Roach “A” formation. If A/R “A” formation comes deeper or shallower with the uncertainty +/- 50 m, then the casing setting depth will be shifted depending on the top A/R ”A” formation depth.

3 The 12-¼” section is planned to be drilled in single bit run with a PDC bit.

4 The section will be drilled with 9.2 ppg – 9.6 ppg water based polymer mud (0.48-0.50 psi/ft).(ensure to start section with only 9.2 ppg mud – any deviation from this need TBD with OD/2)

5 If the 13-3/8’’ casing pressure test was not achieved on bump plugs, then prior to drilling shoe track, close the BOP and pressure test 13-3/8” casing to 2000 psi. This should be agreed before attempting to pressure test casing.

6 Ensure that all drilling tools and equipment are on site and are in serviceable condition prior to drill out.

7 The 12-¼” hole will be drilled with 5” drill pipe back to surface. Ensure that all pipe picked up is accurately drifted, strapped and tallied.

8 The BHA should be inspected before drilling 12-¼’’ section.

9 The 9-5/8’’ casing will be 47 lb/ft, drifted to 8.525”. Ensure that the casing is drifted as soon as it arrives on location.

10 Ensure that 9-5/8” casing running tools and operators are available and the casing is tallied in good time prior to reaching 12-¼” section TD.

11 Ensure all material and equipment is on site and that water pit is full and waste pit empty before starting the section.

12 Check the ID of all downhole equipment for the passage of an FPI tool and survey instrument fishing tools.

13 A flow rate of 900-950 GPM should be sufficient to maintain good hole cleaning. Maximise flow rate throughout this section but be aware of inducing losses.(make sure that MWD orifice is built to sustain the mentioned GPM).

14 The 9-5/8” casing string will be run and cemented with lead and tail cement slurry (two slurries).


Samples to be collected every 5 m (from top Apollonia to top A/R “A” Mbr).



Potential Problems and Drilling Issues for 12 1/4” Section

Bit and stabilizer balling in top Apollonia with PDC bit reducing ROP.

Losses - Minor to moderate losses might be seen in Apollonia and Khaoman

Hard back reaming may be required after drilling while POOH (happen in all offset well and wiper trip required while drilling to reduce back reaming time)

Chert: Chert beds in Apollonia (can be up to 60%)

Mud foaming may be present while drilling the due to presence of CO2 in Apollonia and Khoman in the Sitra area.

Shale instability in Khoman A.

Page 27 of 47



Pump a surfactant pill with salt saturated mud pill to remove bit balling.

Ensure enough LCM and water on site.

Drill at reduced pump rate to avoid excessive losses.

Increase water loss while drilling to 10-15 in case of continuous losses.

Use CO2 scavenger and defoamer in mud proactively in case foaming is observed. . (Also use fresh water in preparation for fresh mud).

Use KCK polymer mud

2.2.2Drilling 12-¼” Hole Section

1 Hold a toolbox talk / safety meeting and ensure all personnel are aware of operations.

2 The 12-¼” hole section will be drilled with water based polymer drilling fluid. Ensure that the hole is switched to polymer mud prior to drilling out shoe track.

Note:

Water loss should be kept between 5-12 cc/30 min.

3 Ensure the wear bushing has been installed.

4 Make up the proposed BHA and RIH. Proposed BHAs for the 12- ¼” section are given below. Final BHA will be advised by Cairo office prior to drilling out the hole section.

BHA #1 – Rotary Assembly with PDC Bit

12 ¼” PDC Bit12 1/8” N.B.S1x 81/4” Pony D/C 12 1/8” String stab8” MWD12 1/8” String Stab9 x 8 1/4” Drill collars 8’’ JAR2 x 8 ¼’’ Drill collar XO15 x 5” HWDP

Note:

The BHA’s mentioned above are advisory but can be changed for good reason in liaison with Sr. Drilling Engineer and Drilling Engineer.

Report all tool offsets from bit in DDR (e.g. GR from bit, etc.)

Report all tagged depths in DDR (float collar, shoe, bottom of rat hole, etc.)

5 Wash down and tag TOC. Record tag depth.

6 Drill cement plugs and shoe track carefully observing for the pump pressure and weight indicator - report depths on the DDR (DSV/STP to be on rig floor while drilling plugs).

7 Drill plugs and shoe track carefully not to have plugs jammed which will create piston effect (DSV to be on rig floor).

8 Drill 5 meters new formation, pull back to shoe, condition mud in & out.

9 Perform FIT to 0.65 psi/ ft,(checked with the office) record data and send it to office.

Page 28 of 47


10 RIH back and Drill with controlled parameters until stab out of 13 3/8” CSG.

11 ensure mud has satisfied properties before apply max. parameters

12 Commence drilling 12-¼” hole to TD. Ensure that back up motor on site if trajectory shows significant increase in vertical section than max allowable planned (67 m as per attached trajectory).

13 It may be required to ream full stand while drilling to drop any building tendency.

14 If the ROP is lower than normal (<15 m/hr) with the bit at the start of drilling in Apollonia, then this might be due to bit balling. Pump a salt saturated mud pill and see if there is any increase in ROP.

15 It might be well shifted from vertical. Aim for max. ROP and well to be turned in 8 ½” hole to right trajectory if necessary.

16 Once top of A/R “A” is confirmed with formation samples and rig site geologist, drill at least 40 meters in A/R “A” formation to section TD at approximately 2608 m.

17 At TD circulate bottoms up until shakers are clean, Rotate at a minimum of 80 RPM (possibly okay to go to 120 RPM at section TD). Reciprocate the string to prevent washing a ledge.

18 At section TD, sweep hole with 100 bbl high viscosity pill to ensure the hole is clean. When circulating clean make sure that the shakers are clean before tripping. It may take a while for hole enlargement to stop.

19 Spot 150 bbls of Hi-vis pill on bottom before pulling out of hole to suspend and hold any cuttings / cavings minimising possible fill buying you time to get the casing in the ground.

Note:

Check cuttings at shakers while circulating. If carvings are present, action must be taken to cure them (i.e. increase mud weight) prior to POOH.

20 Strap out of the hole to run casing.

21 POOH whilst continuing to circulate at reduced rate to ensure string is kept full. Pump out of hole if required.

22 If hole condition is good on the trip out, do not make a wiper trip. Wiper trip only if hole condition dictates. Consult Cairo office prior to performing a clean out trip.

23 Pull wear bushing and rig up to run 9-5/8” casing.

POOH / Trip Procedures

1 When pulling out of the hole use ½ BHA weight as a maximum overpull before you go back down away from the tight spot.

2 When pumping out of hole apply the same guidelines as regular pulling out of hole.

3 If any signs of packing off are observed or string cannot pass upwards after overpull or the string does not freely drop off after taking an overpull – go down, start the pumps and increase the pump rate slowly and rotate at 100 rpm+. Make sure that the hole is cleaned properly and no cuttings are coming over the shakers before attempting to pull out again.

4 Sweep with a hi-vis pill only if the pressure and torque are normal otherwise a pack-off can occur.

5 Pump out of hole with half the drilling rate flow rate to avoid a pack off occurring. The hydraulic effect of pressure is quite pronounced and can push the string further into a sticky area if a temporary pack-off has occurred.

6 If there are excessive cavings while pumping/back reaming out of the hole, clean the hole before continuing POOH and getting into any tight spots.

7 Back ream out with great care; avoid over pulls, monitor torque and pressures for signs of packoff.

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2.2.39-5/8” Casing Running & Cementing

The 9-5/8” casing shoe is to be set at approximately 2660 m AHBDF using a top and bottom plug.

The 9-5/8” casing will be run with a two joint shoe track. Baker lock the shoe track connections.

Swab / surge calculations should be performed to ensure that the planned running speed does not result in formation breakdown (by SHELMBERGER / WSDE / ECS unit).

Send cement and water sample to Halliburton prior to casing job.

The Drilling Supervisor shall verify pump volumes with cementing company prior to pumping.

The 9-5/8” casing will be cemented in place with 25% excess on open hole using 12.5 ppg lead slurry and a 15.8 ppg tail slurry (will be reviewed before the job and final recipe will be send by Halliburton).

Top of cement at 1500 m BDF or to cover the shallowest HC zone if any.

9-5/8” Casing Specifications


47 lbs/ft L80 VAM TOP 6858 psi 4756 psi1086

Klbs

15900

ft-lb8.681” 8.525”

0.07320

bbl/ft


THS Test Pressure 3000 psi* Casing hanger (“S”) & THS seals (“FS”), ring joint, & side

outlets outlet

Preparation

1 Ensure all 9-5/8” casing running and handling equipment is present and has been checked with backups and is in good conditions (check that SAPESCO check list is completed correctly).


3 Clean all connectors using non-metallic brush and solvent or high pressure steam gun. If this is done more than 48 hours prior to running the casing, threads should be lightly oiled to prevent corrosion.

4 Drift and tally casing (drifted to 8.525"). Calliper a minimum of 10-15% of the ID of the casing. Send final tally to Ops Engineer to check and confirm.

5 Joint numbers are to be marked on the casing. Take extra casing off pipe racks after the casing tally is prepared by the drilling supervisor.

6 Visually check the float shoe and float collar joints to ensure no debris inside.

7 Check that floats are non-rotating type.

8 Visually check the condition of cement plugs and report any notes.

9 Send cement and water samples to Halliburton in advance.

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10 Perform and compare cementing calculations (SHELMBERGER and Bapetco). When calculating displacement volumes, take volumetric efficiency of mud pumps into account.

11 Test and confirm volumetric efficiency of rig and cementing unit pumps (also refer back to previous cement jobs for estimates of mud pump efficiency). Report volumetric efficiency results in the DDR.

9-5/8” Casing Running

1 Hold toolbox talk / safety meeting to review the operational requirements for casing prior to the start of job. Ensure all personnel understand their roles and responsibilities.

2 Driller should have a final version of the casing tally and check off joints as they are

3 DSV / WSDE to be witness entire casing running & cementing operating.

4 Rig up casing running equipment (power tongs, etc)

5 After the float collar joint has been made up, check the float equipment is clear by filling shoe track with mud and picking up to ensure that casing drains.

6 Run centralizers as follows:

two centralizer per joint for shoe track.

One per two joints for first 10 joints.

One per 5 joints to TTOC.(almost 1500 m). Then none to surface.

Note: centralization may be changed up on hole condition.

Note:

Fill casing every 3 – 4 joints to avoid casing ‘floating’ in elevators and to ensure an adequate overbalance is maintained. Monitor hook load to ensure string does not ‘float’. This will require every joint initially to prevent float.

Monitor casing running speeds. Ensure that the speed does not exceed the maximum value calculated by surge calculations. Check rig alignment with BOP first 10 joints it may cause POSS fill up tool ( NO-GO plate) to stuck in the casing collar.

Monitor gains/ losses.

7 Break circulation prior to 9-5/8” casing entering open hole.

8 Continue running casing to casing setting depth.

Performance improvement: Aim to achieve 19 joint/hr for running casing.

9 Wash down the last two joints of casing.

10 Slack off last 3 meters slowly. Land slowly and carefully the casing hanger through BOP in the casing head housing.( take all the precautions not to damage the hanger seal during this process).

11 Ensure the casing is landed with circulation. Drain stack prior to landing and route the returns via the side-outlets.

Record the string weight just prior to landing the hanger in the housing.

12 Once landed pressure test the hanger to 1000 psi if casing mandrel hanger is used. (Double check that the side out let is open not to induce losses at this step).

13 Establish circulation and circulate a minimum of one complete circulation. Monitor returns while circulating to ensure no losses. If hydrocarbons have been seen in the section then it would be prudent to circulate the full annulus volume.

Note:

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If there is any possibility that debris has been lost down the casing while making up and running, circulate a minimum of the entire casing string volume (i.e.100%) to ensure that the float is clear prior to commencing cementing operations

Make sure annular velocities are no higher than the planned cement displacement rate (approximately 5 BPM - stage up to this value to lessen the potential of inducing losses).

Do not exceed the ECD’s seen during the drilling phase.

9-5/8” Casing Cementing

The return and displacing tank arrangements are to be planned before cement mixing commences. Pump strokes alone are not accepted as sufficiently accurate to be used as the sole method of displacement volume measurement




1 Rig up cementing equipment and cementing lines while circulating.

2 Inspect plug loading head prior to loading

3 Pick up and install plug loading (SCHLUMBERGER rep to supervise).

4 Load top and bottom plugs in cement plug loading head. DSV to witness and verify loading of plugs.

5 Pressure test cement head and lines to 5000 psi.

6 Zero rig and SCHLUMBERGER cementing unit pump strokes.

7 Pump Fresh water spacer ahead as per SCHLUMBERGER recipe.

8 Stop pumping spacer and release the bottom plug. SCHLUMBERGER rep to supervise and DSV / WSDE to witness.

9 Mix and pump lead and tail cement as per cementing programme.


11 Once the cement has been pumped, release the top plug. SCHLUMBERGER representative to supervise and DSV / WSDE to witness.

12 The cement will be displaced with mud. Stop pumping from the cement unit, switch the cement line at the cement head manifold and continue displacing with cement pumps.

13 Displacement rate (consistent with not inducing losses) to be advised prior to job.

Note:

Pump strokes alone are not accepted as sufficiently accurate to be used as the sole method of displacement volume measurement.

The displacing volume must be measured from the mud tanks (or cement tanks if cement unit is being used).


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14 Frequent checks should be made on the mud tanks throughout the displacement to ensure that the volume being used compares with the rate of displacement.

Ensure the mud-logging unit monitors and records all displacement volumes and pressures.

15 Slow the pumps down immediately prior to bumping the plug (recommend slowing down at theoretical plug bump assuming 100% volumetric efficiency) and record differential pressure. If the cement thickening time is approaching, ignore this and continue displacement until the plug bumps.

16 Theoretical top of cement is plan at 1500 m BRF.

17 Bump the plug at slow pump rate. If the plug does not bump when expected, limit over displacement to ½ shoe track volume. (consult with Cairo office)

Note:

Make sure volumetric efficiency of pumps is taken into account in calculation of theoretical displacement volumes.

18 When the plugs bump, pressure up and test casing to 3000 psi (i.e. 3000 psi absolute pressure, not 3000 psi over plug bump pressure). Note and record volume required reaching test pressure.

19 Bleed off pressure and check operation of float equipment. Re-bump plugs if float valves fail to hold; maintain static differential pressure until the cement sets sufficiently to prevent backflow, or until the surface samples set.

20 Release the pressure and check for backflow.

21 Nipple down BOP, install and test the THS. If an emergency slip and seal hanger is set, test same before lifting BOP’s. (be active and assemble THS and back up DSAF prior to N/U with reasonable time and loosen DSAF nuts).

22 Lay down 12-¼" BHA.

23 Nipple up BOPs.

24 Pressure test hanger/well head and BOP system.

Rams 500 / 5000psi

Annular 500 / 3000 psi

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2.3 8-½” Main Hole (Reservoir) Section from 2562 m to 3420m AHBDF

2.3.1General

1 The 8 ½" reservoir section will be drilled vertically to 2600 m then start directional work from 2600 to well T.D. @ 50 m in Kharita TD at ± 3420 m AHBDF

Directional Plan: Will start kick-off @ 2600 m which will be in A/R formation build-up to 26 deg. With 2.5 max. dogleg Then holding to well T.D.

2 The target tolerance is 75 m radius for Baharyia rectangular.

3 TD criterion is defined as 50 m in KHARITA formations.

4 The section will be drilled with 0.48-0.53 psi/ft HYDRO GUARD SYSTEM from start to section TD. In case of Diesel shortage & couldn’t use OBM

5 Ensure that all drilling and coring tools, BHA components (including crossovers) and equipment are on site and are in serviceable condition prior to drill out.

6 If a successful casing pressure test was not achieved on plug bump, close the BOP and pressure test 9-5/8” casing to 3000 psi prior to drilling shoe track. Consult Cairo office before attempting to pressure test casing.

7 The 8-½” hole will be drilled with 5” drill pipe back to surface.

8 Ensure that all pipes that is picked up is accurately strapped and tallied (there is a +/- 70 mTVD uncertainties in the 8 ½’’ formation tops and TD.

9 Check the ID of all down hole equipment for the passage of an FPI tool and survey instrument fishing tools.

10 No R.O.P limit has been set, but careful monitoring of cuttings returns and connection overpull is important to prevent stuck pipe and pack-off incidents.

16 A flow rate of 600 GPM should be sufficient to maintain good hole cleaning. Maximise flow rate throughout this section. (make sure that MWD orifice is built to sustain the mentioned GPM).

11 The 7” liner will be run and cemented with 15.8 ppg cement slurry (final recipe will be issued before the job).


Samples to be collected every 2m from top A/R “A” to well T.D.



Potential Problems and Drilling Issues

Hard formation / low ROP abrasive formations (base of Bahariya and Kharita).

Unable to complete section due to complete loss (low possibility)

The Abu Roash “G” formation can be very reactive and sale sloughing can occur. However as the section will be drilled with hydro guard, so these problems are not expected.

Possibility of heavy losses due to sever depletion in A/R formations and Bahariya.

Unable to reach the proposed TD in case of encountering sever losses in case of setting the 7" liner to cure a shallower losses (did not happen in offset wells)

Differential sticking

High drilling torque and drill string failure.

Potential twist offs.

Running and cementing 7” liner.

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Ensure mud is kept in good condition.

Do not allow the mud weight to drift up and keep LG solids as low as possible.

Circulate prior to connection to move cutting far enough from BHA to avoid settling while connection.

Ensure that the string is not left stationary across the stands for more than 1-2 minutes while taking survey or while connection with rotate the pipe in the slips if any indication of sticking while preparing next stand, keep close control of torque.

Monitor the hole for any signs of sticking, over pull while picking up, high torque while starting and keep watch the off BTM torque.

If over pull is encountered during connections, push the string down. If string does not get free and the string become stuck then immediately apply max torque to the string. If string is still not free then set down max weight while holding torque (Driller must be aware to take required action until DSV & TP come to rig floor).

While POOH of the initial over pull should be limited to a maximum of 30 Klbs of ½ of the BHA weight in mud , if 30 Klbs reached then the string should be moved down some distance (1 stand or a single ) and circulation of cutting bottoms up should be performed.

If ultimately the problems are so severe that the back reaming is the only way to get the string out of the hole so to limit the annulus cutting concentration to the same as when it was drilled we can only back ream out of the hole with max 2 or 3 stands per hour.

Before POOH circulate 3 bottoms up with a pump rate of min 500 GPM, rotate pipe at a minimum of 80 RPM.

In case of not bad hole condition, Perform wiper trip to 9 5/8” CSG shoe and RIH again to check hole condition. Experience from the area that hole is good after check trip which minimize problems while running W/L logging.

Ensure drill pipe & BHA components are inspected and do not exceed the minimum inspection requirements without prior approval from town.

2.3.2 Drilling 8-½” Hole Section 1. Hold a toolbox talk / safety meeting and ensure all personnel are aware of operations.

2. Ensure the wear bushing has been installed.

3. Make up the proposed BHA and RIH. Proposed BHAs for the 8-½ ” section is given below. Final BHA will be advised by Cairo office prior to drilling out the hole section.

BHA #3 8-½” Directional Assembly

8-½” PDC BIT 6 3/4” Low speed Motor.7 3/4” stab 6 ½” MWD / LWD6 1/2” x.over3 x 6-½" Drill Collars1 x 6-½" Jar2 X 6-½" Drill Collar

X/O 21 x 5” HWDP

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Notes:

The BHA mentioned above is tentative. The final BHA will be advised prior to drilling out the casing in liaison with Sr. Well Engineer and / or the Drilling Engineer (ODD/2 or ODD/X).

Make sure that motor assy are on site as back up.

Report all tool offsets from bit in DDR (e.g. GR from bit, etc.)

Report all tagged depths in DDR (float collar, shoe, bottom of rat hole, etc.)

4. Make up and RIH with the 8-½” BHA. Wash down and tag TOC.

5. Drill out shoe track meanwhile displace well to HYDRO GUARD SYSTEM .(ensure fresh mud is at bit before entering rat hole).

6. Drill 5 meters new formation, pull back to shoe, condition mud in & out.

7. Perform FIT to 0.7 psi/ ft, record data and send it to office. (checked with the office)

8. RIH back and Drill with controlled parameters until stab out of 9 5/8” CSG.

9. ENSURE MUD HAS SATISFIED PROPERTIES BEFORE APPLY MAX. PARAMATERS (circulate if needed).

10. Continue drilling the 8-½” hole to TD +/- 3420 m AHDBDF (50 meters in KHARITA formation).

11. OPTIMIZE ROP TO HAVE ONLY RECORDED DATA FOR LWD NO NEED FOR REAL TIME DATA.

12. It was noticed in offset wells building tendency in the south west direction. Reaming twice every stand helps to minimize the building tendency (refer to SITRA 8-19 reports).

13. At TD circulate hole clean a minimum of three bottoms up or until shakers are clean. Spot some hi viscous pill on bottom if required.

Note:

Check cuttings at shakers while circulating. If cavings are present, action must be taken to cure them (i.e. increase mud weight) prior to POOH.

14. Conduct a rotational check and record the surface torque with the bit just off bottom at rotary speeds of 10, 15 and 20 rpm. Repeat this process with the bit at the planned 7” liner hanger position (torque readings taken at this point will be referred to as the “drilling” cased hole torque). Report on DDR.

15. In case of not bad hole condition, Perform wiper trip to 9 5/8” CSG shoe and RIH again to check hole condition. Experience from the area that hole is good after check trip which minimize problems while running W/L logging.

16. Consider dropping the spare Hydril dart to drift the drill pipe on the last trip out of the hole to ensuring passage of liner cementing dart. If a drift or the dart is not dropped on the last trip out of the hole, the 5” drill pipe will have to be drifted as it is run. All drill pipe, pups, and crossovers that will be run with the liner must be drifted.

17. Pull out of hole to run logging.

18. Strap the drill pipe on the last trip out of the hole to ensure that the drill pipe tally is up to date prior to running the liner. It is essential that the liner TD is accurately known.

19. Prepare to run wire line logs. Hold a tool box / safety meeting prior to rigging up for logging and commencing logging. Ensure all personnel understand their roles and responsibilities.

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i. Log 8-½” Hole Section

W/L Open hole logs

GR /Resistivity /Neutron/Density.

GR/RDT (Samples are optional).

GR/Image. (Optional).

Sonic (Optional).

Check shots (Optional).

LWD Open hole logs (optional)

LWD will be required in case of using water base mud to drill the 8.5’’ section to overcome bad hole conditions.

• GR /Resistivity /Neutron/Density.• LWD GeoTap pressure points (optional in case of using LWD instead of W/L).

Note: a detailed logging programme will be issued prior to the logging job.

1 Rig down Halliburton.

2 Pull wear bushing and rig up to run 7” Liner.

3 ½” handling equipment should be on location while logging in case plug back is required.

Clean out trip may be required prior to running casing if calliper log indicates or if hole conditions dictate (if overpulls are recorded during logging).

MAKE SURE THAT YOU SENT CALL OUT FAX TO HALLIBURTON LOGGING ONE WEEK IN ADVANCE.

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ii. 7” Liner Running & Cementing

7’’ 29 lb/ft, L-80 VAM Top liner will be run from +/- 3578 mAHBDF through the reservoir to at least 100 meters overlap inside the 9-5/8” casing.

The liner string will be run on a Baker hydraulic set rotating liner hanger c/w bottom wiper plug and a retrievable pack-off bushing. The assembly will be run with an integral “ZXP” tie back packer (ZXP will be confirmed later).

A three joint shoe track will be run.

Note:

This is a generic liner programme – A separate detailed and updated liner running and cementing programme will be sent prior to the job.

7” Liner / Casing Specifications


29 lbs/ft L80 VAM Top 8160 psi 7030 psi 676 Klbs9400

ft-lb6.184” 6.059”

0.03714 bbl/ft


THS Test Pressure 3000 psi* Casing hanger (“S”) & THS seals (“FS”), ring joint, & side

outlets outlet

Preparation

1 Swab / surge calculations should be performed by WSDE to ensure that the planned running speed does not result in formation breakdown.

2 Construct a drag chart (e.g. using Well Plan - BAPETCO WSDE / Baker or Weatherford) based on actual coefficient of friction values from previous trips.

3 Ensure all liner running and handling equipment is present and has been checked.


5 Clean all connectors using non-metallic brush and solvent or high pressure steam gun. Dry connectors using compressed air. If this is done more than 48 hours prior to running the casing, threads should be lightly oiled to prevent corrosion.

6 Drift and tally liner. The 7” casing is to be drifted to 6.059” for the 29 lb/ft, L-80 casing.

7 Produce independent liner running tallies (WSDE / BAKER checked by the DSV).

Note:

Do not set the liner top packer within 2-3m of a 9-5/8” casing coupling.

Run a pup joint, positioned in the liner string so as to be 30m (TBA after agreement / discussion with PE) above the top of reservoir. This pup joint will act as a marker for any future logging runs (make sure at least 3 pup joints are available on the rig).

8 Joint numbers are to be marked on the casing.

9 Take extra casing off pipe racks after the casing tally has been compared.

10 Visually check the float shoe and float collar joints to ensure there is no debris inside.

11 Ensure that the liner shoe depth and float collar depth has been agreed with town.

12 Perform and compare cementing calculations (Halliburton and Bapetco). When calculating displacement volumes, take volumetric efficiency of mud pumps into account.

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13 Test and confirm volumetric efficiency of rig and cementing unit pumps (also refer back to previous cement jobs for estimates of mud pump efficiency – report volumetric efficiency results in the DDR.

14 Prepare the plug dropping head. Check operation of the flag sub and mark “open” and “closed” position on flag. Baker / Weatherford hand to supervise and DSV to witness. Ensure the drill pipe pump down plugs is installed in the correct sequence.

15 Check lengths, ODs and IDs of all liner hanger equipment and running tools.

16 If required, liner hanger tool representative should adjust the anti-rotation pins in the hanger spacer sub / cone.

17 Check the compatibility of the setting ball and shear out seat and the free movement of the ball through the wiper plug system. Also check the compatibility of the liner wiper plug system with the DP darts and the liner grade being used.

18 Check the condition of the ZXP packer element and the number of packer shear pins.

19 Check the HR liner running tool release pressure +/- (TBA) psi standard shear and that it is locked inside the tie back extension. Check on the inspection drawings that the H.R. running tool has been supplied with two mechanical release pins (TBA) ft. Lbs. Left Hand torque.

20 Final 7” Liner running and setting procedures will be sent separately before the job.

7” Liner Running

Hold toolbox talk / safety meeting to review the operational requirements for casing prior to the start of job. Ensure all personnel understand their roles and responsibilities.

Driller should have a final version of the casing tally and check off joints as they are run.

Do not rotate while RIH unless unable to pass down.

Only check rotation for 2 mins while circulation on BTM before CMT job every 0.5 hr.

Commence rotation only when pumping cmt and stop last 20 bbl from displacement.

DSV / WSDE to be witness entire casing running & cementing operating.

Note:

a) A three joint shoe track will be run.

b) Prior to picking up the first joint, count the number of liner joints on the pipe rack.

Do not install the TIW valve if it has a square shoulder, as a precaution not to damage the plug while dropping.

Direct contact between the rig floor and the cement unit during releasing the plug. Do not pump cement after releasing the plug release to insure there is no excessive cement behind the plug.

Swivel must be rotationally checked prior to installing it.

Do not reverse circulation if plugs didn’t pump.

If there is no clear indication from the flag sub that the plug is released, break the cement head and confirm that plug is released.

Do not proceed with any circulation (reverse or normal) if have any doubt that dart plug didn’t release.

Ensure that there is a backup dart plug on site. Check dart plug configuration before job, Dart plug to be loaded in rig site.

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1 Rig up liner running equipment (power tongs, etc)

2 After the float collar joint has been made up, check the float equipment is clear by filling shoe track with mud and picking up to ensure that casing drains.

Bakerlock shoe track. All connections, including casing collars to one joint above landing collar are to be Bakerlocked.

3 Run centralizers as follows:

2 x Spirolizer centralisers will be preinstalled on each of the 3 shoe track joints

Run one spriolezer/solid body centraliser per joint (will be reviewed depending on interested zones, hole conditions, standoff, etc)

4 Run liner as per tally, filling liner string every 3-5 joints (or every joint if this is considered to be more convenient) to avoid string floating in the elevators (more often initially).

5 Install liner hanger and ZXP packer after the last liner joint has been run.

Note:

Count number of liner joints remaining as a check on the number of joints run.

Be careful to keep the liner hanger centralised when running through the rotary to avoid damage to the packer element and hanger slips.

6 Leaving the casing slips set on liner joint, pick up 1 - 2ft to check if the setting tool and all other connections are made up properly.

7 Remove slips and lower hanger assembly and note liner weight. Be careful to keep the hanger centered while lowering through the table to avoid damage to the piston slips etc.

8 Lower hanger assembly through the rotary table and set the DP slips on the lift nipple, do not set slips on the setting sleeve.

9 Make up the first stand of drill pipe and break circulation with a maximum circulating pressure of 1000 (TBA) psi. Maximum allowable circulating rate prior to setting liner hanger is (TBA) 6/10 bpm. Record circulating pressures. Circulate liner contents.

Note:

Ensure total numbers of stands of drill pipe in the derrick are known before running in liner and that the number of drill pipe joints agrees with tally.

Check that drill pipe tally is accurate.

Ensure that the exact length of drill pipe to be run to put liner at TD has been calculated and checked.

Monitor weights closely when running hanger through BOP to avoid hanging up.

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10 Make up the first stand of drill pipe and break circulation with a maximum circulating pressure.

11 Run liner in hole on 5” drifted drill pipe, filling every 3 - 5 stands.

12 At the 9-5/8” shoe, break circulation slowly to break mud gels. Record pressure at various circulating rates up to (TBA) 6/10 bpm. Do not exceed (TBA) 1000 psi surface pressure. Visually monitor for leaks while circulating.

13 Take up and down weights, and circulate at the last casing shoe. If possible, check the torque of the liner inside the casing prior to running in the open hole section.

14 Break circulation every 150 m while running in open hole. Limit the maximum set down weight on the liner sleeve with the HR setting tool to (TBA) 100,000 lbs.

When running liner in open hole, wash down if required (with compensator open). Do not exceed (TBA) 1000 psi surface pressure or (TBA) 6-10 bbl/min flow rate.

Wash down slowly, as the dynamic (surge) pressure caused by running the liner will add to the effective pressure seen at the liner hanger.

If required the liner can be rotated to bottom. Maximum allowable torque will be the drill string cased hole torque + 80% of 7” casing make up torque (Check with Cairo office if any increase in torque is required)

15 Wash down last three DP stands to the liner setting depth. Keep circulating.

16 Space out drill pipe as required minimising surface stick-up while ensuring that packer is not set closer than 3 m to a 9-5/8” casing coupling.

17 Tag bottom and pull back 3 m. Note up and down weights.

18 Go back to liner setting depth.

19 Circulate and condition mud as required to reduce viscosity prior to cementing. Ensure shakers are clean.

20 Install Baker/Weatherford plug dropping head (drift any pup joints picked up for space out). Check setting of flag sub on cementing head.

21 Rig up cementing lines and test to 5000 psi against the kellycock.

22 Slowly break circulation. Do not exceed (TBA) 600 psi initially and gradually increase circulation rate to a maximum of (TBA) 1000 psi or (TBA) 6 bpm. Check string weight with and without circulation.

23 Circulate and condition mud as required to reduce viscosity prior to cementing. Monitor returns. Circulate bottoms up + 120% of string volume whichever is greater.

7” Liner Setting

1 When circulation is complete (check shaker clean), drop the setting ball.

2 Pump the ball down to the seat in the ST Landing Sub watch pressure gauge for pressure increase. During this time check the pickup and slack off weights, tag bottom and pick up to setting depth.

3 Pressure up to 2000 psi, hold for 1 minute, then bleed pressure to 500 psi and slack down liner weight plus 30 Klbs on the liner setting tool from the drill pipe.

If liner did not set, increase the pressure in 100 psi increments and repeat step above until reaching 3000 psi.

If liner still did not set change the setting position 3-4 feet in search for better host casing surface, then repeat above step.

If no success setting hanger then inform Cairo office prior to setting hanger on bottom. Set hanger on bottom and proceed with running tool releasing procedures.

4 Increase the pressure to +/-2500 psi and hold for 2 minutes. This will release the HR Tool.

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If liner did not release hydraulically, back up mechanical release with ¼ turn to the left of the tool will be applied to shear off at +/- 5200 ft-lb.

Note that the HR liner setting tool will not release until it is in compression, i.e. the liner must be set first.

If running tool didn’t release hydraulically or mechanically contact Cairo office.

5 Open bleed valve and keep it open, and check running tool is free by picking string up max 3 ft above D/P neutral weight.

6 Increase pressure slowly, to shear the ball seat with +/- 3600 psi (consult liner hanger technical data and tool representative). Record new up weight.

7 Set down 40,000 lbs of DP weight onto the liner hanger. Record new down weight. Establish circulation.

NOTE:

After the Liner Hanger and ball seat have been sheared out, circulation rates can be increased to 10 bpm and a minimum of one bottom up must be circulated prior to pumping cement.

If ball seat didn’t shear out, bleed pressure to zero and pressure up to 4000 psi. Repeat this procedure by bleeding to zero and pressuring up to last pressure value plus 500psi.

8 Pick up DP and set down a minimum amount of weight onto the liner and do a rotation test. Maximum allowable torque is drill pipe free rotating torque (measured during POOH at casing shoe) + 80 % of the optimum liner make up torque.

9 Slowly set down 30.000 lbs weight on top of the Liner Hanger (to compensate for pump out forces) and establish circulation.

10 Condition mud and rotate liner at 15 – 20 rpm, ensuring maximum applicable torque is not exceeded.

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7” Liner Cementation




The flow meter / stroke counter on the cement unit must be calibrated prior to the liner cement job.

Excess on cement slurry is to be (TBA) 15-35% on gauge hole volume plus the equivalent of (TBA) 50m above the top of the liner.

Cement calculations to be performed and cross-checked by DSV, WSDE, and Halliburton cementer.

Slurry will be batch mixed where possible as in previous programmes.

Continue rotating the liner during cementing job ensuring maximum applicable torque is not exceeded.

1 Line up to cementing unit and test surface equipment.

2 Pump spacer as detailed in the cement programme.

3 Release the first pump down drill pipe dart.

4 Mix and pump 15.8 ppg Class G cement slurry as per the cement programme.

5 Once the cement has been pumped, release the top plug dart from the cement head (cement line to the rig floor should still be full of cement).

Note:

DSV to witness the release of top dart from cement head. Displace dart down drill pipe using cement unit. Displace at a maximum pump rate.

6 Once the cement has been pumped, release the top plug dart from the cement head (cement line to the rig floor should still be full of cement).


Note:

Pump strokes alone are not accepted as sufficiently accurate to be used as the sole method of displacement volume measurement.

The displacing volume must be measured from the mud tanks (or cement tanks if cement unit is being used).

All preflush, spacer and cement displacement volumes and pressures should be independently monitored / recorded by the mud logging, cement unit and the drill floor.

8 Slow pumps down to 5 bbl before the first pump down dart reaches the wiper plug. The pump pressure will build up when the first pump down dart seats in the bottom wiper plug. Bring pump rate back up once bottom plug has sheared.

Note:

Use the flow meter / stroke counter on the cement unit to monitor cement displacement, with a visual tally of the volume pumped as a back-up.

Frequent checks must be made on the mud tanks throughout the displacement to ensure that the volume being used compares with the rate of displacement.

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A shear may be observed when the first wiper plug and drill pipe dart land on the landing collar.

9 Stop rotating 3-5 bbls before total displacement.

10 Slow the pumps down immediately prior to bumping the plug and record static differential pressure.

11 Bump the plug at slow pump rate. Bump plug with 1000 psi over final displacement pressure. Hold for 5 minutes.

Note:

If the plug does not bump when expected, limit over displacement to half shoe track volume.

Make sure volumetric efficiency of pumps is taken into account in calculation of theoretical displacement volumes

Record volume required to pressure up to (TBA) 1000 psi.

12 When the plugs bump, pressure up and test casing to 3000 psi (i.e. 3000 psi absolute pressure, not 3000 psi over plug bump pressure). Note and record volume required reaching test pressure.

13 Bleed off pressure and check for backflow. Leave the landing string open to atmosphere.

If floats do NOT hold, set ZXP packer, pull above TOL, flow check well.

If well still has back flow after setting the ZXP packer, reverse circulate till cement to surface and shut well in. Reverse circulating will provide additional ECD over conventional circulating in an attempt to keep additional pressure on the floats while cement sets.

14 Set ZXP packer by pulling the running tool above the ZXP packer tieback extension to activate the spring loaded dogs. Establish rotation at 20 – 30 rpm then move the tool down to set 60,000 lbs weight on the packer to shear pins to set packer element.

If there is no indication that Dog sub has set then P/U string 5-6 feet and rotate at 50 rpm for 2 minutes. Slow down to 10 rpm and slack off 60,000 lbs.

If there is no success landing Dog Sub on packer then repeat the above step with 80 rpm and 100 rpm if required.

15 Pull back 5-10 meters and reverse circulate out cement.

16 Pressure test liner to 3000 psi in leak off mode with 500 psi steps.

17 Separate running and cementing programme will be sending before the job.

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b. Completions Program

A separate completion program will be issued for running the tubing and installing X-Mas tree prior to job.

Note: the proposed material will be needed based on the proposal

W.L.E.G., XN-Nipple, 7” CS Packer, SSD for Jet pump installation, Seating Nipple for Sucker Rod

pump installation., Tubing to surface (3 1/2" CS, 9.2 Ib/ft & L-80 tubing).

8.5” Section directional Plan

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Risk Assessment

The following risks have been identified for the drilling phase only. Days to recover from each particular incident (i.e. NPT) have been estimated and a cost generated from this based on an all inclusive spread rate of $30,000/day plus casing/mud/cement cost if necessary. A probability for each incident has been estimated based on the field experience.

1. Problem:

Corrective Action:

Days NPT: 1 days

Slow 17-1/2” hole ROP (< 10 m/hr)

Continue drilling to TD. Do not plan bit change unless ROP unacceptable (< 5 m/hr).

NPT Cost: $50,000 Probability: 0.05

2. Problem:

Corrective Action:

Days NPT: 2 days

Unable to get 13-3/8” casing to TD

Make a wiper trip before running the casing and increase MW before pulling out (losses permitting). Depending on how deep the casing and if the casing can be pulled, the decision will be taken by Cairo to either pull casing out of hole, make wiper trip and increase MW or to cement casing in place and drill ahead to next TD.


3. Problem:

Corrective Action:

Days NPT: 1 days

Slow 12-1/4” hole ROP (< 10 m/hr)

Continue drilling to TD. Do not plan bit change unless ROP unacceptable (< 5 m/hr).


4. Problem:

Corrective Action:

Days NPT: 2 days

Unable to get 9-5/8” casing to TD

Make a wiper trip before running the casing and increase MW before pulling out (losses permitting). Depending on how deep the casing and if the casing can be pulled, the decision will be taken by Cairo to either pull casing out of hole, make wiper trip and increase MW or to cement casing in place and drill ahead to next TD.


5. Problem:

Corrective Action:

Partial losses in Apollonia

In case of partial losses in 12 ¼” hole, continue drilling whilst pumping LCM. If the losses are greater than 150 bbls/hr, may be required to POOH and set cement plugs depend on the hole condition

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Days NPT: 1 days

.


6. Problem:

Corrective Action:

Days NPT: 2 days

Partial or Total losses in Apollonia

In case of partial or complete losses, spot LCM pills and continue drilling.


1. 7. Problem:

Corrective Action:

Days NPT: 1 days

Slow 8-1/2” hole ROP ( < 10 m/hr )

Optimise hydraulics and bit choice. Consider different BHA design.


2. 8. Problem:

Corrective Action:

Days NPT:1 day

Losses in AR “F” and cannot drill to Kharita. Set casing and Drill 6” hole and set 4” liner.

Pump LCM to cure losses. Set cement plug if losses cannot be cured with LCM.


9. Problem:

Corrective Action:

Days NPT: 2 days

Unable to get 7" liner to bottom

In order to reach the objectives of this well it is critical that this liner is run to bottom. Ensure a wiper trip is done prior to running liner.


10. Problem:

Corrective Action:

Days NPT: 3days

Major rig equipment failure (e.g. mud pump, top drive, etc.)

Repair as required.


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Documents

ALMagd C-86-C Drilling Program v1