Drilling Program MSSM01 280808 SPUD Rev00

DRILLING PROGRAM

MSSM-01

Prepared by: Drilling Engineer : M. Fadil _

Yudie Prayogo _

Sr. Drilling

Engineer

: Saridjo Ronowikarto _

G & G : Indra Hudaya __

P E : Tri Firmanto

_

Reviewed

by:

Drilling

Superintendent

: Raden Sularso _

Drilling Engineering Manager : Eddy Sutrisna _

Approved

by: Head of Drilling : Edi Sutriono

_

Sr. Manager Engineering & Planning

: T. Zulfikar _

Sr. Manager Exploration

: Arif Wibowo _

Revision / Issued Record :

Revision Date Comment

DISTRIBUTION LIST

WELL NAME : MSSM-01

KONDUR PETROLEUM S.A :

- Drilling Manager- PE Manager- Prod.Eng Manager- Well Service Manager- Sr. Eng & Plan Manager- Sr. Exploration Manager

Kondur Petroleum S.A Drilling Program MSSM-01 Rev 00 Page 1 of 66

- File MSSM-01


TABLE OF CONTENTS

TABLE OF CONTENTS..................................................................................................................................... 2

MANAGEMENT GUIDELINES......................................................................................................................... 4

DATA OF MSSM-01 WELL............................................................................................................................... 5

1 GENERAL DATA........................................................................................................................................ 6

1.1. STRUCTURE............................................................................................................................................. 61.2. OBJECTIVE.............................................................................................................................................. 71.3. FORMATION TOP...................................................................................................................................... 8

2 WELL PLANNING AND DRILLING PROGNOSIS...............................................................................10

2.1. INTRODUCTION...................................................................................................................................... 102.2. GENERAL DRILLING PROGRAM AND DESIGN...........................................................................................112.3. ZONE OF INTEREST, FORMATION PRESSURE AND FRACTURE GRADIENT...................................................152.4. CASING SETTING DEPTH........................................................................................................................ 162.5. MUD PROGRAM..................................................................................................................................... 182.6. WELLHEAD............................................................................................................................................ 182.7. BOP STACK.......................................................................................................................................... 192.8. PRESSURE TESTING................................................................................................................................ 192.9. BIT PROGRAM....................................................................................................................................... 202.10. CEMENTING PROGRAM....................................................................................................................... 202.11. ELECTRIC LOGGING PROGRAM...........................................................................................................212.12. CUTTING SAMPLING........................................................................................................................... 212.13. MWD/LWD...................................................................................................................................... 212.14. DIRECTIONAL SURVEY...................................................................ERROR! BOOKMARK NOT DEFINED.2.15. DRILLING HAZARD............................................................................................................................. 23

2.14.1 Shallow Gas Sands Pressure.......................................................................................................... 232.14.2 Shale Stability............................................................................................................................... 232.14.3 Low Leak-Off Tests........................................................................................................................ 232.14.5 Pipe Sticking................................................................................................................................. 232.14.6 Toxic Environments (H2S or Other Dangerous Gases)..................................................................23

3 DRILLING PROCEDURE........................................................................................................................ 24

3.1 RIG MOVE AND PRE-SPUD..................................................................................................................... 243.2 PRE-SPUD MEETING............................................................................................................................... 253.3. 20" DRIVE PIPE..................................................................................................................................... 253.4. DRILLING 17 ½” HOLE FOR 13 3/8” CASING...........................................................................................263.5. DRILLING A 12 ¼” HOLE FOR 9 5/8” CASING.........................................................................................303.6. DRILLING 8 ½” HOLE FOR 7” LINER.......................................................................................................343.7. ABANDONMENT PROGRAM..................................................................................................................... 37

4 SAFETY, HEALTH, ENVIROMENT AND SOCIAL REPSONSIBILITY.............................................39

4.1. PRE-JOB MEETING................................................................................................................................. 394.2. RIG INSPECTION..................................................................................................................................... 394.3. PRE-SPUD INSPECTION........................................................................................................................... 394.4. BOP TESTING/DRILL............................................................................................................................. 404.5. HYDROGEN SULPHIDE (H2S)/FLAMMABLE GASES..................................................................................404.6. SIGNPOSTING......................................................................................................................................... 404.7. SMOKING/IGNITION SOURCES................................................................................................................. 404.8. HOT WORK........................................................................................................................................... 414.9. CONFINED SPACE WORK........................................................................................................................ 414.10. HAZARDOUS SUBSTANCES.................................................................................................................. 414.11. DANGEROUS CIRCUMSTANCES............................................................................................................ 414.12. SAFETY MEETINGS............................................................................................................................. 414.13. PERSONAL PROTECTIVE EQUIPMENT...................................................................................................424.14. BREATHING APPARATUS TRAINING....................................................................................................43


4.15. FIRE.................................................................................................................................................. 434.16. ACCIDENT/INCIDENT REPORTING........................................................................................................ 434.17. MAN HOURS WORKED....................................................................................................................... 454.18. ALCOHOL AND DRUGS....................................................................................................................... 45

ATTACHMENT................................................................................................................................................ 46

ATTACHMENT 1: LOST CIRCULATION.....................................................................................................47ATTACHMENT 2: TRIPPING PROCEDURE.................................................................................................54ATTACHMENT 3: WELL CONTROL............................................................................................................56ATTACHMENT 4: ON SITE DRILLING TEAM RESPONSIBILITIES..........................................................58ATTACHMENT 5: CASING DESIGN...........................................................................................................62ATTACHMENT 6: MUD PROGRAM............................................................................................................. 63ATTACHMENT 7: CEMENTING PROGRAM..................................................Error! Bookmark not defined.


MANAGEMENT GUIDELINES

EMP MALACCA STRAIT (KPSA) IS COMMITED TO CONDUCTING ALL DRILLING RELATED ACTIVITIES IN A SAFE, PRACTICAL AND COST EFFECTIVE MANNER. IT IS RECOGNIZED THAT CONTINUOUS CHANGE IS NECESSARY TO IMPROVE THE DRILLING PROCESS. IDEAS AND RECOMMENDATIONS FOR IMPROVEMENT ARE WELCOME FROM ALL PARTIES INVOLVED IN THIS PROCESS.

THIS DRILLING PROGRAM IS TO BE USED AS A GUIDANCE ONLY. CHANGES CAN AND SHOULD BE MADE IN RESPONSE TO ACTUAL WELLBORE CONDITIONS.


DATA OF MSSM-01 WELL

Well Name : MSSM-01

Well Classification : Exploration

Drilling Rig : 550 HP Rig

Drilling Contractor : SPA-07

SurfaceWell Coordinates

: Northing : 115 983.21 mN Easting : 210 054.26 mE Lat : 1° 02’ 54.031” N Long : 102° 23’ 40.197” E

Sub-SurfaceWell Coordinates

: Northing : 115 983.21 mN Easting : 210 054.26 mE Lat : 1° 02’ 54.031” N Long : 102° 23’ 40.197” E

Primary Objectives : Upper SihapasLower Sihapas

Secondary Objectives : Menggala

Proposed TD : 3,208.7 ft ss +/- 200 ft

RT Elevation : +/- 44 ft

Ground Elevation : +/- 26.6 ft

Estimated Time (AFE) : 29 days

AFE Number :08-00003

AFE Amount :US$ 2,443,755.00

1 GENERAL DATA Kondur Petroleum S.A Drilling Program MSSM-01 Rev 00 Page 6 of 66

The MSSM structure is located in the Padang Fault Thrust Zone in the western side of Melibur Structure. MSSM is a three way dip fault dependent closure that lies in the Padang Thrust Fault Zone, in the western side of Melibur Anticline. Structurally, the closure is strongly controlled by the Padang Thrust Fault, trending NW-SE direction as a result of reactification of older basement-involved faults.

The main objective of MSSM-01 well is to test the hydrocarbon bearing potential of the Upper and Lower Sihapas Formation. The trap of this section is dependent upon fault seal. In addition to that, the stratigraphic trap is exhibited by the strong amplitude anomaly and “a cup of palm arm” reflections character of 3D seismic in PSTM volume also in PSDM volume. The secondary objective was to test the Transition and Menggala Formation. The MSSM-01 well will be TD at depth of 3,250 ft on Basement Section.

In 2007, a petrophysical study was taken to determine the possible recoverable reserves and to optimize the development of such reserves. The study resulted an appropriate petrophysical model which will be used in the next geological and reservoir study. The result has been used in all geological mapping and reservoir evaluation for MSSM structure in Melibur Field, including geological mapping, STOOIP calculation.

The well will be drilled vertically with common drilling practices in the Malacca Strait PSC with specification is similar with MSCM-01 well or any other wells in Melibur Field. An access road is around 0.3 km from the Melibur-Kurau junction road to MSSM-01 Drilling Site.

Based on the technical and economical evaluations it is concluded that the MSSM-01exploration well is feasible to drill. The MSSM-01 Well would provide a recoverable oil of 0.832 MMSTB, produced at initial oil rate of around 400 BOPD.

MSSM-01 is proposed to drill and produce Sihapas Sand with TD at 3,252.7 ft MD

1.1. Structure

The prospect is a fault dependent three way dip closure within the Padang Thrust Fault Complex. The sub-thrust fault throw in the Sihapas level is seen to be effective in the trapping hydrocarbon along this trend. The Padang Thrust Fault System which is trending northwest-southeast, strongly controls the trapping mechanism in the prospect.

Mapping exercises show that the closure remain observable down to the Menggala level. The presence of intra-formational shale within the targeted zones, support the MSSM structure to be an effective hydrocarbon trap and it has been proven in The Melibur Field. MSSM-01 prospect is predicted to have different OWC with the other compartement in Melibur.

Stratigraphy of SM area consists of formation from Transition Sand through Minas Sand, which is inferred from all MSSM-01 wells with the succession as follow:

Petani and Minas Formation


Sihapas Group: Telisa Formation

Sihapas Formation

-Upper Sihapas Member

-Lower Sihapas Member

Transition Formation

Menggala Formation

Basement

Detailed predicted section for the proposed infill well MSSM-01 can be seen in Figure 1.3.

1.2. Objective

MSSM-01 well is a vertical exploration drilling well in Kurau Field with target to find gas and oil in Lower Sihapas Formation. The primary objectives are Lower and upper Sihapas sands and secondary target is Menggala formation. The well will be vertically drilled with proposed TD about 3,252.7 ft MD.

FIGURE 1.1 WELL MAP


FIGURE 1.2 WELL LOCATION

1.3. Formation Top

Formation TopSubsea

(ft)

Depth(ft TVD RT)

Depth (ft MD KB)

44 44

Petani Formation 650.50 694.50 694.50

Telisa Formation 1,231.30 1275.30 1275.30

Upper Sihapas Sand Formation 1,749.74 1793.74 1793.74

Lower Sihapas Sand Formation 2,191.66 2235.66 2235.66

Menggala 2,698.56 2742.56 2742.56

Pematang 2,886.63 2930.63 2930.63

Basment 3,208.70 3252.70 3252.70


FIGURE 1.3PREDICTED SECTION


2 WELL PLANNING AND DRILLING PROGNOSIS

2.1. Introduction

The offset well of MSSM-01 is MSCM-01, MSJ-57 and MSCN-01. The casing design of offset well will be different, Minas formation will be covered early by 13-3/8” casing due to its uncosolidate sand properties. The 13-3/8” casing was set bellow top Petani formation, 9-5/8” casing was set on top of Upper sihapas and 7” liner will set on TD of the well.

MSCM-01 SummaryThe well was spud on 7 January 1991 and rig was released on 27 January 1991. Reached a total depth of 3,070 ft in 8-1/2” hole section of Menggala formation. The primary objecetive of this well is to test the “Melibur A and B” also “Juliet” sands. The well was also planned to test the sands of Menggala formation.

The 14” casing was pre driven and set at 149 MD. The 12-1/4” hole drilled to 1272’ (9-5/8” casing point) using 8.5 ppg mud. IEL-LSS-SP-GR-UGR log was run in the well. Unable to pass 275’. R/D HLS. RIH with bit for wiper trip. Circulate and ream from 280’-319’ continue RIH to 1272’. Circulate hole clean and POOH (no tight spot). R/U HLS. Unable to pass 275’ with tools. Remove centralizers and caliper tool. Same result. R/D HLS. RIH with bit, wash and ream from 270’ to 380’ (unable to wash down without reaming). Spot hi-vis pill in hole. POOH to log. R/U HLS. Unable to pass 275’. R/D HLS. RIH w/bit for wiper trip prior to run casing. RIH to 1272’ (no fill). Circulation hole clean, POOH. Run 9-5/8” casing 40 ppf, K-55 to 1264’. Necessary to wash casing down from 350’-470’ and from 510’ to 590’. Break circulation and attempt to reciprocate without success. Circulate well clean with full returns. Pump 50 bbls fresh water spacer followed by 540 sxs class “G” neat cement (60% excess) at 15.8 ppg. Displace cement with 98 bbls mud. Plug did not bump at theoretical displace at 93 bbls. Had full returns throughout job and 15-20 bbls cement to surface.

Drill 8-1/2” hole 15 ft new formation to 1287’. Perform LOT with result is 14.1 EMW. Continued drill to 1547’ (coring point) using 9.1 ppg mud. Nine coring job were perform at range depth 1547’ to 1783’. Trip gas was occur 565 units at 1605’ and 50 units at 1635’. Continue drilling to 2711’. Bit torquing up. POOH to 2051’. Well swabbing RIH to 2667’. Wash fill to 2711’, circulate clean hole. POOH to 1841’. Well swabbing. RIH to 2711’. Circulate clean hole and POOH. No Swabbing. Continue drilling to 3070’. Four wire line logging were run in the hole. They are DLL-MSFL-GR-CAL-SP, CDL-CNL-GR, LSS-GR, and SHDT.

The well was Plug and Abandoned. The plug cemented from 2450’ – 2200’, set balanced cement plug from 1365’ to 1065’, and 400’-200’ with 15.8 ppg cement slurry.

During drilling, shows were encountered at several levels, but on log and sidewall cores no indication of significant hydrocarbon accumulation were encountered in the primary target. However, the thin oil zone was encountered in the basal part of the lower sihapas formation. The oil is trapped in the fault-independent closure on the chrest of fault block.


MSJ-57 Summary

The MSJ-57 shallow well was spud on 4 July 2000 and rig released on 09 July 2000. The 9-5/8” conductor was pilled to 167 ft. The MSJ-57 is shallow well with only 8-1/2” hole section drilled to total depth is 1235 ft. Even the MSJ-57 is the nearst location from MSSM-01 there are unsufficient drilling data recorded while drilling this well.

MSCN-01 Summary

The well was spud on 5 January 2006 and the rig was released on 25 January 2006. Reached a total depth of 2,984 ft in 9-5/8” hole. The main objective of this well is to test hydrocarbon content at Sihapas and Menggala reservoir.

The 20” casing was pre driven until 147 ft MD. The 17-1/2 hole begin to drill using KCL PHPA mud with 8.6 ppg until 487 ft, and increased the weight to 9.1-9.3 ppg until reach 13-3/8” casing point at 1505 ft MD. the drill was stop due to geological reason and decided to set casing at depth 1470 ft MD. The 13-3/8”, K-55, 54.5 ppf casing run and set at 1470 ft MD and cemented with 12.5 lead sllury 280 bbls and 69 bbls 15.8 ppg tail slurry.

The 12-1/4” hole section begin with drilled to 1515 ft or 15 ft new formation. The leakof test was perform using 8.8 ppg mud and resulted 12.99 ppg EMW. Continued drilling 12-1/4” hole using KCL-PHPA mud until reach depth 2357 ft MD, the top transition zone was found at 2308 ft. Drilling continued to 2460 ft MD using KCL PHPA with mud weight 8.8 to 8.9 ppg and found ROP slow (25-30 fph) expected menggala formation was drilled, stop the drilling and circulate and flow check. Static loss 0.45 bbl/mnt, mix and pump wall nut to the circulating system until mud loss stop. The LCM was spoted before POOH string to surface and the stabilizer should cleaned from cutting. After make up new BHA drill continue to TD at 2984 ft MD using KCL-PHPA 8.8 ppg mud and flow check-static loss = 0.07875 bbls/min. Mix and pump wall nut to the system, circulate and spot wall nut around the annulus before POOH bit. Four kind of logging tools were running in MSCN-01 well: 1#Super Combo (SP/GR/CNL/LDL/MSFL/DT/LLD-LLS), 2#MDT-LFA to take pressure and sampling fromm E-1, E-5, E-12, D2B and take pressure only from E-4, E9 sand. 3# CST Tools, and 4# VSP.

Different casing setting depth will be applied on MSSM-01 from previous MSCN-01 well. The 13-3/8” casing will set at top of petani formation (+/- 10 ft intrusion) at estimate 694 ft MD to cover minas formation. The 9-5/8” casing will set at top of upper sihapas estimate at 1793 ft MD to prevent explosure reactive clay formation. The 8-1/2” hole The 7” casing will set at TD 3495 ft.


2.2. General Drilling Program and Design

Note: All depths are referenced KBEstimate GL Elevation 27 ft.

RT-GL 44 ft.

The MSSM well program assumes 19 days will be required from spud until the well is completed. A proposed drilling time versus depth curve for MSSM-01 is shown in Figure 2.2. The casing program is shown in the Figure 2.1

TABLE 2.1MSSM-01 WELL DESIGN

Casing

(in)

Hole Size

(in)

Depth ft

MD KB / TVD

Mud Weight

(ppg)

LOT EMW

(ppg )

20 Driven 181.8 NA NA

13 3/8 17 ½ 694 8.8 – 9.2 12.50

9 5/8 12 ¼ 1,793 8.8 – 9.5 13.00

7 8 ½ 3,252.7 8.8 – 9.0 -

TABLE 2.2KICK TOLERANCE

Hole Size (inc)

Depth

(ft TVD KB)

Last Casing (inc)

Shoe Depth

(ft MD KB)

LOT (ppg)

Max. Mud Weight (ppg)

Kick Size

(bbls)

Max Annulus

Circ Press

Kick Tolerance

ppg

12 ¼ 1,793 13 3/8 +/- 694 12.50 9.5 10 108 0.5

8 ½ 3,495 9 5/8 +/- 1,793 13.00 9.0 10 354 1.1


FIGURE 2.1MSSM-01 WELL DIAGRAM


FIGURE 2.2 TIME VERSUS DEPTH

0.00

500.00

1,000.00

1,500.00

2,000.00

2,500.00

3,000.00

3,500.00

4,000.00

0 2 4 6 8 10 12 14 16 18 20Days

Dep

th

$-

$500,000.00

$1,000,000.00

$1,500,000.00

$2,000,000.00

$2,500,000.00

$3,000,000.00

US

$


2.3. Zone of Interest, Formation Pressure and Fracture Gradient

FIGURE 2.3PORE PRESSURE AND FRACTURE PRESSURE (Depth is TVDKB)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

5.00 6.00 7.00 8.00 9.00 10.00 11.00 12.00 13.00 14.00 15.00

PPG

Dep

th

pore productive pressure

mud pressure 1

mud pressere 2

LOT

u

Kondur Petroleum S.A Drilling Program MSSM-01 Rev.00 Page 16 of 64

TABLE 2.3MSSM-01 DEPTH ZONE OF INTEREST

Formation TopSubsea

(ft) Depth

(ft TVD RKB) RKB

Depth (ft MD KB)

Upper Sihapas Sand Formation 1,749.74 1,793.74 1,793.74

Lower Sihapas Sand Formation 2,191.66 2,235.66 2,235.66

Menggala 2,698.56 2,742.56 2,742.56

2.4. Casing Setting DepthTABLE 2.4

CASING PROGRAMME

Casing Size

Hole Size

Depth

(ft MD KB)

Weight (ppf)

Grade Thread Remarks

20” - +/-181.8 1” wtPile Pipe

Weld On Drive 3-4 jts casing below cellar.

13 3/8” 17 1/2” +/- 694 54.5 K-55 BTC

Set 40-50 ft below top of PETANI shale at 650 ’SS +/- 50’ as determined by lithology from Offset Well. This casing is set to cover Minas and Petani formation and give casing integrity to drill next section.

9 5/8” 12 ¼” +/- 1,793 43.5 K-55 BTC

Set on top of Upper Sihapas sand est.at 1,749’SS +/- 50’. This casing is for isolate Telisa formation. The TD of this casing will be dictated by hole condition, MW and previous LOT by Kick of tolerance calculation.

7” 8 1/2” +/- 3,253 26 L-80 BTC Liner set as production liner to cover primary and secondary target.


TABLE 2.5CASING DESIGN LOADS - BURST LOADS

Casing Weight (lb/ft)

Grade From (ft MD KB)

To (ft MD KB)

Burst Loading

(psi)

Burst Rating(psi)

Safety Factor

13 3/8” 54.5 K-55 Surface +/- 694 450 2,730 6.079 5/8” 43.5 K-55 Surface +/- 1,793 1244 3,950 3.18

7” liner 26 L-80 +/-1,593 +/- 3,252 2900 8,160 2.81Casing Burst Pressure Design Parameter13 3/8” Fully evacuated and fluid gradient with pore pressure at external profile9 5/8” Fully evacuated and fluid gradient with pore pressure at external profile

7” liner Internal Case : Pressure test and green cement pressure test. External Case: Fluid gradient with pore pressure. Production load: Injection down casingj

TABLE 2.6CASING DESIGN LOADS – COLLAPSE LOADS



To (ft MD KB)

Collapse Loading

(psi)

Collapse Rating

(psi)

Safety Factor

13 3/8” 54.5 K-55 Surface +/- 694 397 1,130 2.859 5/8” 43.5 K-55 Surface +/- 1,793 627 2,570 4.10

7” liner 26 L-80 +/-1,593 +/- 3,252 1827 7,020 3.84

Casing Collapse Load Design Parameters13 3/8” Full/Partial Evacuation. External: Fluid gradients with pore pressure9 5/8” Lost return with mud drop. External:mud and cement slurry

7” liner Drilling Load: Cementing . Production Load: Full Evacuation. External: Fluid Gradient with pore pressure

TABLE 2.7CASING DESIGN LOADS - TENSION LOADS



To(ft MD KB)

Mud Weight(lb/gal)

Axial Loading (1000 lb)

Body Strength(1000 lb)

Safety FactorAxial /

Triaxial13 3/8” 54.5 K-55 Surface +/- 694 9.0 346 909 2.639 5/8” 43.5 K-55 Surface +/- 1,793 9.6 213 714 3.35

7” liner 26 L-80 +/-1,593 +/- 3,252 9.0 187 490 2.62Tension Design Parameters All tension calculations are based on 100 klb overpull force, green cement

pressure test and service loads


2.5. Mud Program

TABLE 2.8MUD PROGRAM

Drilling Fluid Specifications

MUD PROPERTIES 17 ½” 12-1/4” 8 1/2” Completion

Mud TypeGel-KOH Spud mud

7% KCL/PHPA

7% KCL/PHPA (Less damaging Fluid)

KCL-Brine

Interval, ftMD Surface –

Mud Weight 8.8 – 9.2 8.8 – 9.5 8.7 – 9.0 8.4-8.7

Funnel Viscosity (FV) 40 – 60 40 – 60 40 – 60 -

Plastic Viscosity (PV) < 20

( ALAP)

< 20

( ALAP)

<16

( ALAP)

-

Yield Point 25 - 30 20 – 24 20 – 24 -

Gel strength (10”/10’) >5 / < 14 4-6 / 6 – 14 2-4 / 6 – 10 -

Solid Content < 6 ≤ 12.5 ≤ 6 ≤ 6

API Fluid Loss < 8 ≤ 6 ≤ 6 -

HTHP Fluid Loss @2500F

NC NC<10 -

MBT ≤ 10 ≤ 12.5 ≤ 12.5 -

pH 8.0 – 9.0 9.0 -9.5 9.0-9.5 8.0

Chloride TBA > 34000 > 34000 > 25000

Total Hardness < 200 < 200 <200 -

2.6. WellheadTABLE 2.9

WELLHEAD

SectionCasing

SizeBottom Top Description

20” 20” 2M SOW 21 ¼” 2M Flange Top Starting Head

A 13 3/8”13 3/8” Slip on weld bottom

13 5/8” 3M Flange Top conn.

FMC Starting Head

B 9 5/8”13 5/8” 3M flange bottom

11” 5M Flange TopFMC Casing head spool


2.7. BOP Stack

TABLE 2.10BLOWOUT PREVENTION EQUIPMENT

CasingPressure Rating

Description

20” 2000 21 ¼” 2M Spool, 21 ¼” 2M Diverter, 21 ¼” 2M Annular

13 3/8” 5,00013 5/8” 5M BOP; Spool 13 5/8” 5M flange top x 13 5/8” 3M flange btm, Blind rams, Pipe rams, Annular Rams

9 5/8” 5,00013 5/8” 5M BOP; Spool 13 5/8” 5M flange top x 11” 5M flange bottom, Blind rams, Pipe rams, Annular Rams

7” 5,000 As above

2.8. Pressure Testing

TABLE 2.11PRESSURE TESTING SCHEDULE

Casing String

Setting Depth

(ft MD KB)

Plug Bump (psi)

Seal Assembly

(psi)

Pipe Rams (psi)

Blind/Shear Rams (psi)

Annular (psi)

Surface Equipment

(psi)

20” Conductor 182 NA NA NA NA NA NA

13 3/8” Surface 694 500 over 2000 300/2000 300/2000 300/2000 300/2000

9 5/8” Intermediate

1,793 1000 over 2000 300/5000 300/5000 300/3500 300/5000

7” Production 3,252.7 1000 over 2000 300/5000 300/5000 300/3500 300/5000

Note:• Pressure tests shall be proceeded by a low pressure test of 300 psi for five (5) minutes. High pressure

tests to be 10 minutes duration. Chart recorder shall be used for all tests, signed and submitted with the daily reports.

• Routine BOP test frequency shall be fourteen (14) days, or on the first bit trip after this period has elapsed.

• The contractor is responsible for maintaining an auditable record of pressure tests for all equipment including safety valves. These records are to be provided to the Operator prior to spud.

• The plug bumping pressures, when and if annulus packers are used and set, are subject to packer set-up which will be determined when actual depths and mud weights are known.

2.9. Bit Program


TABLE 2.12BIT PROGRAM

Hole Size Bit type IADC Type Nozzle Size

17 ½” 17 1/2” Rock Bit 1-1-5 Reed T11 TBA

12-¼” 12 ¼” Rock bit 2-1-7 HP21G TBA

8 1/2” 8 ½” Rock Bit 5-3-7 TD-53 APDH TBA

6” 6” Rock Bit 1-1-7 SL62DH 20 x 20 x 20

2.10. Cementing Program

TABLE 2.13CEMENTING PROGRAM

Hole Size 17 ½” 12 ¼” 8 ½”

Open Hole Excess 100% 100% 35% Caliper

Slurry Type Lead Lead

Interval (MD-BRT) Surface – 500 Surface – 1,493

Weight 12.5 ppg 12.5 ppg

Slurry Yield (cps) 2.12 2.77

Free Water < 1% < 1%

Thickening time >4 hrs >4 hrs

Compressive Str 800 psi in 24 hrs 800 psi in 24 hrs

Slurry Type Tail Tail Tail

Interval (MD-BRT) 500-694 1,493-1793 1,493-3,252.7

Weight 15.8 ppg 15.8 15.8

Slurry Yield (cps) 1.15 1.52 1.54

Free Water Nil Nil Nil

Thickening Time >2 hrs >2 hrs >3 hrs

Compressive Str 2,500 psi in 24 hrs 2,500 psi in 24 hrs 2,500 psi in 24 hrs

Gas Block if required

The detailed cementing programme will be provided by the cementing company. Cementing tests will be conducted with water and cement samples from the rig to confirm additives and

thickening times

2.11. Electric Logging Program


TABLE 2.14LOGGING PROGRAM

HOLE SIZE TOOLS DESCRIPTION REMARK

17 ½” Hole N/A

12¼ ” Hole N/A

8 ½” Hole 1. TRIPLE COMBO

2. DT SONIC

3. MDT

4. SWC

5. VSP

9-5/8” & 7” Liner 1. CBL-VDL-CCL-GR

2.12. Cutting Sampling

TABLE 2.15CUTTING SAMPLING

Hole Size 17 ½” 12 ¼” 8 ½”

Interval 50’ 30’ 10

Bulk 1 set 2 set 2set

Washed and Dried Nil Nil 3set

Geochemical Nil Nil 1set (50’)

2.13. MWD/LWD

TABLE 2.16MWD/LWD PROGRAM

HOLE SIZE TOOLS DESCRIPTION REMARK

17 ½” Hole N/A

12 ¼” Hole N/A

8 ½” Hole N/A


FIGURE 2.5WELL SUMMARY


2.14. Drilling Hazard

2.14.1 Shallow Gas Sands Pressure

The well program assume there is no shallow gas sand pressure in Minas Formation, however the proper diverter will be installed prior to drilling this formation. The next sands formation will be encountered after set 9 5/8” casing where the BOP has been installed. The drilling crew should be ready for any gas kick/potensial gas flow in this well.

2.14.2 Shale Stability

The shale sections in offset wells were drilled with 5% KCL-PHPA without any significant hole problems. Minor problems with tight hole wiper trip were experienced which was corrected with an inrease in mud weight.

2.14.3 Low Leak-Off Tests

The leak-off test (“LOT”) at each casing seat is critical for the well design. If the LOT does not meet minimum casing design requirements consideration will be given to squeezing the shoe until an adequate LOT is achieved or the maximum available LOT is determined. The next casing setting depth will be dependent on the LOT achieved, the ECD and the mud weight required.

2.14.4 Loss Circulation

The loss circulation may be encountered. The treatment of loss circulation should be depending on the type of losses. The drillers have to be prepared to pick up immediately if losses occur and commence filling the annulus with reserve mud. The drill string should be reciprocated and rotated to avoid packing off. Extreme care to prevent getting stuck if total losses occur. The drilling supervisor and Mud Engineer should ensure the availability of LCM on-site.

2.14.5 Pipe Sticking

There may be problems with tight hole that is caused by the swelling clays or unconsolidated shale. The potential of sticking the drill-string is high so if tight hole is encountered while wiper trips and increased mud weight will be used. The utilization of Black Magic/MillFree/EZ Spot mud chemical has been recommended to get free pipe.

2.14.6 Toxic Environments (H2S or Other Dangerous Gases)

There is no significantly hazardous levels of H2S and CO2 have been recorded during testing the Pematang sands formation, but Operations will be suspended / terminated in the event that conditions are considered unsafe due to toxic gas.


3 DRILLING PROCEDURE

The Drilling Procedure is to be used as a guidance only. Changes can and should be made in respond to actual drilling conditions. Proposed changes to the program should be made only after consultation with the Senior Drilling Supervisor, Senior Drilling Superintendent with the approval of the Drilling Manager/KPSA Well Service Manager.

3.1 Rig Move and Pre-Spud

1. Inspect and ensure the Rig equipment has been completed and in good condition for drilling the all section based on the contract equipment list.

2. Well Control refresher is a mandatory for Drilling supervisor, Rig Superintendent, Tool pusher, Driller and Assistant Driller. It will be conducted by DSS on KPSA behalf.

3. The 21 ¼”-2M Diverter or 21 ¼”-2M Annular Preventer shall be tested on the supplier workshop and withness with Company Representative prior to send to rigsite.

4. Hold Pre Job Safety meeting prior to rig move from previous well.

5. Mobilize the rig to MSSM-01 surface location.

6. Ensure the supply of drill water from the water wells or river to mud pit is sufficient, at minimum 8 bpm.

7. Ensure enough stock of mud chemicals, barite and cement at rigsite.

8. Ensure physically the complete of wellhead equipment including test tool, wear bushing and its retrieve/running tool, adapter spool, seal, ring gasket, etc are available on the rig.

9. Ensure with Rig Superintendent the wellhead drawing or BOP stack up for wellhead flange/clamp sizes and pressure ratings. Ensure all BOP related equipment, spools, adaptors, ring gaskets, etc required for BOP stack up are available on the Rig. Ensure on the required space below rig floor the maximum height of BOP stack up.

10. Ensure the integrity of the well site including its drainage, water wells and cutting pits.

11. Ensure float valves of all sizes of BHA are non ported types. It will be the policy of this well for all BHA’s to use a non-ported float.

12. Rig up and conduct proper function test for rig pumps, pump lines, mud pits and its lines, mud mixing system, all solid control equipment (shale shakers, desander, desilter, mud cleaner and centrifuges), rotary table and top drive. Calibrate the rig pump and calculate its efficiency.

13. Pressure test rig pump, pump lines, stand pipe manifold, rotary hose, swivel, Kelly, Kelly cock (upper and lower) to minimum of 3,000 psi – 10 minutes.

14. Mobilize 13 3/8” casing and its accessories from the yard to rig site.


15. Rig up and function test cementing units and its lines, cement silos, cement cutting and bulking systems.

16. Rig and all third parties equipment/personnel will not go on operating rate until KPSA drilling supervisor is satisfied that their equipment are rigged up properly and tested, and the sufficient drill water supplies are available on the rig

17. Mix 11.0 ppg Kill Mud in reserve pit and 8.7 ppg Fresh water-Gel-KOH mud in active system. Ensure the mud is sufficiently sheared before spudding well.

18. Prepare and send sample of cement, cement additives, and water for slurry lab.test, also initial mud to ELC division in Jakarta. Ensure that cement, cement additives and water samples are taken from same sources as materials to be used in the upcoming job. The onsite cementer shall pilot test thickening time of proposed slurry prescriptions for a section and report the result to KPSA Driling Supv.

19. Write in Daily drilling report for the well record with the following data; RKB – Ground Level (GL) Spud date and time Rig Heading GL-Mean Sea Level (MSL) Final Well Coordinate (Geodetic and UTM)

3.2 Pre-Spud Meeting

A prespud meeting will be held in Company’s office and on the rig site prior to spudding the well by the Drilling Manager and KPSA Well Service Manager. Prior to spud, perform MIGAS checklist and inspection. Ensure that all of safety issues has been addressed to HSE contractor, KPSA and DSS.

3.3. 20" Drive Pipe

20. A 20" conductor pipe has been driven approximately 150-175’ deep.

21. Cut 20” conductor above the ground, do not cut below the ground. (cut based on calculation maximum height of BOP’s).

22. Weld on casing swage 20” SOW x 21 ¼”-2M Flange to accept 21 ¼” Annular/Diverter system.

Note: All item above need to be done before rig move to location

23. Nipple up the 21 ¼”-2M Annular Diverter System complete with min 150’ of 2 x 10” diverter lines equipped with pneumatic/automatic valves. Function test diverter bag, and all associated valves for automatic operation. Pump water through both lines to flush. After making required rig inspection, fill in D.M.G.B. Rig Safety Check List. Record times of closing Preventer and opening Diverter valves.

NOTE: Prior to drilling any section of hole, the Senior Drilling Supervisor, Contractor Rig Superintendent will hold a safety meeting with the mud engineers, cementer, mud loggers, toolpushers, drillers and rig crew in attendance. The drilling hazards, casing point, anticipated formation pressure, mud weights and the operational procedures to be followed will be reviewed.

3.4. Drilling 17 ½” Hole for 13 3/8” CasingKondur Petroleum S.A Drilling Program MSSM-01 Rev.00 Page 26 of 64

Note:

Drilling will penetrate 40-50ft below top of petani formation. Petani formations are known as predominantly reactive shale/clay and probably over-pressured. Offset wells experienced sloughing shale and significant rheology increase due to characteristic of these formations. The first few hundred feet to drill will most likely be sand.

No indication of shallow gas possibility on seismic interpretation for Minas Sand formation.

Be ready with 120 bbls 11.0 ppg Kill Mud.

Never close the well or never close 21 ¼” Diverter and diverter line at the same time at any condition. During killing procedures, if required, must continues pump kill mud/mud/water and divert the flows thru opened Diverter Line to the air/cutting pit.

If the gas presence, stop drilling and circulate until all gas circulated out. Stop pump and observe for flow.

o If no flow: continue drilling.o If there is a flow;

Open diverter valves, close diverter, and pump kill mud with higher rate, 500 GPM min.

Continue drilling with kill mud.

If the well kicks, open Diverter Valves and close Diverter and pump kill mud with 500 GPM min until the well is dead. Mix additional 11.0 ppg kill mud if required. If the kill mud is run out, continues pump water with 500 GPM min until the well is dead.

Use 2 pumps to drill with mud and line up 1 pump to water pits in case continues killing or pumping water to the well with 500 GPM is required. Fill up all unused pits full with water before spud.

During the trip out of hole, pump out of hole and pull slowly to avoid swabbing.

1. Make Up 17 ½” Rock bit and 60’/90’ Pendulum BHA consisting of 17-1/2” Rock bit, bit sub with FV, 2x 8” DC , 17-1/2” String Stab, 1x 8” DC, 17-1/2” String Stab, 2x 8” DC, X-O sub, 1 x 5“ HWDP, 6-1/4”Jars, 10x 5” HWDP Up. Clean out 20” conductor to 175’.

2. Drill vertical hole to top of Petani Marker at +/- 694’ MD, ream each stand prior to making a connection, use Hi-Vis sweeps to clean hole as required. Flow check, 5 min. The casing seat depth for 13 3/8” casing should be 40-50ft below top Petani formation. The wellsite geologist and G&G from Jakarta office will advise the setting depth.

Drilling Parameters: 600-800 gpm, 5-15 Klbs, 90-120 RPM Control ROP to optimize hole cleaning by circulating at maximum rate as

specified in drilling parameter. Sweep hole with 30 bbls of 80 sec/qt Hivis every 3 stands when drilling 17 ½”

hole, only if required.


Mud Engineer must control mud properties, make adequate dilution. Utilize 0.1 gpb of mud detergen to minimize bit balling and KCL-PHPA treatment for any shale/gumbo problem.

Take survey at casing point with TOTCO tool and any point if required. Run centrifuges continuously to maintain low gravity solids as low as

possible. Maintain PV 10-20 (or as low as possible). Increase mud weight as required to 9.2 ppg to run casing.

3. At TD, circulate hole clean, sweep Hi-Vis, wiper trip and backream to 20” shoe, flow check at shoe, RIH back to bottom, sweep Hi-vis, drop carbide, circulate. Flow check, 5 min. Drop totco survey. Pump out of hole to surface for casing ( flow check-5 min at shoe and prior BHA pass through Diverter).

Drilling supervisor, tool pusher/rig superintendent must on the rig floor during pulling out of hole operations until bit is up in casing string.

Mud Engineer must control mud properties, make adequate dilution. Utilize 3 ppb Soltex on mud system when experience with gumbo or reactive shale.

Do not leave the hole open too long. Work to fill up and to run 13 3/8” casing as soon as possible but not to induce surging.

Observe and monitor wellbore while drilling and tripping for any shallow gas presence and other anomaly.

4. Rig up 13 3/8” casing handling tools and fill up tool and run 13 3/8" casing as follows :

Description NoLength

(ft) Setting

Depth (ft) Weight

(ppf) Grade Connection

Total Depth 694 20” Float shoe 1 2 692 54.5 K-55 Float shoe x btc box

20” Casing 1 40 652 54.5 K-55 BTC pin x box

20” Float collar 1 2 650 54.5 K-55 BTC pin x box

20” Casing 17 680 -30 54.5 K-55 BTC pin x box

Note:

a) Bakerlok the first five joint.

b) Check the integrity of float equipment.

c) Ensure that all casing has been rabbit with proper size.

d) Run Bow centralizer 3’ above shoe and at top of jt #2, #4 and #6 and 1 ea every five joint. And 1 rigid centralizer to position around wellhead area. Minimize centralizer utilization to reduce tight hole while run casing.

e) Fill up casing every five joint if the fill up tool is unavailable.

f) Circulating swedge must be available on rig floor.

g) The optimum torque of 13 3/8” casing is 5000-6000 ft.lbs. Check triangle mark for the first 10 jts while making casing connection.

h) Be prepared to wash the casing to bottom but use extreme care not to stick the casing as the 13 3/8” casing setting depth is critical to the success of the well

i) The good primary cement job on 13 3/8” casing is critical for the LOT


5. Circulate to clean and condition hole for cementing (break circulation slowly and increase periodically until AV around casing similar with while drilling). Check for any gas to surface. Reciprocate casing while circulating if possible. circulate minimum of one casing volumes and lower mud rheology. Take final circulating temperature.

6. While circulating, conduct a pre-job meeting with all parties involve to discuss action items and contingencies.

7. R/U Cementing lines. Flush cement lines with water, rig up lines, break circulation and test lines to 2500 psi for 5 mins.

8. Release bottom plug

9. Cement 13 3/8” casing as per program using 12.5 ppg lead slurry and 15.8 ppg tail slurry

The slurry should be re-tested on location prior the cementing job

The Tail slurry column length around 200’ from the proposed casing shoe and followed by Lead slurry until the surface. Using 150% excess for open hole or 30% excess volume by carbide lag check or depend on well condition (TBD).

Reciprocate casing about 10-15 ft during cementing job if possible

10. Release top plug and follow by 2 bbls tail slurry and 10 bbls water. Continue displace with mud as per program.

11. Bump plug with 500 psi over final pump pressure, hold for 5 minutes. If plug does not bump plug with calculated displacement, the maximum displacement should not exceed theoretical volume to float collar plus ½ shoe track volume.

12. Bleed off pressure and check floats holding. Open the side outlet casing head valve, and flash out the diverter packet and casing head from any access/contaminated cement.

Mud Engineer should check weight of contaminated cement

13. Monitor 20” x 13 3/8” annulus for fluid level drop. WOC until sample cement gets hard.

14. Pick Up 21 ¼” Divereter, rough cut 13 3/8” casing, L/D excess casing, N/D Diverter. Cut off and dress 13 3/8” casing. Install 13 3/8” SOW Casinghead x 13 5/8” 3M flange top, pressure test seals to 1,000 psi - 10 min (80% of 13 3/8” casing collapse resistance). Install spacer spool and DSA, NU 13 5/8” BOP. Do a top job on the annulus if required, weld annulus cover (20”x 13 3/8”) complete with 2” bleeder valve

The final level of wellhead should be positioned based on the maximum height of BOP’s on next section

Stack up and test all Wellhead Adaptors, BOP’s, choke manifold on line as much as possible to reduce the drilling time.

15. RIH and set test plug. Pressure test BOP as per program.

Ensure housing outlets are opened before testing BOP’s.

During test BOP, prepare 7% KCL-PHPA for next section.

16. Retrieve test plug and set wear bushing.



3.5. Drilling A 12 ¼” Hole for 9 5/8” Casing

Note:

7% KCL-PHPA will be used to drill this section. Mud Engineer need to control the quality of this mud including the KCL content not less than 7% and the solid content is not excessive. Add into mud system with 3 ppb of Soltex when encountered more reactive shale.

Optimize hole cleaning, circulate at maximum rate as specified in the drilling parameters. Optimize the shaker screen sizes applicable for the flow rate and max.allowable solid content in mud. Optimize mud cleaner with 200 Mesh screen and centrifuges.

Sweep hole with 30 bbls of 80 sec/qt Hi-Vis every 500’ drill, only if required.


Do not leave the hole open too long

Mobilize 9 5/8” casing and its accessories from the yard to rig site.

Avoid swab and surge pressure.

Vital to maintain hole full at all the times. Gas zones in upper sihapas may open in this section

Petani and Telisa formations are known as predominantly reactive shale/clay and probably over-pressured. Offset wells experienced sloughing shale and significant rheology increase due to characteristic of these formations

There is a possibility of gas sand bed in bottom of Telisa formation

1. Make Up 12 ¼” Rock Bit and stif BHA consist of 12-1/4” Rock Bit, 12” NB Stab w/FV, 1 x 8” DC, 12-1/4” String stab, 1 x 8”DC, 12-1/4” String stab, 3 x 8”DC, XO, 1 x 5” HWDP, 6-1/2” Jar, 10 x 5” HWDP . RIH to top of cement.

Optimize hydraulic for good hole cleaning and bit horse power.

Use larger jets in case LCM are needed to cure losses.

2. When Rock bit close to top of cement, run slowly and tag gently to avoid bumping and breaking of rock bit’s inserts.

3. Drill out cement inside 13 3/8” casing . Pressure test casing to sufficient pressure for performing LOT. Ensure the pressure are not more than casing burst rating pressure. Cont.drill out cement to shoe.

Increase mud to 8.8 ppg.

Slowly penetration around shoe to avoid back out shoe joint.

Max. WOB 2-6 klbs. Min. 80 RPM.

4. Drill 10’ new formation. Circulate hole condition with 8.8 ppg mud. Perform Leak of test.

Perform LOT using cementing unit with maximum rate 0.25 bpm and record the pressure taken from the low ranges gauge.

Prepare to squeeze the shoe if LOT value is below 12.5 ppg. Call Jakarta for the LOT result.


Plot LOT in pore pressure plot and based on this data make assessment of the kick tolerance at ~ 1,793 ft MDKB/ 1,793 ft TVD-BRT (propose 9 5/8” casing shoe).

5. Drill 12 ¼” vertical hole to 1,793 ft MDKB.

Note: While drilling 12 ¼” hole

Drilling parameter 700-800 GPM, WOB 5-25 Klbs, 80-100 RPM. Final drilling parameter will be advised by Bit technician specialist and discussed with drilling supervisor.

Control ROP to prevent overloading the annulus with drill cuttings which could induce stuck pipe or loss of returns.

Increase mud weight as required

Sweep hole with 30 bbls of 80 sec/qt if required.

Short trip if required.

6. Circulate hole clean. Wiper trip (pump out of hole or slow back ream if required) to shoe, flow check-5 min and RIH back to bottom. Circulate and drop carbide. Pump out of hole to shoe. Flow check – 5min. Drop totco survey. POH to surface (Flow check-5 min prior BHA pass through BOP).

Drilling supervisor, tool pusher/rig superintendent must on the rig floor during pulling out of hole operations until bit is up in casing string

Circulate with 800 GPM, twice bottoms up

Reduce mud viscosity if considered necessary to minimize fracturing/losses.

7. Retrieve wear bushing.

8. Change top 5” rams with 9 5/8” ram.

9. Rig up 9 5/8” casing handling tools and fill up tool. Run 9 5/8" casing as follows:

9 5/8” CASING

Description No.Length

(ft)Setting Depth

(ft MD KB)

Weight (ppf)

Grade Connection

Total Depth 1,793

9 5/8” Float shoe 1 2 1,791 43.5 K-55 BTC

9 5/8” Casing 2 80 1,711 43.5 K-55 BTC

9 5/8” Float collar 1 2 1,709 43.5 K-55 BTC

9 5/8” Casing 43 1,720 -11 43.5 K-55 BTC

Note:

a) Bakerlok first five joint.




d) Run Bow centralizer 3’ above shoe and at top of jt #3, #5 and 1 ea every five joint. And 1 rigid centralizer to position around wellhead area. Minimize centralizer utilization to reduce tight hole while run casing.

e) Fill up casing every five joint if the fill up tool is unavailable.

f) Circulating swedge must be available on rig floor.

g) The optimum torque of 9 5/8” casing is 4000-5000 ft.lbs. Check triangle mark for the first 10 jts while making casing connection. Re-check every 10 jts.

h) Be prepared to wash the casing to bottom but use extreme care not to stick the casing as the 9 5/8” casing setting depth is critical to the success of the well

i) The good primary cement job on 9 5/8” casing is critical for the LOT

10. Circulate to clean and condition hole for cementing (break circulation slowly and increase periodically until AV around casing similar with while drilling). Check for any gas to surface. Reciprocate casing while circulating if possible. circulate minimum of one casing volumes and lower mud rheology, cut YP to 12. Take final circulating temperature.

11. While circulating, conduct a pre-job meeting with all parties involve to discuss action items and contingencies.

12. R/U Cementing lines. Flush cement lines with water, rig up lines, break circulation and test lines to 2500 psi for 5 mins.

13. Release bottom plug

14. Cement 9 5/8” casing as per program using 12.5 ppg lead slurry and 15.8 ppg tail slurry


The Tail slurry column length around 200’ from the proposed casing shoe and followed by Lead slurry until the surface. Using 100% excess for open hole or 30% excess volume by carbide lag check or depend on well condition (TBD).

Reciprocate casing about 10-15 ft during cementing job if possible

15. Release top plug and follow by 2 bbls tail slurry and 10 bbls water. Continue displace with mud as per program.

16. Bump plug with 1000 psi over final pump pressure, hold for 5 minutes. If plug does not bump plug with calculated displacement, the maximum displacement should not exceed theoretical volume to float collar plus ½ shoe track volume.

17. Bleed off pressure and check floats holding. Open the side outlet casing head valve, and flash out the BOP’s and casing head from any access/contaminated cement.

Mud Engineer should check weight of contaminated cement

18. Monitor 13 3/8” x 9 5/8” annulus for fluid level drop. Close 9 5/8” rams. WOC until sample cement gets hard.


19. Observed annulus pressure if any. Call Jakarta office if pressure are presents. Otherwise, Open 9 5/8” rams. Pick Up 13 5/8” BOP. Set 9 5/8” casing slips, slack off weight.

20. Rough cut 9 5/8” casing, L/D excess casing. Cut off and dress 9 5/8” casing.

21. Install tubing head/casing spools. Pressure test tubing head seals to 2,000 psi (80% of 9 5/8” casing collapse resistance). Install 13 5/8” 3M Flange top x 11” 5M flange btm, NU 13 5/8” BOP. (Do a top job on the annulus if required).

22. Change top 9 5/8” rams with 5” ram


Ensure tubing head spools outlets are opened before testing BOP’s.

During test BOP, prepare 7% KCL-PHPA for next section.



3.6. Drilling 8 ½” Hole for 7” Liner

Note:

7% KCL-PHPA Less damaging fluid will be used to drill this section. Mud Engineer need to control the quality of this mud including the KCL content not less than 7% and the solid content is not excessive.

Possible lost circulation during drilling thru Secondary and Primary objective, The prevention can be seen in the Lost Circulation attachment.

Optimize hole cleaning, circulate at maximum rate as specified in the drilling parameters. Optimize the shaker screen sizes applicable for the flow rate and max.allowable solid content in mud. Optimize mud cleaner with 200 Mesh screen and centrifuges.

Sweep hole with 30 bbls of 80 sec/qt Hi-Vis every 500’ drill, only if required.


Mobilize 7” liner and liner hanger with its accessories from the yard to rig site

Do not leave the hole open too long.

Avoid swab and surge pressure.

Vital to maintain hole full at all the times. Gas zones in Upper menggala and Pematang interbedded sands may open in this section

The Menggala and Pematang formation is very abrasive and hard formation.

Ensure LCM are onsite.

Prepare 8 ½” Insert bit IADC 537.

25. Make Up 8 1/2” Insert Bit and BHA consist of 8 ½” Insert bit, Bit Sub w/FV, 2 x 6 1/4” DC, 8-1/2” String Stab, 1 x 6 3/4” DC, 8-1/2” String Stab , 3 x 6 1/4” DC, XO, 1 x 5” HWDP , 6-1/4” Jar, 10x 5” HWDP. RIH to top of cement.

Optimize hydraulic for good hole cleaning and bit horse power.

BHA will be prepared by rig and company if available and discuss with KPSA drilling supervisor. Any changes should be informed and gotten approval from Jakarta office.

Use larger jets in case LCM are needed to cure losses.

When Rock bit close to top of cement, run slowly and tag gently to avoid bumping and breaking of Rock bit cutters.

26. Drill out cement inside 9 5/8” casing . Pressure test casing to sufficient pressure for performing LOT. Ensure the pressure are not more than casing burst rating pressure. Cont.drill out cement to shoe.

Dilute mud to 8.8 ppg.

Slowly penetration around shoe to avoid back out shoe joint.

Max. WOB 2-6 klbs. Min. 80 RPM or refer to Bit Technician Specialist advised.


27. Drill 10’ new formation. Circulate hole condition with 8.8 ppg mud. Perform Leak of test.

Perform LOT using cementing unit with maximum rate 0.25 bpm and record the pressure taken from the low ranges gauge.

Prepare to squeeze the shoe if LOT value is below 13.0 ppg. Call Jakarta for the LOT result.

Plot LOT in pore pressure plot and based on this data make assessment of the kick tolerance at ~ 3,253 ft MD-BRT / 3,253 ft TVD-BRT (propose Well TD).

28. Drill a 8 ½” vertical section to 7” casing shoe, estimate at +/- 3,253’ MD-BRT/ 3,253’ TVD-BRT

Note: While drilling 8 ½” hole

Drilling parameter 500-600 GPM (or related with tool parameter limited), WOB 5-25 Klbs, 80-100 RPM. Final drilling parameter will be advised by Bit technician/specialist and discussed with drilling supervisor.

Ensure MBT and filtration loss as low as per program to avoid formation damage.

Control ROP to prevent overloading the annulus with drill cuttings which could induce stuck pipe or loss of returns.

Increase mud weight as required.

Sweep hole with 30 bbls of 80 sec/qt if required.

Short wiper trip if required.

29. Circulate hole clean. Flow check-5min.

30. Wiper trip (pump out of hole or slow back ream if required) to shoe, flow check-5min, and RIH back to bottom and drop carbide. Circulate hole clean. Flow check-5 min. Drop totco survey. Pump out of hole to shoe. POH to surface.

Drilling supervisor, tool pusher/rig superintendent must on the rig floor during pulling out of hole operations until bit is up in casing string

Circulate with 600 GPM, twice bottoms up

Reduce mud viscosity if considered necessary to minimize fracturing/losses.

31. Run electrical logging as per program. The final logging program to be advised.

Wiper trips every 2 times logging (maximum 3 times logging).

Observe annulus when run logging.

Be prepared with 7” lubricator and pack off seals.

32. Wiper trips as item 6.

33. Retrieve wear bushing.

34. Change top 5” rams with 7” ram.

35. Rig up 7” casing handling tools and fill up tool.


36. Make up 7” Liner hanger and running tools, lay out same in Vee door, Run 7" casing as follows;

Description No.Length

(ft)

Setting Depth

(ft MD KB)

Weight (ppf)

Grade Connection

Total Depth 3,253.00

7” Float shoe 1 2.3 3,250.70 26 L-80 BTC

7” Casing 1 40 3,210.70 26 L-80 BTC

7” Float Collar 1 1.3 3,209.40 26 L-80 BTC

7” Casing 1 40 3,169.40 26 L-80 BTC

7” Landing Collar 1 1 3,168.40 26 L-80 BTC

7” Casing 39 1560 1,608.40 26 L-80 BTC

7” Liner Hanger with

Packer1 set 12 1,596.40 26 L-80 BTC

Note:

a) Bakerlok first five joint.



d) Ensure that all 5” DP has been rabbit with proper size refer to OD of pipe dart.

e) Run Bow centralizer 3’ above shoe, middle of float collar joint, middle of landing collar joint and at top of jt #3, #4,#5,#6,#7,#8,#9 and 1 ea every two joint. And 1 rigid centralizer to position around liner hanger area. Minimize centralizer utilization to reduce tight hole while run casing.

f) Fill up casing every five joint if the fill up tool is unavailable.

g) Circulating swedge must be available on rig floor.

h) The optimum torque of 7” BTC casing is 3000-4000 lbs. Check triangle mark while making casing connection.

i) Be prepared to wash the casing to bottom but use extreme care not to stick the casing as the 7” casing setting depth is critical to the success of the well

j) The good primary cement job on 7” casing is critical for the isolation between production zone and reduce the production skin.

37. Pick up liner hanger jt. Make up wiper plug and hanger. RIH with pup joint. Confirm total weight of liner.

38. Run liner in hole on drill pipe, monitor returns for losses while RIH. Circulate liner at 9 5/8” casing shoe. Wash last stand to bottom, increase circulation rate slowly monitoring PVT for losses. Circulate minimum of one casing capacity, reciprocate casing throughout.


39. Check static, pick up and slack of weight.

40. Drop ball and set liner hanger (refer to liner hanger program as per Liner hanger specialist), release running tool, cement 7” liner as per program. Release DP dart. Displace with small amount of cement. Continue pumping displacement with mud. Observe when the dart latches in and shearing off the liner wiper plug.

41. Pump theorectical displacement, bump plug with 1000 psi above final circulating pressure. If plug does not bump, displacement should not exceed the calculated volume to float equipment plus 1/2 shoe track volume.


The Tail slurry type to be advised. The excess slurry volume to be determined based on caliper log or hole condition.

42. Bleed off pressure and check floats holding. Pick up engage dogs and set liner packer, pressure test packer to 2000 psi (or as per KPSA recommendation). Release liner running tool.

43. POH 5-10ft, Reverse circulate. Observe and record volume of any cement returns. POH with running tool to surface. Pressure test packer to 2000 psi (or as per KPSA recommendation.

44. Change top 7” rams with 3 ½” ram.


Ensure tubing head spools outlets are opened before testing BOP’s.

During test BOP, prepare KCL-Brine for next section


47. Make up 8 1/2” Mill tooth bit and clean out BHA. RIH and clean out cement to top of 7” Liner. Circulate hole clean. Record top of 7” liner depth. POH.

48. Make up 6” Mill tooth bit complete with 7” casing scraper and 9 5/8” casing scraper. RIH and clean out cement inside 7” liner to landing collar or any depth recommended by KPSA.

49. Displace hole with KCL-Brine.

50. POH to surface.

51. Rig up wireline logging. Run CBL-VDL-CCL-GR. Log to 7” top of liner. Rig down wireline logging.

52. Pressure test casing to 2,500 psi for 15 min.

53. The completion program will be issued separately.

3.7. Abandonment Program

This abandonment program should include the minimum of;

54. Isolate any permeable zone(s) and permeable fresh water zone(s) with cement plug 100’ above and below interval(s).


55. Set a 400’ of cement plug across 9 5/8” shoe consist; 200’ above and 200’ below 9 5/8” shoe. WOC 6 hrs tag cement to verify TOC and record depth. Test cement plug with 15 kips and 1000 psi for 15 mins, pressure drops max 10

56. Set a 150’ of surface cement plug

57. Cut off wellhead and fill cellar full of cement. Make up a steel sign on top of cut off with sufficient written information to identify the well.

58. All abandonment or suspension programs are subject to BP MIGAS approval.


4 SAFETY, HEALTH, ENVIROMENT AND SOCIAL REPSONSIBILITY

4.1. Pre-Job Meeting

Before any work commences on specific contracts, the contractor is to attend a briefing with the Drilling Supervisor / Company Man. At this briefing:

• the procedures and safety requirements for the work will be reviewed;

• reporting relationships will be established;

• potential problems and responsibilities will be discussed. This will include details of hazards that may exist or to be introduced/created by those doing the work, and details of management and control methods. All personnel on the drilling site will be informed of these decisions through safety meetings prior to the start-up of the job.

4.2. Rig Inspection

A Rig inspection will be conducted by a MIGAS Safety Inspector prior to spud the well.

Should this inspection reveal an unsafe act or condition, the Drilling Supervisor/ Company Man is to be work with Rig Superintendent so that immediate steps can be taken to effect remedial action.

A result of the Rig inspection is to be forwarded to Drilling Manager/Drilling Superintendent/KPSA Well Service Manager with copy to Drilling SHE Manager.

4.3. Pre-Spud Inspection

An inspection of the drilling operation is required to ensure the following requirements have been fulfilled:

• rig in full & safe operating mode;• all necessary materials are on the drilling site;• all safety equipment on hand and• H2S gas detection gear installed and fully operational if required.

The rig inspection will be conducted by the Drilling Manager, the Drilling Supervisor / Company Man, the Rig Superintendent and HSE Manager/Officer.


4.4. BOP Testing/Drill

Testing: This is to be carried out immediately after installation then every 14 days. The frequency of testing will increase as the operation dictates. Function tests will be carried out on trips out of the hole, alternating between drillers and consoles.

Drills: Pit/kick drills are to be initiated by supervisors while drilling/tripping and response time logged. A drill is to be conducted once a day and should reported in Drilling Report.

4.5. Hydrogen Sulphide (H2S)/Flammable Gases

The mud logging unit/ H2S Specialist will have the appropriate equipment for the detection of H2S and flammable gases. Alarms will be set to automatically sound should the H2S gas level exceed >20 ppm or the flammable gas concentration exceed 20% of the lower explosive limit.

Evacuation drills will need to be practised and muster point / assembly areas arranged beforehand.

4.6. Signposting

This will be posted detailing well identification, person-in-charge, flammable liquid storage, reporting procedures, no smoking, and the wearing of personal protective equipment (“PPE”).

During the drilling programme, the appropriate signage will need to be erected in those areas off-limits due to:

• the presence of combustible or noxious gas;• the use of explosives;• formation testing; and• high pressure work.

4.7. Smoking/Ignition Sources

Smoking or the carrying of matches, lighters or other ignition source is not permitted on the drilling site. Smoking may be allowed in designated smoking areas / muster point.

Machinery and equipment that are a potential source of ignition shall not be placed or used within the vicinity of any source of flammable vapour. The Drilling Supervisor / Company Man may waive or modify this requirement depending on the drilling activity and provided the appropriate procedures are taken.


4.8. Hot Work

No hot work shall be undertaken without the express written consent of the Rig Superintendent / Company Man.

Hot work is defined as that which involves a potential source of ignition and includes welding, gas cutting, naked flame use, grinding, concrete chipping, percussion tools, sand blasting, drilling, electrical equipment not intrinsically safe (including battery-operated devices) and internal combustion engines.

4.9. Confined Space Work

No entry or work in a tank, vessel, pipe, sump or pit shall be undertaken without the express written consent of the Rig Superintendent or Drilling Supervisor / Company Man. Generally an air quality test will be done prior to the issue of this consent.

4.10. Hazardous Substances

Before any substance that is likely to be hazardous is used or handled, the current material safety data sheet (“MSDS”) is to be checked for the precautions to be taken. Do not handle the substance unless the precautions are clearly understood.

The MSDS shall be current, and supply full and correct details on:

• identification and ingredients;• health hazard and first aid;• precautions for use;• safety handling;• environmental hazards, spill and disposal procedures; and• contact point.

Radioactive material is to be under the control of a licensed operator with the transportation, storage and work area suitably protected.

Asbestos or products containing asbestos are not to be used or supplied with plant or equipment for use on the drilling site.

4.11. Dangerous Circumstances

Anything that could be a cause of danger of any kind is to be immediately reported to the person in control who shall take remedial action.

4.12. Safety Meetings

There will be several safety meetings should be conducted, such as: Pre-Tour meeting, daily/shift day&night, Supervisor meeting, weekly meeting, Pre-Job/Safety Talk as required.


The above safety meeting will be attended by the Drilling Supervisor / Company Man and Rig Superintendent. They will also be held whenever operational activities are planned that may increase hazards (e.g. drilling into known pressure zones, lost circulation problems, etc.).

A copy of the meeting report is to be forwarded to the SHE Drilling Manager and Drilling Manager.

4.13. Personal Protective Equipment

Generally, personnel are to be supplied by their employer with the appropriate PPE for the work being undertaken. This equipment is to be worn.

Clothing

Loose fitting clothing is not to be worn when attending moving machinery.

Safety Footwear

Standards approved covered steel cap safety footwear is to be worn by all personnel working on the drilling site.

Gloves

Gloves are to be worn when handling machinery, equipment, ropes and chains. Special gloves should worn, when handling with any chemicals.

Eye Protection

Impact-resistant safety glasses are to be worn by all personnel walking/working on or around the drilling site. Where there is a risk from flying objects, for flame cutting and exposure to dust or chemicals, the appropriate eye protection is to be worn.

Respiratory Protection

Respiratory protection is to be worn where toxic vapours, dusts or an oxygen deficiency exists.

Hearing Protection

Hearing protection is to be worn where a noise hazard exists. This will occur when in the vicinity of the mud tanks, rig engines and drill floor for more than two hours per day. Grade 2 ear plugs or muffs are suitable.

Hard Hats


Standards approved hard hats in good condition and less than two years old are to be worn on the drilling site at all times. Aluminium hard hats are not permitted. All hard hats are to be fitted with chin straps.

Safety Belts/Life Line/Fully Harness

Certified Safety belts/life lines/Fully Harness are to be worn at all times by the derrickman and persons working over unprotected drops (minimum 2 meters above).

4.14. Breathing Apparatus Training

Those persons who may be required to wear self-contained breathing apparatus (“SCBA”) are required to be trained in the use of the equipment and/or have undertaken refresher training within the previous 12 months.

4.15. Fire

It is essential that good surveillance is maintained to ensure that fire risk is minimised.

Adequate fire fighting equipment will be available for immediate use, will be in good working order and shall have been tested within the previous three months.

All crew members are to be trained in the use of the equipment and regular fire drills held.

All personnel are to be aware of their muster station.

An alarm capable of alerting all personnel will be installed and tested.

A drilling site-specific emergency response/evacuation procedure (ERP-Emergency Response Plan) is to be prominently displayed and all personnel made familiar with it.

All personnel shall comply with any emergency response procedures in force and are to participate in drills and exercises as instructed by the Rig Superintendent / Company Man.

4.16. Accident/Incident Reporting

Every injury, illness, property damage, fire, explosion or near miss is to be reported immediately to the Rig Superintendent and the Drilling Supervisor Company Man.

Reporting of all incidents will comply with the MIGAS and KPSA reporting procedures.

Serious Harm Injury


Upon Investigation

If there is actual or there could have been major loss (i.e. “serious harm” injury), fire, explosion or major non-injury accident, the following are to be contacted immediately:

- Resmono/Fatkhu Roji Work: (+62) 21 5290 6100 ext. 1091Mobile:(+62) 811 140 914

- Edi Sutriono Work: (+62) 21 5290 6100 ext.4260Mobile:(+62) 812 103 1134

The Rig Superintendent and Drilling Supervisor / Company Man are to take control at the scene and preserve the accident site until further instructions.

Note:Except for the purpose of saving life, preventing injury, or preventing serious damage to or serious loss of property, the accident scene is not to be interfered with.

The Company Man or the On Scene Commander is to notify the above VIP person who will notify BPMIGAS/MIGAS of the accident details in the event of:

- major loss: immediately by telephone or facsimile;- other lost time injury: within seven (7) days by written accident report form.

Upon Investigation

If of minor nature:

- affected person or witness to complete an accident report;- the Company Man to complete investigation and determine cause;- the Company Man to develop and take remedial action;- the Company Man to report findings and remedial actions to the On Scene Commader and Emergency Response Leader within 24 hours of the event.

Note:An Accident Report is to be completed by the Drilling Supervisor / Company Man for all lost time injuries and faxed to the SHE Drilling Manager, VP & GM KPSA Jakarta office within 24 hours of the event.

Medivac and Fire Excecise should be done as per KPSA SOP

4.17. Man Hours Worked


Each contracting company is to forward to the SHE Drilling Manager by the daily report, the following details of the previous month’s work performed on the well site:

• total man hours worked;• lost time man hours due to injury/illness;• number of lost time injuries;• number of minor (first aid) injuries.

4.18. Alcohol and Drugs

No person shall enter or remain on any site owned or operated by KPSA while in a state of intoxication or under the influence of recreational drugs.

Alcohol or recreational drugs must not be brought on to or consumed on any site owned or operated by KPSA, including a drilling site.

Disciplinary action will be taken for those persons not observing this work condition. This may include summary dismissal.


ATTACHMENT


ATTACHMENT 1: LOST CIRCULATION

1. Introduction

Lost Circulation can be the caused by Natural Losses or Induced Losses. Natural losses are where whole fluid is lost to formations that are highly permeable, unconsolidated, fractured, cavernous or vugular. Induced losses are caused when excessive pressure hydraulically fractures the formation resulting in the loss of the drilling fluid. The losses can be classified as seepage losses, less than 10 bph, partial losses, up to 100 bph, and severe losses, over 100 bph to total losses.

Any time lost circulation is encountered it will increase the well costs but the incremental increase in cost is more significant with severe or total losses. In the case of total losses the sudden loss of hydrostatic pressure can result in a well control situation or well bore instability which could result in stuck pipe and the loss of the hole.

2 Lost Circulation Material

There are six types of lost circulation material that can be added to the drilling fluid to cure the lost circulation as follows:

Type Description Lost Circulation Material

Fibrous Material with relatively little degree of rigidity that plug the surface or within the formation that is taking fluid

MI- Cedar Fiber or M-I-X (fine, med and course grades)

Granular Particulate materials of various degrees of rigidity, rugosity and size that bridge and wedge in the formation that is taking fluid

Calcium Carbonate, Walnut Hulls or Sized Salt (fine, med and course grades)

Flaked Material with a flat, layer like appearance that have limited or no rigidity

Mica, Cellophane etc (fine, med and course grades)

Mixed A mixture of all three types in one sack. This provides a blend of material with proper sizing

Kwikseal, M-I Seal (fine, med and course grades)

High Fluid Loss Squeeze

This slurry readily dehydrates when squeezed into a loss zone. The solids pack off the fractures forming a seal

Diaseal M

Soft Plugs These plugs contains three sun types polymers, bentonite and chemical treatments

Gunk Squeezes, Sodium Silicates

3 Prevention and Control of Lost Circulation


The casing design is the most critical item in the avoidance of lost circulation particularly in the case of induced lost circulation in abnormally pressured formations. In this case the ECD of the drilling fluid required to drill to the next casing seat exceeds the fracture gradient of a weaker formation in the open hole interval resulting micro fractures (commonly referred to as ballooning). This normally results in the well flowing back on connections which will show up on the mud log as Connection Gas. Connection Gas is the main indicator that the well is being drilled with insufficient drilling fluid weight and the tendency is increase the mud weight. In the case of micro fractures it may require the mud weight and /or the circulating rate to be decreased to eliminate the well flowing back on connections instead of raising the weight and increasing the ECD.

The casing design should minimize the amount of open hole between the casing seat and a potential lost circulation zone. Also in the case of a cavernous, vugular or fractured formation a casing string needs to be set just above the zone. The casing design should include a contingency string of casing for the drilling of abnormally pressured formations.

The drilling program should include lost circulation prevention procedures and the lost circulation contingency material for the well. Some of the operations that need to be addressed are:

Annular Loading The overloading of the annulus can result in seepage to partial losses which may require the implementation of controlled drilling practices or a reduction in the pump rate.

Seepage Losses If the probability of seepage losses is high, pretreat the active system with LCM ( Mica or Kwickseal fine) and size the shaker screens to keep the LCM in the active system

Drilling Fluid Properties

Maintain good mud properties to minimize the ECD and a low water loss to reduce the thickness of the filter cake

Surge & Swab Pressures

Use good drilling procedures to minimize swab and surge pressures while tripping and breaking circulation

Pumping out of the Hole

Pumping out of the hole should be implemented with discretion as it can increase the hole instability due to pressure surges if there are problems with the annulus packing off.

4 Treatment of Lost Circulation

The effective treatment of lost circulation must consider the following items:

Assess the possible cause of the lost circulation Identification of the type of loss zone Establish the location of the zone

The assumption that the losses are on bottom should be not be applied unless the losses are combined with a significant drilling break or an interval of erratic and high torque. The losses could be up the hole if there has been a gradual increase in ROP for 10 to 15 feet


which increases the ECD such that a weaker zone loses circulation with the additional ECD from the drilling break.


4.1 Seepage Losses (< 10 bph)

The first thing that needs to be implemented when seepage losses occur is to stop drilling and circulate the hole clean at the same pump rate while it is determined if the losses are down hole or at surface. If it is determined the losses are down hole the required treatment will vary based on the situation.

The treatment when the seepage losses are due to a weak zone that can develop sufficient strength with the LCM treatment and the build up of a filter cake to reach the next casing seat (the next casing setting depth is normally not including abnormal pressure) .

Step Operation Comments

One Continue drilling at a controlled drill rate, Monitor returns closely to determine rate of loss

If losses increase stop drilling and circulate at a sufficient rate to clean hole with minimum of losses ( treat as per partial losses)

Two Sweep hole with a minimum of 40 bbls LCM pill consisting of a minimum of 30 ppb of fine LCM, (Mica, Ca Carb, Kwik-seal, or nut plug for water based fluids) ( Kwik-seal or Ca-Carb for OBM)

Monitor rate of loss prior to and after LCM pill is out of the hole

Three

Continue drilling at a controlled rate provide losses remain as seepage losses until the next casing seat is reached

Add fine mica to the active system if required

The treatment when the seepage losses are due to micro fractures (ballooning) when drilling in abnormal pressures attempting to optimize the next casing seat is more complex. The recommended procedure is as follows:


One Continue circulating at a reduced pump rate until the hole is clean, increase the pump rate to establish the rate the losses commence

Need to determine if the ECD can be reduced by reducing the mud weight and pump rate to enable the casing seat to be reached

Two Shut in pumps, put well on the trip tank to determine if there is any static losses and to establish the rate the well flows back in case the losses are due to ballooning

If ballooning exists, reduce the mud weight in 0.2 ppg increments and circulate to check max pump rate before seepage losses occur

Three

Sweep hole with a minimum of 80 bbls LCM pill consisting of a minimum of 30 ppb of fine LCM material compatible with mud system,

Control pump rate do eliminate losses due to ballooning, displace LCM pill with the lighter weight mud

Four Conduct pumping rate test to determine if For critical wells consider


the ECD can be controlled to allow the drilling to commence.

adding LCM (FLC-2000 or equivalent) to active system prior to commencing drilling

Five Continue drilling at a controlled rate monitor losses closely check well for flow back on connections

Add LCM to the active system if required

4.2 Partial Lost Circulation (> 10 to <100 bph)

The first thing that needs to be determined is the depth of the lost circulation zone and the type of treatment. The following is the recommended procedure:


One When the partial lost circulation occurs, slow the pump rate to minimize losses and pick up off bottom.

Attempt to circulate the well clean while preparing an LCM pill

Two Spot an LCM pill, a minimum of 30 ppb of fine and med LCM on bottom, (Mica, Ca Carb, Kwik-seal, or nut plug for water based fluids) ( Kwik-seal or Ca-Carb for OBM)

Pump maximum amount of mud that can be mixed in the slug pit, POH to shoe or a minimum of 100 feet above LCM pill. Observe well for static losses

Three

Attempt to circulate after allowing the LCM to soak, if still having losses, spot a larger LCM pill, 200 bbls. If there is any doubt of loss zone spot LCM pill off bottom. POH to shoe, circulate and condition mud monitor rate of loss

If there is any doubt about location of losses, spot pill just outside shore, pick up above LCM pill and circulate with losses pushing LCM pill to the loss zone

Four After curing the losses with LCM pills, circulate and condition mud, consider reducing the mud weight, wash and ream to bottom, circulate at a reduced pump rate until the hole is clean, increase the pump up to the circulating rate to check for losses

Need to determine if the ECD can be reduced by reducing the mud weight and pump rate to enable the casing seat to be reached



4.3 Severe Lost Circulation (Unable to circulate, but no static losses)

The method used to cure this type of circulation is similar to the partial returns except the concentration of LCM material needs to be as high as possible based on BHA and the amount of LCM pill pumped needs to be larger. The following is the recommended procedure:



One When the severe lost circulation occurs, slow the pump rate to minimize losses and pick up off bottom as far as possible. SIP

Monitor well to determine if there is any static losses Attempt to circulate the well clean while preparing an LCM pill

Two Monitor well to determine if there is any static losses while preparing an LCM pill

Circulate across the wellhead using trip tank to record static losses.

Three

Spot an LCM pill, 40 to 50 ppb of fine and med LCM on bottom, (Mica, Ca Carb, Kwik-seal, or nut plug for water based fluids) ( Kwik-seal or Ca-Carb for OBM)

Pump minimumof 100 bbls LCM pill, POH to shoe. Observe well for static losses

Four After curing the static losses with LCM pills, circulate and condition mud, consider reducing the mud weight, wash and ream to bottom, circulate at a reduced pump rate until the hole is clean, increase the pump rate to establish the rate the losses commence

If losses commence again, repeat Step 3, if losses cannot be cured consider setting a cement plug or drilling blind for a maximum of 100 feet and setting casing



4.4 Total Lost Circulation (Hole not standing full)

There are two drilling operations where total lost circulation occurs. The most critical is losing total circulation while trying to establish a casing seat at the top of a carbonate reservoir. Since the bottom hole pressure in the reservoir is normally considerably les than the mud weight required to drill the shale section just above the reservoir. When the total losses occur the fluid level in the annulus will drop rapidly which can allow for an influx of formation fluid into the wellbore or the shale section above the reservoir can slough in and stick the drill string. This potentially serious situation should be addressed in detail in the drilling program for the well. The following is the recommended procedure:


One Prior to drilling the section of hole build a minimum of 200 bbls of lighter weight mud (9 to 10 ppg) to be used to fill the annulus as soon as the total lost circulation occurs and the fluid level drops in the annulus

Build the lighter weight mud in the largest reserve mud pit available. If drilling 12 ¼” hole increase the amount up to a maximum of 400 bbls. Have a dedicated mud pump lined up on the light weight mud

Two In the second reserve pit mix a minimum of 200 bbls of LCM pill with predominantly Ca-Carb (fine, med and

This will be the first mud that is pumped down the drill pipe after the fluid level is


course with some Mica established in the annulus

Three

If drilling a well, drill to within 100 feet of the top of the reservoir, POH, lay down BHA, RIH with slick BHA with large nozzles for handling LCM

This step may be omitted for the wells where the difference between the mud weight and the formation pressure is not to big and there is good depth control for the top of the Carbonate

Four When the severe lost circulation occurs, slow the pump rate, pick up off bottom as far as possible. SIP

Check fluid level in the annulus, if fluid level not visible

Five Commence pumping light weight mud until annulus fills up, record quantity and weight,

If all light weight mud pumped switch to water and fill the annulus with water until annulus fills up

After annulus fills up, circulate across the wellhead with the trip tank to record static losses. Calculate the estimated BHP based on the mud gradient in the annulus

Six Pump LCM pill from reserve pit 2, pump minimum of 100 bbls, displace the LCM with mud, after 50 bbls outside bit , pump out of the hole a minimum of 4 stands while displacing the last 50 bbls.

Take returns to trip tank to record amount of mud returned if the well starts to circulate.

Seven

SIP, let the LCM pill soak, keep record of rate of static losses. If static losses cease, go to Step Eight

If static losses persist, RIH to 2 stands off bottom and set another LCM Pill. If static losses severe consider setting an LCP 2000 or a cement plug through the bit

Eight After static losses cease, POH to casing shoe, circulate and reduce mud weight, wash and ream to bottom reducing mud weight.

The decision on what is required to condition the hole for casing will be made based on losses and hole conditions.

If the total lost circulation occurs after setting the casing above the carbonate reservoir the lost circulation will be handled as per the section on Pressure Mud Cap Drilling.


ATTACHMENT 2: TRIPPING PROCEDURE

It is critical that all trips out of the hole are conducted by applying industry accepted tripping procedures. The following outline covers normal tripping operations for different type wells, pumping out of the hole and pressure mud cap tripping operations. It is the responsibility of all the Rig Supervisory personnel to ensure the trips are conducted safely without any incidents. The rig crews must be informed of any potential hole problems and the if there is any hydrocarbon bearing zones that can be swabbed in. The hole fill up must be monitored and recorded in the trip sheet and any time the hole is not taking the correct amount of mud the Company Policy is “to return to bottom and circulate bottoms up to check for any influx”.

1. Shallow Wells

There is a tendency to not use sufficient mud weight to provide a safe “Trip Margin” for trips in shallow wells where there are hydrocarbon zones exposed. For example the following table illustrates the relationship between mud weight, trip margin and depth for two zones at 2000 and 10,000 ft:

Item 2000 ft Well 10,000 ft Well

EMW of formation 9.5 ppg 9.5 ppg

Bottom Hole Pressure 988 psi 4940 psi

Mud Weight 10.5 ppg 10.5 ppg

Mud Column Hydrostatic Pressure 1092 psi 5460 psi

Trip Margin 104 psi 520 psi

Mud Weight required for 200 psi Trip Margin

11.43 ppg 9.9 ppg

The industry standard for a Safe Trip Margin is 200 psi for the shallow well a 1 ppg increase in mud weight over formation pressure is approximately 50% of the way there while for a deeper well the same mud weight is 250%.

This is a safety factor that is over looked in most shallow well drilling programs as it is very common to see drilling programs with LOT results in excess of 13.5 ppg calling for mud weights of 9.5 to 10 ppg. The mud weight in the shallower zones should be increased to provide a higher trip margin to prevent swabbing in shallow hydrocarbon bearing zones and better hole stability.

2. Trip Procedure (Vertical Wells)

The following is the recommended trip procedure for all standard vertical wells:

Step Description Comments

One Circulate Bottoms up to remove all cutting from the well bore

For abnormally pressure wells, circ 30 min, SIP, swab well 4 to 5 times, circ to check for simulated trip gas


Two Perform SIT on well prior to pumping slug, pump slug and min 5 bbl mud

Not required for surface holes and routine wells

Three Pull two to three stand observe annulus to make sure well is not swabbing

Allow slug to equalize, do not be concerned if hole doesn’t take correct amount of fill

Four Commence pulling pipe, fill hole with trip tank record fill per 5 stand on trip sheet

Toolpuher and Company Rep should be on rig floor until bit is up in the casing string

Five Do not make it standard practice to pump out of the hole for routine trips

Should avoid pumping out to minimize pressure surges which can increase hole instability

Six If the hole fill up is less than calculated , RIH and circulate bottoms up

SAFETY IS THE BEST POLICY

Seven Perform SIT at the shoe and at the BHA

Give consideration an circulation bottoms up at the shoe on deep abnormally pressure wells

2. Trip Procedure (High Angle Wells)

The following is the recommended trip procedure for high angled (over 35 degrees) holes :

Step Description Comments

One Circulate Bottoms up to remove all cutting from the well bore

For abnormally pressure wells, circ 30 min, SIP, swab well 4 to 5 times, circ to check for simulated trip gas

Two Perform SIT on well prior to pumping slug, pump slug and min 5 bbl mud

Toolpuher and Company Rep should be on rig floor until bit is up in the casing string

Three Pump out of the hole, back reaming to remove cuttings from the low side of the hole

Rotate the string at min 80 rpm to assist in hole cleaning. Any tight hole ream stand until hole free

Four Perform SIT at the shoe and circulate the well clean

If the trip to the shoe is a wiper trip, wash and ream to bottom, low RPM, and then pump out to the shoe

Five Slug pipe, POH Use trip sheet to make sure the hole is taking the correct amount of fluid


ATTACHMENT 3: WELL CONTROL

Well control problems can be expected at any time while drilling. Shallow gas and over pressured horizons are possible. KPSA’s DRILLER METHOD well kill procedure to be followed, an example well kill form is included. The following guidelines should be adhered to unless alternatives are specifically approved.

1. After surface casing is set and the BOP stack has been run, the well will be shut-in in the event of a kick. It will not be diverted. DRILLER’s METHOD will be used, deviation to this should get DSS and KPSA’s approval.

2. Drill with non-ported float at all the time

3. Have sufficient volume of water and water pump capacity

4. Leak off test will be run at all casing points

5. As a guideance, maximum mud weight is 1.0 ppg below leak off test.

6. Make a 10 stand short trip to previous casing shoe before pulling all the way out.

7. A minimum 1000 sack stock barite to weight up the system to be maintained at all times.

8. Blowout drills will be conducted every shift until supervisor is satisfied with all crews performance, there after weekly for each crew.

9. Hard shut-in BOP should be applied for all kicks.


DRILLER’s METHOD

FIRST STEP SECOND STEP

1.

Hold Shut-in Drill Pipe Pressure Constant until circulation is started by bleeding mud from casing, [Allow pressure to rise 100 psi before bleeding, Do not bleed gas]

1.

Calculated Kill weight mud and increase mud weight to that value.

2.

Hold Casing Pressure Constant while bringing pump up to kill rate speed. This speed to be held constant.

2.

Hold casing pressure constant while bringing pump up to kill rate speed. This speed to be held constant.

3 Hold casing pressure constant a few more minutes drill pipe pressure stabilizes.

3.

Hold casing pressure constant until drill string volume has been pumped

4 Read drill pipe pressure and hold this pressure constant until the kick is circulated out of hole.

4.

Read drill pipe pressure and hold this pressure constant until mud returns are at kill weight.

5 Hold Casing pressure constant while bringing speed down, when pump speed is down to the point that the pump is barely running:

Shut pump off (first)

Finish closing choke

5.

Shut down pump and shut in well

6 Read Pressure 6.

Read pressures, should be zero

7.

Check for flow through choke line

8.

Open Preventers

Note: If possible with mud system, commence mixing kill mud weight, based on the original shut-in drill pipe pressure, while circulating out kick.


ATTACHMENT 4: ON SITE DRILLING TEAM RESPONSIBILITIES

Toolpusher

Communicate all directives from company man to drillers, rig crews, mud engineers, and mud loggers.

Organize and Supervise preparation of all tools, and equipment required for efficient operations.

Co-ordinate all work requiring permits with HSE supervisor, and company man. Monitor Rig Floor Activities while tripping out of hole (until trip parameters normalize)

and during flow check prior to BHA being pulled to surface. Ensure Well Safety by preparing light weight mud and/or water is available to fill hole

down annulus immediately if total loss circulation is encountered, (direct line from rig water tank to “Bell nipple” via centrifugal pump or pit of unweighted mud which can be pumped via mud pump down the hole fill line).

Driller

Check Crow O Matic visually at beginning of every tour change. Check Flow Show / Pit Level monitors and Hi / Low alarms. Monitor Drilling Parameters very closely for early “kick” detection. Any change in

ROP, Torque, or Stand pipe pressure to be reported to company man, and confirmed by mud loggers.

DRILLERS HAVE THE AUTHORITY AND RESPONSIBILITY TO FLOW CHECK AND / OR SHUT IN WELL ANY TIME THEY HAVE WELL CONTROL CONCERNS. Time taken for these actions is minimal and it is better to be safe if there is any concern about the well flowing.

Know the shut in procedure for “soft shut in” and the MASCP (maximum allowable shut in casing pressure) with the mud weight being used.

Inspect all tubulars for damage, and drift ID before running them in the hole. Alternate breaks on drill pipe when tripping and note in drilling report, i.e. single,

double, stand. This enables visual inspection of tool joint threads and shoulders, and allows re-doping of all connections every third trip.

Choke and kill line to be flushed with solid free fluid (water) after each use, and before any BOP test. This operation should include the surge tank (poor boy degasser) & the direct line from the choke manifold to the flare pit (blooey line).

Pre job safety meetings held and documented. Maintain open communications with mud loggers and mud engineers while tripping /

drilling. Trip sheets properly used and copies filed for each trip. Discuss with toolpusher, and

company man how much deviation from theoretical fill is acceptable before trip begins. Tripping (pumping out) Reduce size of active pit to one pit only if possible. This

enables us to recognize small gains or losses. Monitor pump pressure closely to prevent fracturing formation if well bore “packs off”. Trip sheet to be used in same manner as conventional tripping.

Hold regular BOP drills while drilling and tripping. Flow check before each trip, before pulling BHA, any drilling break, and at any time you

have concerns or unexplained changes in pit volume. Flow check on trip tank, not visually through rotary table. By actually measuring volume increase in trip tank and


recording volume to time a trend can be established to determine if the flow is actually a “KICK” or “Ballooning”.

Ensure enough personnel are present on rig floor at all times to carry out the operation in a safe, efficient, manner. Instant response to many situations make the difference between success and failure. Adequate personnel for the job at hand helps prevent injury, and improves efficiency.

Report any equipment not working or damaged to Rig Supt. This is not to put blame on any person or persons, but to aid all of use in our goal of drilling safely and efficiently. If equipment problems are known in advance, alternate procedures can be organized to continue operations without using this equipment.

Drillers Assistant/ Derrick man - Pump man

Ensure choke & kill line manifold valves are lined up & checked at beginning of each tour. Auto-Choke to be functioned and operation visually confirmed. All pressure gauges checked on BOP tests. Any problems should be reported to OIM/ Rig Supt. Who should then inform the Drilling Supervisor.

All down hole equipment measured, & “OD/ID” callipered. Drawing of all tools kept in driller BHA book in case of fishing job. Overshot and grapple inventory complete and up to date. THIRD PARTY EQUIPMENT CHECKED IN ADVANCE TO CONFIRM THAT FISHING TOOLS ON RIG ARE COMPATIBLE. STABILIZER BLADES CALIPER WITH BIT GAUGE RING OR PROPER CALIPER.

Well control equipment to be checked at beginning of tour. This includes stabbing valves, inside BOP (dart valve), and any crossovers required. Don’t forget valve operating handles. Insure all valves intended for stabbing have adequate lifting and turning handles to enable quick installation and closing.

Mud pit volume & mud properties confirmed with mud engineer for each individual pit. This data should be posted on white board at mud pit area. Ensure this data is also available in mud logging unit.

Mud loggers informed before transfers from active system to trip tank Solids control equipment should be run at least once every week to ensure supply lines

& supply pumps are not plugged and equipment is ready to be used if needed. Degasser & associated mud supply pump to be run daily, and kept lined up for

immediate use. When in use check & record mud weight in & out. The vacuum on the degasser chamber checked to confirm that the mud supply to the jet is sufficient for good gas removal.

When using Saraline based drilling mud ensure all water sources are kept away from mud pits, shale shakers, and rig floor. Before mixing any water based fluids (cementing spacers etc.) confirm that the pit, pump, and mixing hopper intended for use is isolated from OBM pits.

Pump maintenance; Know the hours on expendable items used and ensure an adequate inventory of spares is available. Hand tools required for pump repairs to be kept close at hand to enable quick repairs.

Pre-check all rig and service company equipment required prior to the operation taking place. Casing equipment ready, hawk jaw for tripping checked, rotary slip dies and keepers in good condition, collar clamps in good condition and sized properly, tubulars and BHA components ready. Service company alerted ahead of time. Service personnel waiting on the rig, not the rig waiting on waiting on service personnel.

Delegate ground work (crane operations, roustabout work, shale shaker monitoring, general house keeping) to others. Make yourself available respond to directives from driller.


Practice having the rig floor supported in every way possible prior to and during the task at hand.

Trip tank should be checked every tour for fill and/or plugging of pump suction. Clean as needed and check calibration of mud logger PVT to ensure no damage to PVT equipment during cleaning.

Mud loggers

Constant monitoring of active system at all times while returns from flow line are directed to active system. Immediately inform rig floor if there is any change in active pit levels. Know what pits are actually being used as active pits. Set hi level alarm at approximately ½ of the kick tolerance amount which will allow rig floor personnel enough time to shut in if necessary. Document in writing on the monitor screen at rig floor & company man office any gains, losses, change of assigned active pits. DON’T RELY on verbal directives alone, which may be misunderstood or ignored.

Monitor trip tank when tripping out of hole. Know in advance the steel displacement of tubulars being pulled. Verify with driller if the string is pulling dry. If wet pipe is pulled confirm that the mud saver (mud bucket) is returning into the trip tank.

Flow checks on trip tank monitored and displayed on screen to enable crews to readily see trends of volume verses time.

Communicate with mud engineer at all times to ensure you know what is being done on mud pits.

Drilling parameters monitored. ROP, Torque, & Stand pipe pressure changes can be used for possible “kick” detection. Pump pressure displayed on screen time verses pressure to help crews recognize wash outs in string.

Check & calibrate all monitoring equipment frequently. Relay all findings concerning equipment malfunctions and failures to company man.

While Tripping in hole log volume increase per stand. Less than theoretical indicates possible surging. Know if string float is used to calculate the volume per stand.

Check cutting samples and report to company man any indications of sloughing, or over pressure shale

Mud engineer

Ensure mud weights in & out are checked and recorded every 30 minutes or more often if requested.

Before transferring be sure mud loggers are notified as to what is being transferred, where the fluid is being transferred to, and approximate volume of transfer. Mud loggers notified when transfer operation is completed.

Inform mud loggers of actual pits incorporated in active system. When transferring mud from another pit it should be incorporated into active system before transferring begins. After transfer is complete it can then be removed from active system.

When mixing directly into active system calculate amount of gain expected from chemical additions, and relay this information to mud loggers and drill floor.

Mud checks should be obtained more often than at report times. Especially oil/water ratios (OBM) and chlorides (WBM) to help determine if mud weight increases are necessary.

Inform company man of any materials required. Keep sufficient inventory of LCM to enable operations to continue if losses occur. Barite stock should be sufficient to increase mud weight 1 ppg in active + hole volume.


Communicate with rig personnel as to expected operations. Sweeps, LCM pills, and hi-weight slugs prepared in advance.


ATTACHMENT 5: CASING DESIGN

13-3/8” Surface Casing

9-5/8” Intermediate Liner

7” Production Liner


ATTACHMENT 6: MUD PROGRAM


Drilling Program MSSM01 280808 SPUD Rev00

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