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Page 1: Revised Booklet 2

Husky Liwan 3-1-1

Well Booklet

Page 2: Revised Booklet 2

_________________

Husky Liwan 3-1-1

Geological Well Programme ________________________

CONTRACT AREA 29/26 Pearl River Mouth Basin

South China Sea People’s Republic of China

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December, 2005 i

TABLE OF CONTENTS

1. SUMMARY WELL DETAILS................................................ 1

2. PERMIT DETAILS ................................................................ 2

3. REGIONAL GEOLOGY........................................................ 3

4. PROSPECT DETAILS .......................................................... 7

4.1 LOCATION ........................................................................................................ 7 4.2 TRAP............................................................................................................... 9 4.3 RESERVOIR.................................................................................................... 10 4.4 SEAL ............................................................................................................. 11 4.5 SOURCE/MIGRATION....................................................................................... 11 4.6 GEOLOGICAL PROGNOSIS ............................................................................... 12 4.7 EXPECTED SEDIMENTARY SECTION.................................................................. 14 4.8 POTENTIAL DRILLING HAZARDS ....................................................................... 15

5. PRELIMINARY DRILLING PLAN....................................... 21

6. WELL EVALUATION.......................................................... 27

6.1 SAMPLING REQUIREMENTS.............................................................................. 27 6.2 MUD LOGGING ............................................................................................... 29 6.3 CORING ......................................................................................................... 30 6.4 LWD............................................................................................................. 31 6.5 WIRELINE LOGGING PROGRAMME.................................................................... 33

6.5.1 Open Hole Wireline Logging Programme................................................. 35 6.5.2 Logging Run in Sidetrack Hole for Core................................................... 37

7. MINISTRY OF PETROLEUM INDUSTRY WIRELINE DATA REQUIREMENTS ................................................................... 40

8. DRILLING SECTION .......................................................... 41

8.1 GENERAL INFORMATION AND WELL DATA ......................................................... 41 8.2 REFERENCES ................................................................................................. 42 8.3 GEOLOGICAL INFORMATION ............................................................................ 42

8.3.1 Objectives ................................................................................................ 42 8.3.2 Strataigraphy Depths ............................................................................... 42

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8.4 DRILLING OPERATIONS SUMMARY................................................................... 43 8.4.1 Operations Summary ............................................................................... 43

8.5 POTENTIAL HAZARDS ..................................................................................... 43 8.5.1 Offset Well References ............................................................................ 43 8.5.2 Shallow Hazard Survey............................................................................ 43 8.5.3 Pore Pressure/Fracture Gradients ........................................................... 44 8.5.4 Potential Lost Circulation ......................................................................... 44 8.5.5 Other Hazards.......................................................................................... 44

8.6 CASING PROGRAM......................................................................................... 45 8.6.1 Casing Properties .................................................................................... 45

8.7 DRILLING OPERATIONS/PROCEDURES ............................................................. 46 8.7.1 Rig Move.................................................................................................. 46 8.7.2 36” Section............................................................................................... 51 8.7.3 26” Hole/20” Surface Conductor Section.................................................. 62 8.7.4 BOPs, Stump Testing, Running and Testing............................................ 75 8.7.5 17½” Hole/13⅜” Intermediate Casing Section ......................................... 79 8.7.6 12¼” Hole/9⅝” Intermediate Casing Section ........................................... 91 8.7.7 8½” Hole Section ................................................................................... 103 8.7.8 8½” Side Track Hole/7” Liner Section .................................................... 108 8.7.9 Abandonment......................................................................................... 121 8.7.10 Lost Circulation .................................................................................... 124 8.7.11 Equipment / Materials Details .............................................................. 127 8.7.12 Personal Responsibilities ..................................................................... 163 8.7.13 Miscellaneous Forms ........................................................................... 172 8.7.14 General Data........................................................................................ 175

APPENDIX 1............................................................................. 1

LWD LOGGING PROGRAMME ..................................................................................... 1 1.1 LWD - 17 ½” Hole ....................................................................................... 1 1.2 LWD - 12 ¼” Hole ....................................................................................... 1 1.3 LWD - 8 ½” Pilot Hole ................................................................................. 2 1.4 LWD - 8 ½” SideTrack Hole ........................................................................ 3

APPENDIX 2............................................................................. 1

DETAILED LOGGING PROGRAMME............................................................................... 1 2.1 Run 1 - Logging Run at Intermediate Casing - ITD2 ................................... 1 2.2 Run 1 - Descent #2:- GR/VSI...................................................................... 3 2.3 Run 2 - Logging Run at Pilot Hole Total Depth - PTD................................. 4 2.4 Run 2 - Descent #2 and 3:- GR/MDT ( Contingent ): .................................. 6 2.5 Run 2 - Descent #4:- GR/VSI :.................................................................... 7

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December, 2005 iii

LIST OF FIGURES, TABLES & ENCLOSURES

Figure 1: Location Map________________________________________________2 Figure 2: Stratigraphy of the Pearl River Mouth Basin________________________6 Figure 3: Survey Location of Liwan 3-1-1__________________________________8 Figure 4: Depth Structure Map – Near T50 Horizon. ________________________16 Figure 5: Seismic Line 04EC-LW31002. Location of Liwan 3-1-1.______________17 Figure 6: Seismic Line 93EC-1569. Location of Liwan 3-1-1. _________________18 Figure 7: Seismic Line 04EC-LW31002 Basin Configuration and Sedimentary Sequences.19 Figure 8: Prognosis and Summary Evaluation for Liwan 3-1-1.________________20 Figure 9: Depth vs Time Curve. ________________________________________21 Figure 10: Preliminary Well Design. _____________________________________22 Figure 11: Operational Flowchart – Dry Hole Scenario.______________________23 Figure 12: Operational Flowchart – HC Below 3160 m Only.__________________24 Figure 13: Operational Flowchart – HC in Miocene Turbidites Only. ____________25 Figure 14: Operational Flowchart – HC below 3160 m and in Miocene Turbidites. _26 Figure 15: LWD Programme for the Pilot Hole. ____________________________31 Figure 16: Logging and Coring Programme for possible Sidetrack(s). __________32 Figure 17. Well Summary_____________________________________________49 Figure 18. Pore Pressure Graph _______________________________________49 Figure 19. Wellbore Schematic ________________________________________50 Figure 20. 36" Casing Schematic_______________________________________58 Figure 21. 20" Casing Schematic_______________________________________73 Figure 22. BOP Schematic____________________________________________78 Figure 23. 13 3/8" Casing Schematic____________________________________90 Figure 24. 9 5/8" Casing Schematic____________________________________102 Figure 25. Drilling Time vs Depth Graph ________________________________168 Figure 26. Drilling Cost vs Depth Graph_________________________________168 Figure 27. Offset Well Designs (1) _____________________________________178 Figure 28. Offset Well Design (2) ______________________________________179 Table 1: Core Analysis Summary of Panyu 27-1-1. _________________________10 Table 2: Geological Prognosis/ Formation Tops. ___________________________13 Table 3: Sampling Programme. ________________________________________27 Table 4: Logging Abbreviations and their Explanations. _____________________33 Table 5: Logging Programme__________________________________________34 Table 6. Stratigraphic Tops ___________________________________________42 Table 7. Casing Design ______________________________________________45 Table 8. Casing Properties____________________________________________45 Table 9. Jetting Schematic ____________________________________________53 Enclosure 1: Summary Prospect Montage.

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December, 2005 iv

Signature Page Date Vice President - Exploration David R. Taylor _____________________________________ __________ Manager, Frontier & International Exploration David D. Johnson _____________________________________ __________ Manager, International Engineering Canada & Frontier Business Unit Janice Knoechel _____________________________________ __________ General Manager – Husky Oil China Wing-On Chu _____________________________________ __________ Chief, Drilling and Completions William Ellsworth ____________________________________ __________ Operations Manager Husky Oil China Fang Weihau ____________________________________ __________

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December, 2005 1

1. Summary Well Details Basin: Pearl River Mouth Basin

Petroleum Contract Area: 29/26

Husky Participating Interest: 100%

Location

Projection: WGS84

UTM zone: 50N

Central Meridian: 117°E

Latitude: 19.9120574°N

Longitude: 115.415119°E

UTNX: 334105.0E

UTNY: 2202531.20N

Seismic Location: Intersection 04EC-LW31002 SP2019.42

& 93EC-1569 SP1027.29

Water Depth: 1481 m

XY Target tolerance: 50 m

Prospect

Trap style: Faulted Anticline

Primary Target Formation: Zhujiang Formation

Secondary Targets: Zhuhai / (?) Wenchang / Enping Formations

Miocene Turbidite Fans

Chance of Success: 13%

Primary Target Depth: 3200 m SS

TD: 4071mSS (4094 m RT)

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December, 2005 2

2. Permit Details

The Liwan 3-1-1 wildcat is located within Deepwater Contract Area 29/26 in the

Pearl River Mouth Basin, Figure 1.

The Petroleum Contract was signed in August 2004, with a Commencement Date of

1 October, 2004. The drilling of the LW3-1-1 well will fulfill the work commitment

obligations, in full, for the first exploration term of the contract, which expires on 30

September, 2007.

180 km

Figure 1: Location Map

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3. Regional Geology The Pearl River Mouth Basin is one of four regional petroliferous basins located

along the northern continental shelf of the South China Sea. The Pearl River Mouth

Basin can be further sub-divided into three separate sub-basins. Two of these are

located on the present day continental shelf and the third is in deep water, sea-ward

of the present day shelf margin. Block 29/26 is located in this deep water area

known as the Zhu II Sub-Basin.

The Tertiary evolution of the Zhu II Sub-Basin can be divided into an Eocene to

Lower Miocene extensional phase marked by the development of fault-bounded

rifted sub-basins, followed by a Lower Miocene to recent passive margin phase,

typified by relatively unstructured deepwater sedimentation. Extension and rifting

was probably caused by a combination of both southward slab pull, related to the

subduction of the proto South China Sea oceanic crust and extension related to the

extrusion and clockwise rotation of Indochina along the north-west striking Red River

Fault.

The stratigraphy of the Pearl River Mouth Basin is presented in Figure 2. No wells

have been drilled into the deep water portion of the Zhu II sub-basin to date. The Eo-

Oligocene stratigraphy of the Zhu II sub-basin is anticipated to be similar to the syn-

rift stratigraphy encountered on the shelf at the Panyu and Liuhua gas fields just

north and west from Block 29/26, (Figure 1). The seismic shows that the basin rifting

is comprised of two significant syn-rift phases. These correspond to the Shenhu /

Wenchang (Eocene) and Enping / Zhuhai Formations (Oligocene to Lower

Miocene). Initial rift development during Early to Middle Eocene time resulted in the

deposition of the Shenhu / Wenchang Formations directly overlying the Base

Tertiary unconformity (Tg). Sediments are characterized by coarse-grained, often

mud-rich, matrix-supported conglomerate / diamictite indicative of high energy

alluvial fan deposition adjacent to highly active fault scarps. The second syn-rift

phase is marked by the deposition of the Enping Formation consisting of

predominantly fluvial to lacustrine sediments. The top of the Enping Formation is

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marked by an angular unconformity, (T70), which is overlain by the lower part of the

Zhuhai formation.

The Zhuhai Formation (Upper Oligocene to lowermost Miocene), is an overall

transgressive event typified by a generally fining upward sequence and represents

the initial transition from syn-rift to post-rift sedimentation. A similar sedimentary

sequence is expected for the Zhuhai Formation at LW 3-1-1. The section grades

from high energy, unconfined channel complexes at its base, to moderate and low

energy fluvial facies near the top. The Lower Zhuhai fluvial channels consist of

amalgamated coarse to fine sandstone and sparse shale. Fine grained, lacustrine to

floodplain facies may cap off the interval locally. The Zhuhai Formation terminates at

the 23.8 mybp, T60, sequence boundary, interpreted as the regional breakup

unconformity.

Within wells drilled on the present day shelf, the lower portion of the Zhujiang

Formation consists of marginal marine shoreface sandstones. This section is capped

by a major (?) marine flooding surface, T50, estimated at 21 mybp. The T50

sequence boundary is overlain by an overall progradational highstand sequence

consisting of predominantly tidal-dominated deltaic and shoreface deposits. This

alternation of low and highstand sedimentation is repeated several times throughout

Lower and Middle Miocene, terminating at the top of the Hanjiang Formation. The

Yuehai Formation represents the change to deposition on an open marine shelf,

which continues to the present day.

In contrast to the style of sedimentation occurring on the shelf, deep marine

conditions were established in Block 29/26, from Lower Miocene, T50 time,

onwards.

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The primary target for LW 3-1-1 is the deltaic to marginal marine shoreface

sandstones within the transitional phase between syn-rift and post-rift sedimentation.

These sandstones span the contact between the Zhuhai and Zhujiang formations at

the breakup unconformity.

LW 3-1-1 has potential secondary targets at two stratigraphic levels. The first is

interpreted to be fluvial sandstones within the syn-rift sediments of the Zhuhai

Formation, near TD. These are considered the deepest hydrocarbon target for LW 3-

1-1. Other secondary targets are interpreted as turbidite sandstones occurring within

the Miocene.

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Figure 2: Stratigraphy of the Pearl River Mouth Basin

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4. Prospect Details

4.1 Location The proposed well, Liwan 3-1-1, lies within Contract Block 29/26, in the Zhu II Sub

Basin of the Pearl River Mouth Basin.

The well is located in 1481 m water depth, 320km from the Chinese coast, 350km

southeast of Hong Kong and 65km southeast of the Panyu 30-1 and Liuhua 7-1 wet

gas discoveries. Co-ordinates for the location are outlined below and are shown in

Fig. 3:

Map Projection

Projection system: WGS84 UTM zone: 50 North Central Meridian: 117°E Prime Meridian: Greenwich False Easting: 500,000M False Northing: 0M Meridian Scaling Factor: 0.9996 Origin Latitude: 0.0°N Origin Longitude: 117.0°E Liwan 3-1-1 Well Location Latitude: 19.9120574°N Longitude: 115.415119°E UTNX: 334105.0 M UTNY: 2202531.2 M Intersection of 2-D seismic lines:

04EC-LW31002 (SPN 2019) 93EC-1569 (SPN 1017)

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December, 2005 8

Figure 3: Survey Location of Liwan 3-1-1

Well Location #1

93EC

1569_AR

CIS

1053

1043

1033

1023

1013

1003

04E

C-L

W31

0 02_

WG

2041

2031

2021

2011

2001

Well Location #1

Lat: 19.9120574° NLong: 115.415119° EUTMX: 334105.00 mEUTMY: 2202531.20 mN

WGS84UTM Zone 50 North

Central Meridian: 117° E

Prime Meridian: GreenwichFalse Easting: 500,000 M

False Northing: 0 MMeridian Scaling Factor: 0.9996

Origin Latitude: 0.0° NOrigin Longitude: 117.0° E

Map Projection

S. China Sea

CHINA

MAP AREA

METERS 0 100 200 METERS1:5000

WELL LOCATION #1

BLOCK 29/26SOUTH SEA, CHINA

SCALE: See Map Scale DRAWN BY: TAT KWAN

FILE: bk_42_05+bk_29_26.MFD, .ZGF

DATE: 2005.04.06

GEOLOGIST/GEOPHYSICIST: Michael Tinkler

PROJECTION: UTM WGS84 Zone 50 North

DATA SOURCE: OW Project (S_CHINA_SEA) SW2D Project (bk_05_26)

IMPORTRANT NOTICE: All coordinates are approximate.

MAP MAY NOT BE TO SCALE

South Sea, China

Well Location #1

Block 29/26

22

03

00

02

20

25

00

22

02

00

0

334500334000

115°24'45" 115°25'00"

19

°54

'30

"1

9°5

4'4

5"

19

°55

'00

"

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4.2 Trap

The Liwan 3-1 prospect is a large faulted anticline of up to 61+ square km in closure

(Figs. 4-7).

The LW3-1 structure developed during the Middle Miocene and later as a result of

the reactivation of a series of east-west striking, down-to-the-south extensional, rift

faults, initially developed in Eo-Oligocene times. One of these faults forms the

southern boundary of the prospect. The northern flank of the structure comprises an

east-west striking, antithetic, down-to-the-north fault, which arrests the regional

south directed dip within the basin. The LW3-1 prospect forms at the overlapping tip

points of these two faults (Fig. 4). Depth mapping of the T50 seismic marker

indicates the closing contour to be at -3360 m SS, giving a closure height of around

180 m.

The LW3-1 prospect exhibits both strong amplitude and AVO responses, which

largely conform to structure. The AVO response shows a strong increase in

amplitude with off-set for the trough immediately beneath the T50 seismic marker

and is believed to represent a direct hydrocarbon indicator, indicative of Type II / III

gas sand.

The proposed location for the LW3-1-1 well is towards the southern end of the

mapped closure at T50 level (Fig. 4). This location provides a relatively crestal

location on the structure, at the intersection of two 2-D seismic lines. The chosen

location is felt to represent an optimal position to test the mapped amplitude and

AVO anomalies associated with the prospect and maximize the likelihood of

achieving a good well to seismic tie.

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4.3 Reservoir

The primary reservoir target for the LW3-1-1 well is interpreted to be deltaic and

shoreface sandstones within the lower part of the Zhujiang Formation and possibly

the upper part of the Zhuhai Formation.

The nearest offset well to the prospect is the Panyu 27-1-1 well, which was drilled on

the shelf approximately 60 km to the northeast of the LW 3-1 prospect. The lower

part of the Zhujiang in this well (2758-2848m TVD) is comprised of four coarsening

upwards cycles consisting of fine to medium grained quartoze sandstone. Core

analysis from this interval indicate that tidally dominated deltaic and shoreface facies

contain the best reservoir quality sandstone. It is these sandstones that are

expected to represent the primary reservoir target in the LW 3-1-1 well.

Core analysis results from Panyu 27-1-1 are summarized in Table 1. The upper part

of the Zhuhai Formation (2848-3310m TVD) contains similar reservoir-quality

sandstones to those in the Zhujiang Formation, however, the reservoir facies are

interpreted as estuarine or bay-fill deposits and the sandstones are slightly more

argillaceous than the reservoir-quality sandstone in the Zhujiang, resulting in slightly

lower permeabilities.

Formation Cored Interval Ave Perm Kl (md) Ave Porosity (%)

Zhujiang 2765-2783 187 14.8

Zhuhai 3220-3245 115 15.1

Table 1: Core Analysis Summary of Panyu 27-1-1.

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4.4 Seal

A good regional top-seal for the primary target within the Zhujiang Formation is

expected to be formed by overlying deep marine shale. Strong support for the seal

is provided by the, “Amplitude Versus Offset”, (AVO), anomaly, identified on various

vintages of 2-D seismic data.

Fault seal is considered to represent a minor risk. The faults bounding the LW3-1-1

prospect do extend upwards into the younger Middle and Upper Miocene section.

However, given the fact that the primary target is expected to be overlain by a thick

succession of predominantly deep marine shale, these faults are considered to have

a high probability of sealing. Once again, the AVO response at the prospect level,

lends support to this argument.

Deep marine shale is also considered to provide good top-seals for any potential

turbidite fans that may be encountered in the Miocene.

4.5 Source/Migration

Since no wells have been drilled in the deep water portion of the Zhu II Sub-Basin to

date, the presence of an active petroleum system has yet to be proven. The

discovery of wet gas in the Panyu 30-1-1 and Liuhua 9-1-1 wells on the northern

flank of the Zhu II sub-basin indirectly suggests a petroleum system may exist.

Source rocks are expected to occur within the syn-rift, lacustrine shale of the

Oligocene Enping Formation and/or the Eocene Wenchang Formation. These

formations have provided source rocks for the sub-basins located in shallow water

along the present day shelf of the South China Sea.

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The geological risk associated with secondary migration and charging of the LW3-1

prospect is considered to be low. Firstly, the seismic data indicates a significant

thickness of syn-rift sediments directly underlying the LW3-1 prospect. This section

may contain significant source rock intervals for charging the prospect. Secondly, a

major syn-rift depo-centre has been mapped in the adjacent deepwater Block 42/05,

approximately 40 to 60 km to the west of the LW3-1 prospect. Although the

migration pathway is poorly understood, this depo-centre could act as the source

kitchen for the LW3-1 prospect. It is worth noting that the wet gas discoveries in the

Panyu 30-1-1 and Liuhua 9-1-1 wells are believed to be sourced from the Zhu II sub-

basin to the south, a distance of approximately 60-80 km.

4.6 Geological Prognosis

The geological prognosis for the well is presented in both Table 2 and Figure 8.

The anticipated total depth of the LW 3-1-1 well is set at 4071 m SS, 274 metres

below the top of the deeper secondary target. This should provide sufficient over-

hole to fully evaluate the anticipated reservoir section with down-hole logs. The

expected total depth will be revised should the well encounter hydrocarbon

indications near TD. The total depth will be adjusted in efforts to allow for full

logging and evaluation of all hydrocarbon bearing zones.

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Formation/Surface Prognosed

Depth (mSS)

Prognosed Depth

(mRT) Estimated Error

(+/- m)

Sea Floor 1481 1504 3

Top Fan (CNOOC) 2563 2586 100

Zhujiang Fm 2746 2769 100

Top Fan (Husky) 3000 3023 100

Intra Zhujiang (Near T50) 3200 3223 100

Primary Target (Trough

beneath Near T50) 3225

3248

100

Zhuhai Fm 3378 3401 100

Secondary Target 3797 3820 100

TD 4071 4094

Table 2: Geological Prognosis/ Formation Tops.

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4.7 Expected Sedimentary Section

Wanshan, Yuehai and Hanjiang formations (1481-2746 m SS)

Predominantly mudstone and siltstone with some intercalations of sandstone.

Mudstone is light to medium grey, soft, and silty. Locally, some fine to coarse

grained quartoze sandstone, calcareous with black and green lithoclasts,

occasionally chloritic, soft and hydrating. Mudstone becomes more consolidated

with depth. Siltstones grade to sandstone and mudstone.

Zhujiang Formation (2746-3378 m SS)

Predominantly sandstone with mudstone and siltstone. Sandstones are generally

quartoze to sublithic, light to medium grey with variable amounts of chlorite,

feldspars and black lithoclasts. Fine to course grained sandstone, friable,

moderately to poorly sorted with subangular to subrounded grains. The main target

for the LW 3-1-1 well is the sandstone through this interval. The sandstone is

occasionally white and very well cemented with calcite grading to sandy limestone.

The possibility of a tight limestone unit exists directly overlying the primary target.

Mudstone and siltstone are light to medium grey, occasionally sandy and grade

locally to fine sandstones. Mudstone and siltstone are micromicaceous, kaolinitic,

occasionally micropyritic and chloritic. Mudstone and siltstone are very calcareous

with black lithoclasts, predominantly soft and hydrating.

Zhuhai Formation (3378-4071mSS)

Interbedded sandstone, siltstone and minor mudstone in poorly defined coarsening

upwards cycles. Sandstone is quartoze, often white to light grey, commonly very

calcareous and variably kaolinitic, occasionally feldspathic, micaceous, pyritic and

locally, moderately chloritic. Fine sandstone is commonly argillaceous and grade into

siltstone. Sorting is moderately good with angular to subangular grains. Sandstone

is friable to slightly compacted.

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Mudstone and siltstone are dominantly medium grey-brown and occasionally light

grey-brown to off-white depending on the carbonaceous and kaolinite content.

Mudstone and siltstone are generally slightly calcareous, micaceous, firm, fissile and

slightly to moderately hydrating.

4.8 Potential Drilling Hazards

Geological overpressures and shallow water flows within the Miocene and younger

sediments are considered to represent the most significant potential drilling hazards

for the LW 3-1-1 well.

The site survey performed over the location indicates no issues with respect to

shallow gas over the LW 3-1 prospect. Pore pressure predictions based on an

analysis of the 2-D seismic velocities also suggest a lack of any major over-

pressures down to the primary target zone.

In general, shallow water flows, (SWF), are difficult to predict using seismic data.

However, two potential zones that could represent SWF’s have been identified using

the seismic from the site survey. These are at 30 m and 140 m below the mudline.

The 30 m anomaly is considered to be too shallow to hold appreciable pressure and

is therefore considered unlikely to represent significant risk. The risk associated with

the deeper anomaly is also considered to be low. Firstly, at 140 m, it is shallower

than typical SWF’s which usually occur at 250 – 600 m below mudline. Secondly, the

seismic shows evidence of micro-fracturing, which would have leaked off the excess

pressure, had it been present. As a precautionary measure, the possible presence of

SWF’s will be considered in the well planning.

Gas hydrates are another drilling hazard which can occur at these water depths. The

site survey does not indicate the presence of gas hydrates at the LW 3-1-1 location.

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Figure 4: Depth Structure Map – Near T50 Horizon.

LW 3-1-1P50 Area = 61 sq km; 3360 m subsea contour

B

B’

A

A’

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Figure 5: Seismic Line 04EC-LW31002. Location of Liwan 3-1-1.

LW 3-1-1 Location

T40

Near T50

? T70

N S

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Figure 6: Seismic Line 93EC-1569. Location of Liwan 3-1-1.

LW 3-1-1 Location

T40

Near T50

? T70

Tg

B B’

NNW SSE

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Figure 7: Seismic Line 04EC-LW31002 Basin Configuration and Sedimentary Sequences.

Basin Bounding Fault

Eocene - Oligocene

Lower Miocene

LW 3-1-1 Location

Tg

? T70

Near T50

T40

A A’

N S

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Figure 8: Prognosis and Summary Evaluation for Liwan 3-1-1.

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5. Preliminary Drilling Plan Outlined below in Figure 9 is a preliminary timing estimate for the drilling of Liwan 3-

1-1. Figure 10 is a preliminary schematic diagram showing the casing design.

Figure 9: Depth vs Time Curve.

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Figure 10: Preliminary Well Design.

8.5” Open Hole

36” Casing Jetted to 1556 m SS (1579 m RT) 26” Open Hole

17.5” Open Hole

12.25” Open Hole

20” Casing set at 2057 m SS (2080 m RT)

13 3/8” Casing set at 2362 m SS (2385 m RT)

9 5/8” Casing set at 3137 m SS (3160 m RT)

TD = 4071 m SS, (4094 m RT)

Surface Hole

First Intermediate Hole

Second Intermediate Hole

Main Hole

ITD1

ITD2

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Figure 11: Operational Flowchart – Dry Hole Scenario.

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Figure 12: Operational Flowchart – HC Below 3160 m Only.

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Figure 13: Operational Flowchart – HC in Miocene Turbidites Only.

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Figure 14: Operational Flowchart – HC below 3160 m and in Miocene Turbidites.

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6. Well Evaluation

6.1 Sampling Requirements

Since LW 3-1-1 will be the first deep water well to be drilled in the basin, CNOOC

has requested that Husky provide 2 m sample intervals throughout the well. Husky

will make every effort to achieve this sample rate, by employing 4 sample catchers.

It should be noted, however, that if living space on the ship becomes an issue, it

may be necessary to release up to 2 sample catchers in order to accommodate

more essential personnel. This could result in a lower density of samples, depending

on the drilling rate. Sampling requirements are summarized in Table 3.

Recipient Sets Rate Mass Sample Preparation Packaging

CNOCC 1 Every 2 m 500g Wet, Unwashed Plastic bags & Hubco bags

CNOCC 1 Every 2 m 500g Sieved, washed & dried Plastic bags & Hubco bags

Husky 1 Every 2 m 50g Sieved, washed & dried Paper Envelopes

Wellsite Geo 1 Every 2 m 20g Sieved, washed & dried Samplex Trays

Table 3: Sampling Programme.

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Samples Caught and Processed at the Rig

Two (500g) bags (one unwashed and one washed, clean and dry)

Samples must be air dried at a temperature not exceeding 40°C. They should not be

heated under a light. If complete drying is not possible, ship the sample damp.

• 2 m intervals from base of Surface Casing (SC), 2057 m SS to TD (4071 m SS).

At discretion of Wellsite Geologist in case of high ROP.

• Samples to be shipped to CNOOC office.

One (50g) packet (washed, clean & dry)

• 2 m intervals from base of surface casing, (2057 m SS) to TD, (4071 m SS).

• At end of well, the packets are to be shipped to Husky Oil China Office Shekou

Samplex Trays (20g) (washed, clean & dry)

• 2 m intervals from base of surface casing, (2057 m), to TD, (4071 m).

• At end of well, the trays to be shipped to Husky Oil China Office Shekou

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6.2 Mud Logging A surface logging service will be provided and shall include the following key items:

• Geological Survey: Sampling, Analysis, Data Handling

• Geological Sample Logging

• Gas Total Hydrocarbon Analysis

• Gas Chromatography

• Mud and Filtrate resistivity each day below 1000m and in oil/gas zones,

formation water resistivity from test shall also be determined.

• Abnormal Pressure monitor

• Shale Density

• H2S Detection

• Multi-User Data Acquisition and Processing

• Distribution of Information

• Engineering Application Station

• Data Handling

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6.3 Coring

The decision on coring will be determined by the technical project team in Calgary

subsequent to wireline log evaluation. Up to four 18m cores are programmed for the

well. Cores will only be acquired in the case where hydrocarbons are present in

reservoir-quality sandstone. The plan for acquiring core is to drill to TD and core via

one or more sidetrack well bores, following evaluation of drill and log data. This

methodology is now standard practice in wildcat drilling and has the following

advantages:

• It provides a cost saving in a dryhole case, as there is no need for slow,

controlled drilling in order to identify core points. Likewise, there is no need for

suspension of drilling while cuttings are circulated to surface in order to confirm

shows prior to pulling out of hole to core.

• A sidetrack has the advantage of being able to accurately select the optimum

core point. This will add significant value for any future development feasibility

study.

Since LW 3-1-1 is the first exploration well in the sub basin, it would be very difficult

to pick optimal core points, prior to proper evaluation of the section with wireline

logs.

Mud samples, (500ml), should be collected from the mud return flow line after

coring. Samples should be marked with date, time and current depth. Samples

should be shipped from the rig via supply boat to CNOOC to be handled by CNOOC

as required.

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6.4 LWD

LWD will be run in this well from surface casing shoe to TD using a GR/ARC tool.

This will aid in identifying hydrocarbons and choosing TD. Schematics of the LWD

programme are shown in Figures 15 and 16. Details of the LWD programme are

included as Appendix 1.

Figure 15: LWD Programme for the Pilot Hole.

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Figure 16: Logging and Coring Programme for possible Sidetrack(s).

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6.5 Wireline Logging Programme

The plan is to drill surface hole, run surface casing, drill an intermediate hole (17

½”), drill a second intermediate hole (12 ¼”), drill main pilot hole (8 ½”) to TD, and if

sands/fluid content warrant, drill sidetrack hole (8 ½”) to core sands of interest. A

liner will be run in the sidetrack hole although no testing will be undertaken at this

time. There is no open hole logging planned in the surface hole or first intermediate

hole. Two open hole logging runs are planned for the second Intermediate hole. The

main pilot hole and sidetrack holes will be tentatively evaluated as per programme.

Note that tool combinations/runs for each hole may be changed during drilling

depending on reservoirs encountered. An explanation of some of the logging

abbreviations used in this section of the booklet is included in Table 4. Below is a

summary of the wireline logging programme for Liwan 3-1-1 (Table 5). A detailed

programme is presented as Appendix 2.

Abbreviation Explanation Prognosed Depth SC Surface Casing 2057 m SS, (2080 m RT)

ITD1 Intermediate TD 1 2362 m SS, (2385 m RT)

ITD2 Intermediate TD 2 3137 m SS, (3160 m RT)

PTD Pilot Hole TD 4071 m SS, (4094 m RT)

STD Sidetrack TD Contingent

KOP Kick Off Point Contingent

LWD Logging While Drilling

Table 4: Logging Abbreviations and their Explanations.

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Run# Hole Size Mud Type Depth Logging Suite Descent# (in) (Interval)

LWD 17 ½ WBM 36” csg. to ITD1 GR/ARC1

LWD 12 1/4 WBM ITD1 to ITD2 GR/ARC1

R1-Des1 12 1/4 WBM ITD1 to ITD2 GR/EMS/PEX/AIT3 /DSI

R1-Des2 12 1/4 WBM 36” csg. to ITD2 GR/VSP

LWD 8 ½ WBM ITD2 to PTD GR/ARC1

R2-Des1 8 ½ WBM ITD2 to PTD NGT/EMS/DSI/PEX/AIT3

R2-Des2/3 8 ½ WBM Depths GR/MDT2

R2-Des4 8 ½ WBM ITD2 to PTD GR/VSI

LWD 8 ½ WBM KOP to STD GR/ARC1

R3-Des1 8 ½ WBM KOP to STD NGT/DSI/PEX/AIT3

R3-Des2 8 ½ WBM KOP to STD FMI

R3-Des3 8 ½ WBM Sands CMR

SC – Surface Casing ITD1 – Intermediate Casing (13 3/8”) ITD2 – Intermediate Casing (9 5/8”)

PTD – Pilot Hole TD STD – Sidetrack Hole TD KOP – Kick Off Point

1LWD1/2 to identify potential hydrocarbon zones, and may be run to aid in picking TD.

2Contingent on sands/fluids encountered. 3HRLA may be substituted depending on drilling mud salinity

Table 5: Logging Programme

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6.5.1 Open Hole Wireline Logging Programme.

Run 1 –Open Hole Interval is ITD1 to ITD2

GR/DSI/EMS/PEX/AIT

CASED HOLE GR-CNL (36” csg. Shoe to ITD1)

VSP (36” csg. Shoe to ITD2)

Run 2 –Open Hole Interval is ITD2 to PTD NGT/DSI/EMS/PEX/AIT

GR/MDT (Contingent on sands/fluids encountered)

VSP

Run 3 – Open Hole Interval is KOP to STD (Sidetrack to cut Core) NGT/EMS/PEX/AIT

FMI

CMR

Objectives: The PEX/AIT will provide the base data to determine porosity, lithology,

fluid type, saturation, permeability, net pay, and other petrophysical

parameters.

The DSI will be run to evaluate compressional and shear travel times to:

- aid in establishing porosity, and porosity type

- aid in AVO analysis

- provide a seismic tie

- model wellbore stability

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The CMR will provide data on pore size distribution, porosity, independent

of formation lithology, differentiate free and bound fluids, provide a good

estimation of permeability, and an attempt will be made to determine

hydrocarbon viscosity.

The FMI will be run to determine formation dips and locate faults. In the

zones of interest the FMI will be run in image mode to provide information

on formation orientation and structure, identify faults, and provide an

oriented electrical image to refine the geological and petrophysical

models.

The MDT will be run in different modes to:

• obtain a pressure profile identifying fluid contacts and reservoir fluid

density variations,

• obtain fluid samples to obtain hydrocarbon and water properties.

The VSI will acquire downhole seismic data to refine the seismic models

and interpretations. If casing is run, this service can be run in cased hole

(VSP mode). This acquisition is to act as a standard to properly adjust the

phase of the seismic and to have an unambiguous time-to-depth tie.

Base logs to be run in high-resolution logging mode in all zones of

interest, allowing the best possible formation evaluation in thin, laminated

zones.

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6.5.2 Logging Run in Sidetrack Hole for Core

Intermediate Casing: 9 5/8” @ 3137 m SS – ITD2

Core Sidetrack KOP: TBD

Bit size: 8 ½”

Total Depth: TBD (Estimated Sidetrack TD - STD)

Mud system: WBM

Run 3-Descent 1. GR/PEX w/AIT ( or HRLA ):

Gamma Ray, Platform Express, Litho Density, Compensated Neutron, and

Array Induction.

AIT-GR: STD to 25m above KOP

Vertical Scale: 1:200 and 1:500

Horizontal Scales:

Resistivities: 0.2-2000 ohm-m Log (Lower scale)

Resistivities: 0-50 ohm-m Lin (Upper Scale)

Resistivities: 1000-0 m-mhos Lin (Upper Scale)

GR: 0-150 API (Both scales)

TLD-HGNS-GR-CAL: STD to 25m above KOP

Vertical Scale: 1:200 and 1:500

Horizontal Scales:

GR: 0-150 API (Both scales)

Calipers: 6”- 16” (Both scales)

RHOZ/RHO8: 2 – 3 g/cc (Upper scale)

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PEFZ/PEF8: 0-10 Track 2 (Both scales)

HDRA: -0.05 to 0.45 g/cc Track 2 (Both scales)

DPHZ-NPOR/HNPO: 0.45 to – 0.15 (Lower scale)

LS Porosity Scales -Rho fluid 1 g/cc Rho matrix 2.71 g/cc

Note: 1. Make a complete “Hi-Res” pass with gamma ray, resistivity, density, and

neutron data over all potential pay sands. Hi-Res is on a scale of 1:120 and

AIT on one foot spacing. (Include two and four foot AIT spacings in digital

file).

2. Include in digital data, porosity on Sandstone (2.65 g/cc). and Limestone

Matrix (2.71 g/cc).

3. Hole size is 8.5”. Prepare tools accordingly.

4. If well is deviated, TVD required.

Run 3-Descent #2:- FMI:

Formation Micro Imager

FMI-GR: STD to 25m above KOP

FMI (image mode) over reservoir sections (final intervals determined by

Calgary office at time of logging).

Standard presentation and scales.

Images for Porosity Type and Structure.

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Run 3-Descent #3:- CMR: Combinable Magnetic Resonance

CMR-GR Intervals to be decided

Vertical Scale: 1:200

Horizontal Scales:

GR: 0-150 API (Lower scale)

Tension: Standard scales (Lower scale)

KTIM 0.1 – 1000 md (Lower scale)

KSDR 0.1 – 1000 md (Lower scale)

BFV: 0.3 – 0.0 V/V (Lower scale)

CMFF 0.3 - 0.0 V/V (Lower scale)

TCMR 0.3 - 0.0 V/V (Lower scale)

CMRP: 0.3 –0.0 v/v (Lower scale)

T2LM 0.1 – 1000 msec (Lower scale)

T2CUTOFF 0.1 – 1000 msec (Lower scale)

T2 Distribution 3 – 3000 msec (Lower scale)

Operation Notes: 1. Tension curve to be presented on all surveys, head tension device to be run

on all runs.

2. At least one 50 m repeat over a zone of varied response is required. If more

than one repeat is required, present all on final log. Tool should be repeated

until Companies' representative is satisfied with the data.

3. "Before" and "after" survey calibrations should be recorded, labeled and

included with master shop calibrations. Operations should not proceed if

sonde exceeds acceptable tolerances, unless approved by Companies'

representative.

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4. Overlap tie-ins by at least 30m.

5. Data transmission will be via satellite/internet.

6. If well is deviated, TVD required.

7. Ministry of Petroleum Industry Wireline Data Requirements

The following will be supplied as per article 23 of the “Regulations of the

People’s Republic of China on the Exploitation of Offshore Petroleum

Resources:

a) One (1) copy of any field print.

b) One (1) copy of any final print, to include processed log data.

c) After each logging run, LAS data representing all optical curves, on CD (1

copy).

d) One (1) copy of a 4 mm DLIS data tape (high density data stream 4/8 GB)

to be provided at end of well and to include all log data.

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8. Drilling Section

8.1 General Information and Well Data Contract Area: South China Sea Block 29/26 Well Designation: Liwan 3-1-1 Well Type: Exploratory Operator: Husky Oil China Ltd Planned Spud Date: 1st quarter 2006 Rig Name: Discoverer 534 Rig Type and Class: Drillship Rig Floor Elevation: 23 m Water Depth: 1481m Casing Shoe Depths: Casing Size Depth TVDRKB Depth MDRKB 36” 1579m 1579m 20” 2080m 2080m 13⅜” 2385m 2385m 9⅝” 3160m 3160m TD 4094m 4094m Surface Location Coordinates: Latitude: 19.9120574º N Northing: 2,202,531.2m Longitude: 115.415119° E Easting: 334,105m Tolerance: 50m Radius WGS: 84 UTM: 50 NORTH Primary Objective: Zhujiang Formation Secondary Objectives: Zhuhai / Wenchang / Enping Formations and Miocene

Turbidite Fans AFE Days: 66 days – Mob, Drill, Evaluate, P&A Well, Demob.

85 days – Mob, Drill, Evaluate, Sidetrack, core, evaluate, Suspend, Demob

AFE Number: US-12283 AFE Cost: 22,495,000 Drilled, Evaluated, abandoned

27,007,000 Drilled, evaluated, sidetracked, cored, evaluated and temporary abandoned with a 7” Liner in place.

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8.2 References

• Dril-Quip Service Manual #3640 • Husky Environmental Management Plan • Husky Oil Spill Response Plan • Husky Liwan 3-1-1 Geological Well Program

8.3 Geological Information

8.3.1 Objectives The Liwan 3-1-1 well will be drilled vertically as an exploration well to evaluate the potential for a commercial discovery within the Zhujiang Formation. A sidetrack well bore will be drilled to allow a quality core to be acquired over the crucial reservoir section if required.

8.3.2 Strataigraphy Depths

Geologic Tops Depth (m) TVDSS

Depth (m) RKB

Sea floor 1481 1504 Wanshan, Yuehai, and Hanjiang Fm

1481 - 2746 1504 - 2769

Zhujiang Fm 2746 - 3458 2769 – 3481

Zhuhai Fm 3458 - 4071 3481 – 4094 TD 4071 4094

Table 6. Stratigraphic Tops

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8.4 Drilling Operations Summary

8.4.1 Operations Summary The Discoverer 534 will be used to drill the Liwan 3-1-1. Husky will mob the rig from India to China. There will be a 10-14 day stopover in Singapore to allow Transocean to do some general rig maintenance, repair thrusters and restock the rig. Once the rig is on location final system checks and location verification will be conducted prior to operations commencing. The surface location is: Latitude: 19.9120574ºN Northing: 2,202,531.2m Longitude: 115.415119ºE Easting: 334,105m The tolerance is 50m The water depth on this location is expected to be ± 1481m. The 36” casing will be jetted to ±1579m. A 26” hole will be drilled to 2085m and 20” casing run and cemented at 2080m. The BOPS and riser will be run. A 17½” hole will be drilled to 2390m and 13⅜” casing will be run and cemented at 2385m. A 12¼” will be drilled to 3165m. Logs will be run and the 9⅝” casing will be run and cemented at 3160m. An 8½” hole will be drilled to a planned TD of 4094m. Logs will be run and evaluated. In the case of commercial hydrocarbons the well will be sidetracked and cored. After coring is completed a 7” liner may be run and cemented and the well will be suspended. If no commercial hydrocarbons are found then the well will be plugged and abandoned. All operational instructions, equipment movement and/or changes of plans shall only come from the Drilling Superintendent.

8.5 Potential Hazards

8.5.1 Offset Well References The closest offset well was drilled in 200m of water in the 1980s and is ±60Km away.

8.5.2 Shallow Hazard Survey The only potential shallow hazards the site survey indicated were two (2) buried slumps. One was at ±30m below the mudline and the other slump was ±140m below the mudline. Slumps are potential salt water flow anomalies but it is unlikely that either of these represent significant risk. Both of these anomalies are too shallow to hold appreciable pressure and there is evidence of micro-fracturing on the site survey seismic. These slumps could contain some pea sized rocks that could cause

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some tight hole and or sloughing. Hi-vis sweeps will be used to keep the hole clean and a pad mud will be spotted in the open hole prior to pulling out of the hole to run casing. Due to the fact that it is difficult to predict salt water flows and there is no offset data preparations will be made in the event that a shallow flow occurs a pump and dump method will be used. This method uses a weighted spud mud that is pumped down the drill string with returns to the seafloor. The site survey also indicated a very soft sea bed floor. This will be the third well to be jetted in China and data from the site survey indicated that there should not be any problems with jetting. A mud mat will be used to help ensure the wellhead does not sink into the soft seabed floor.

8.5.3 Pore Pressure/Fracture Gradients Both the site survey and 2D seismic indicated a normal pore pressure. The pore pressure and fracture gradients were developed from the 2D seismic data and based on Gulf of Mexico models.

8.5.4 Potential Lost Circulation Lost Circulation is always a possibility. Contingent plans are in place to combat seepage to complete losses.

8.5.5 Other Hazards Hydrogen Sulfide (H2S) gas has not been reported in the area and is not expected to be encountered. However, precautions will be taken at all times to ensure that the Rig and mud logger’s supplied H2S detection equipment is in good working order and monitored for the presence of H2S. Additionally, the mudlogging unit’s H2S continuous gas monitor in the gas sample line will be monitored. If H2S is detected, drilling will be suspended, conditions assessed and appropriate safety measures initiated.

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8.6 Casing Program

Min. Safety Factors

String OD/Weight/Grade Connection Shoe Depth (m)

Drift Diameter (inches) Burst Collapse

Structural 36”, 553 lb/ft, X-56 D-90 1579 m 33.0 Surface 20”, 166 lb/ft, X-56 S-60 2080 m 18.376 4.57 9.27Surface 13⅜”, 68 lb/ft, N80 BTC 2385 m 12.259 2.88 16.24

2.26 11.03Intermediate/ Production

9⅝”, 47 lb/ft, N-80 BTC 3160 m 8.525 1.35 1.68

Liner 7”, 26 lb/ft, N-80 BTC 4094 m 6.151 3.46 1.16Table 7. Casing Design

8.6.1 Casing Properties

Size (OD)

Weight (lb/ft)

Grade

Conn. Collapse Rating (psi)

Internal Yield (psi)

Joint Strength (1000 lbs)

Body Yield (1000 lbs)

I.D. (in)

Drift I.D. (in)

Cplg O.D. (in)

36” 553 X-56 D-90 2690 4080 9104 33 32 36.1220” 166 X-56 S-60 2510 3980 1450 2741 18.37 18.25 21.013⅜” 68 N-80 BTC 2270 4930 1850 1556 12.41 12.259 14.3759⅝" 47 N-80 BTC 4760 6870 1161 1086 8.681 8.525 10.6257” 26 N-80 BTC 5410 7240 667 604 6.276 6.151 7.656

Table 8. Casing Properties

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8.7 Drilling Operations/Procedures

8.7.1 Rig Move Reliance currently has the Discoverer 534 under contract in India. Once the rig is handed over to Husky it is planned to steam to Singapore, this is planned to take 10 days. A stopover of 10 - 14 days is planned in Singapore as Transocean will do some maintenance and restock the rig with supplies. The rig will steam to China and it is anticipated to take 8 days to travel from Singapore to China. Once the rig is near the location custom officials will meet the rig and the rig and rig crew will clear customs on location. It is planned to have a Husky drilling representative and a Modu-Spec representative on the rig prior to Reliance handing the rig over to Husky. Once on board the rig Modu-Spec will conduct a rig inspection and continue his inspection during the travel time from India to Singapore. The Modu-Spec representative will inspect the BOP Stack, mud pumps and draw-works as a minimum. Currently the BOP has a Drill-Quip Type DX connector on the bottom. This will need to be changed to a Cameron Collet Connector. Transocean is required to have a third party inspect all drill pipe, drill collars, subs, and other downhole tools within 30 days prior to mobilization. The drill pipe shall be inspected to a DS-1 Service Category “4” + UT slip/upset – Premium Class or better. All other items shall be inspected to a DS-1 Category 3 – 5. While the rig is in Singapore a BJ Cement representative and an Oceaneering representative will board the rig to conduct maintenance on their respective units. The Husky Representative shall familiarize himself with the rig and develop a “plan of attack” using the drilling program as a guide during the steaming time. It is planned to conduct a pre-spud meeting with the rig crews while the rig is in Singapore. A second Husky drilling representative will board the rig at this time.

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Anticipated Goals during rig move:

• Have Modu-Spec conduct a full inspection of the drilling unit and develop a preferred order of importance on any deficient items found by the inspection.

• Ensure the tubulars are inspected and any bad tubulars are marked in such a

manner that they will not be used.

• Obtain a joint count of all tubulars including the number and length of pup joints.

• Verify connections on all tubulars and compare to the drilling program.

• Develop a rig specific plan of attack using the drilling program as a guide.

• It is desirable to have 6½” liners in the mud pumps through the 26” hole size.

Once the BOPs are run it is desirable to have 6” liners in the mud pumps. Determine if it there will be enough man power to change the liners while running the BOP and riser. If not then we will opt to have 6” liners for the entire well.

• Inspect the suction screens on the mud pumps to ensure they are free of any

obstructions and/or debris.

• Ensure the bulk tanks are clean and ready to receive bulk material.

• Verify the swivel packing hours.

• Inspect the dies in the tong head and slips. Inspect all chain tongs and pipe wrenches to ensure they are in good condition.

• Inspect the saver sub and ensure there is sufficient spares on the rig.

• Verify the quantity of shaker screens.

• Ensure the mud pits are clean. Fill one pit at a time with seawater to ensure

there is no leakage from one pit to another pit.

• Stump test the BOPs as per program.

• Pressure test the TIWs and IBOPs.

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• Pressure test the manifold and Top Drive.

• Ensure the master bushing can be easily removed from the rotary table.

• Verify there are 13⅜” and 9⅝” casing elevators and slips on the rig.

• Review the initial load out lists with the rig crews to ensure a timely turn around of the vessels.

• Pick up and rack back drill pipe and 5 stands of HWDP.

• If any bentonite was left then mix up a pit of Hi-Vis mud.

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Figure 17. Well Summary

Figure 18. Pore Pressure Graph

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Figure 19. Wellbore Schematic

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8.7.2 36” Section

Objective: Jet 36” casing in place. Things to do prior to running 36” Structural Conductor: Strap the 36” casing and wellhead housing joint Strap the inner string BHA, the bit should be planned to stick outside of 36” ±6” Paint the shanks of the 26” bit white Paint the bottom 5m of the 36” shoe joint yellow with black stripes every meter. Paint the wellhead joint yellow with heavy black stripes every meter and smaller strips every half meter. Consider zero to be at the top of the 36” wellhead housing. Make up and rack back the jetting BHA. Conduct pump rate tests to determine minimum flow rate to turn bit. Prepare spud (hi-vis) mud and pad mud. Make up a 6 ” Reg Pin x 4 ” IF box crossover sub and a 10’ 5” Drill pipe pup joint on top of the 36” running tool. Make up 36” running tool in the 36” well head housing while the housing joint is on the pipe rack. Rig up rig floor for 36” casing operations. Have the MWD crew rig up enough cable to allow them to plug in and download the MWD when it is racked back. Write the well name on the wellhead to help the ROV identify the well at a later date. Review the jetting WOB vs. depth chart at the end of this section with the directional drillers and the Transocean drillers and tour pushers Review with the Drill Quip wellhead man to ensure the proper tools are on board and that there was no damage during shipment. Verify that the shackle pins that are to be used to run the 36” casing fit the welded pad eye eyes. Have the welder cut bigger holes if necessary while the joints are on the pipe rack. The proposed surface location for this well is: Easting = 334,105 m Latitude = 19.9120574 N Northing = 2,202,531.2 m Longitude = 115.415119 E Drill Quip has supplied a Retrievable/Re-Runnable Guideline less Guide Base. Transocean has a funnel down on their BOP stack. An onsite evaluation will determine the need of the Drill Quip guide base. It is preferred to NOT use the Drill Quip guide base if it is determined that the Transocean funnel is adequate. This would allow the ROV to be able to see the landing of the BOPs as well as help ensure there is no “trash” caught in the Drill Quip funnel. If the Drill Quip guide base is not used then care should be taken when stabbing the 26” bit and 20” casing into the 36” wellhead. 36” Casing: Also see schematic at the end of this section

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The 36” casing will run as below (bottom to top) Beveled plain end (shoe) x D-90 box (1.5” wall, 553 lb/ft) 5 joints of 36” x 1.5” wall (D-90 Connections) 36” well head joint (1.5” wall D-90 pin x 36” wellhead)

36” OD Casing

Weight (ppf)

Grade Pipe Yield (1,000 lbs)

Burst (psi)

Collapse (psi)

Optimum Make-up Torque* (ft*lbs)

Maximum Make-up Torque* (ft*lbs)

1.5” wall 552.69 X-56 9,104 4080 2690 36,000 50,000 • Minimum torque = 25,000 ft*lbs.

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Jetting BHA Item OD

(inches) ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

26” DSJC bit w/ 4 x 24 jets

26 2 2 875 7 ” Reg Pin ↑

A962M3460XP motor (17 ” Stab)

17 blades, 9 body

30 32 5,755 7 ” Reg Box ↓x 6 ” Reg Box ↑

Power Pulse High Flow MWD

8.41 26 58 3,100 6 ” Reg

Stabilizer 26 blades, 8 body

3 6 64 900 6 ” Reg

8” Drill Collar 8 2 30 94 4,500 6 ” Reg Stabilizer 26 blades, 8

body 3 6 100 900 6 ” Reg

5 – 8” Drill Collars 8 2 150 250 22,500 6 ” Reg Spacer Subs 8 3 4 (as

needed) 254 596 6 ” Reg

Crossover Sub 7 3 4 258 550 6 ” Reg Pin ↓ x 4 ” IF Box ↑

Drill Quip Running Tool

7 3 3 261 6,400 4 ” IF Pin ↓ x 6 ” Reg Box ↑

Crossover Sub 7 3 6 ” Reg Pin ↓ x 4 ” IF Box ↑

Air Weight 46,076 lbs Buoyed Wt 40,100 lbs In seawater Hydraulics In Out Depth (ft) 4900 5130 GPM 1200 1200 PV 15 15 YP 20 20 Mud Wt (ppg) 8.6 8.6 Pump Psi 3200 3270 MWD Psi Loss 640 640 Motor Psi Loss 200 psi 3% flow loss

Table 9. Jetting Schematic Ensure a ported flapper type float is installed in the motor.

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Running/Jetting Procedure: Move the mud mat to the moon pool and secure same on the spider beams. Rig up the rig floor. Bull tongs will be used to torque the D-90 connection. Rig up the slings/shackles on the bottom of the bails. The total air weight for the first 6 joints of the 36” casing string will be +/-70 tons so ensure the slings and shackles are rated above this value. Have the crane bring the shoe joint into the v-door area. Attach the shackles to the pad eyes. Pick up the shoe joint, cut the lifting eye (on pin end) off so it will not interfere with the mud mat, and lower it through the rotary. Land the joint in the rotary with the slips just below the pad eyes or land the pad eyes on the rotary table if landing in the slips is too high above the rotary to make up the connection. Bring in the next joint as above. Back out the box protector and pin protector after the 2nd joint has been picked up and secured. Inspect the threads on the box and pin and ensure there is a light coat of API modified thread dope. Stab the pin into the box and set the entire weight of this joint down. Apply a chalk mark across the connection to monitor the amount of turn applied when making up the connection. ± of a turn is required to fully make up the connection. Apply the backup bull tong and the make-up bull tong and tighten the connection with 36,000 ft*lbs torque (minimum 25,000 ft*lbs torque, maximum 50,000 ft*lbs torque). Install the Anti-rotation key by driving the key into the slot. Install the screw through the key and tighten to retain the key in the slot. Remove (welder to cut off) the pad eyes and lift eye and continue running the rest of the casing. The 36” wellhead joint should be picked up with the 36” running tool installed in it. Just prior to picking up this joint the elevators will have to be changed to drill pipe elevators. Once the wellhead joint is made up and lowered down install the Drill Quip hang off split plates which fit into the external recess groove of the 36” well head housing and lower to rotary. Record the weight of the 36” casing string (should be ±125,000 lbs buoyed weight, ±145,000 lbs air weight). Back out the running tool and rig up the false rotary, Drill Quip will provide the Drill collar support plate (false rotary). The bowl & slips to be used on the inner string are to be Weatherford supplied bowl and slips. Run the inner string BHA as per schematic below. Once the running tool is made up have the ROV verify the position of the bit compared to the 36” shoe (the bit should stick out ±6”)

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Ensure all of the bull plugs have been removed from the running tool. Record the 36” casing/inner string weight. This is to be the maximum WOB while jetting. The drill string should be rotated five (5) turns to the left to engage the running tool dogs into the wellhead. Verify the running tool is properly made up into the housing by checking the height of the indicator rod, it should be ” from the retainer ring. Turn the running tool back to the right of a turn to help ease the back out of the tool after jetting is complete. DO NOT EXCEED MORE THAN TURN TO THE RIGHT. Paint a vertical line on the stem and down onto the tool to aid the ROV in observing the turns to release the tool. Ensure the top-drive brake is locked to prevent rotation due to torque from the motor. PU and remove the hang off plate. Lower the 36” casing and latch into the mud mat. Install the slope indicator and record the bubble position, if this has not been done previously. Hold the weight of the casing and inner string with the block as the locking dogs of the mud mat are being engaged as the mud mat is NOT designed to support the weight of the casing string. Once below the splash zone, record buoyant weight of complete assembly. Continue running the 36” casing to the mudline (±1504m). Take into account that there is ±1.5m of stretch in the drill pipe once the 36” shoe is at the seafloor; adjust the RKB-ML figure by 1.5m. Have the ROV on bottom and monitor tagging of the mudline. Once the mudline is tagged make adjustments as needed to eliminate any additional connections – i.e. LD a single or PU a single as needed to get as close as possible to a full stand. The site survey showed a buried slump or infill at 30m below the mudline. There is a possibility of some gravel sized rocks in this and thus the hi-vis sweeps may have to be increased in both volume and frequency to help carry the gravel sized rocks out. Once jetting operations are ready to start, lower the 36” back to the mudline. Prior to starting to jet have the ROV verify the reading on the slope indicator. If the angle is greater than one-half degree ( ) move the rig accordingly to straighten the 36”. The contract between Husky and Transocean allows for a 1 maximum wellhead angle, thus it is recommended that Husky and Transocean senior rig site management agree on the wellhead angle at all times. Have the ROV monitor returns while jetting operations are being conducted and ensure that returns are coming out of the ports in the running tool. The time that the jetting starts shall be noted as the spud date and time.

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Record this time and date on the IADC and Husky morning reports. Record RKB- ML depth (take in account the 1.5m of stretch). Start mud pumps at lowest possible rate to help prevent the jets from plugging (as per test conducted when making up BHA). Mark the drill pipe with the 36” shoe at the mud line – zero the weight on bit at the driller’s console and mark the drill pipe every meter to monitor amount of pipe jetted. Allow the 36” to free fall until it takes 5,000 lbs weight. Slowly increase the pump rate, attempt to stay under 200 GPM for the first 15m of jetting. Have the ROV monitoring flow and ensure the flow is not coming up on the outside of the 36” Work pipe and pump 50 – 75 bbl hi-vis sweeps as needed. Pump a hi-vis sweep every connection as a minimum. Make an assessment of hole cleaning efficiency from PWD and ROV observations. Sweep frequency and volumes should be adjusted as required. If at any time steady progress is not being made it is recommended to reciprocate the casing to help “free” up the pipe movement. Prior to the last connection pick up high enough to observe mud ring on the 36” casing if the ROV can not see the painted marking while jetting. Confirm the mud ring and meter markings on drill pipe are the same. While jetting the last 6m start slowing pumps if possible. Once the 36” wellhead is jetted in place (mud mat is on the seafloor) circulate a 150 bbl hi-vis sweep and shutdown the pumps. Let the 36” soak at the TD WOB weight. Ensure the compensator is at mid-stroke. After allowing the 36” to soak for one (1) hour minimum (depending on ROV visibility may have to soak for a longer period). PU/SO, as required, so that the string weight at the running tool is at the neutral point. Monitor for subsidence of the 36”. Recheck bulls-eye. If subsidence is noted, support full casing string weight and wait for an additional hour. Slack off gradually and recheck for subsidence. The Drilling Supervisors should use their best judgment in determining the length of time that the 36” conductor should soak based upon actual jetting conditions. Have the ROV observe the slope indicator while the 36” is soaking. Record bulls-eye inclination angle at TD. Consult with the Husky Drilling Superintendent if the angle exceeds o. Unlock the top drive. Release the Drill Quip running tool by adjusting to leave 10,000 lbs over-pull at the running tool and turning to the right with 5 turns at the tool. Have the ROV monitor the turns. Allow the compensator to stroke closed – i.e. pull the running tool up out of the wellhead.

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Have the ROV monitor the wellhead until the 26” bit has cleared the wellhead. Care should be taken so that the 26” bit is not allowed to sit on top of the wellhead if a connection is made just as the bit clears the wellhead, may have to lay a single down. Throughout jetting operations, monitor the following operations with the ROV: Check to ensure that there are no returns around the 36” casing at the seafloor. On each connection, check bulls eye inclination reading to ensure angle is no greater than . Make sure running string remains straight and casing is traveling vert ically as the running string is lowered. Do not put 36” conductor above mud line in compression. Monitor to ensure that the wellhead running tool is not rotating and the vertical scribe line is in the same position. Monitor for returns at the wellhead running tool. Survey with the MWD every connection, inclination only. If MWD misses a survey do not recycle the pumps, continue jetting. Record the following in the IADC and Husky reports; Final bulls-eye inclination 36” shoe depth All MWD survey results RKB to mudline RKB to top of 36” housing sea floor water temperature (from ROV) Ensure the pad mud for the next hole section is ready to go and that there is enough hi-vis mud for the 26” hole section. Strap the 20” casing and 18 ” Wellhead housing.

Fluid Properties Seawater Hi-vis Pills Density 8.5 8.6 – 8.8 Funnel Viscosity NA >60 Plastic Viscosity NA ALAP Yield Point NA 40 – 60 Gels NA 14/18 – 16/20 pH NA 9 – 10 API Filtration NA NA Low Gravity Solids NA NA

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36" WellHead10' Stick-up Mud Mat

Mudline

D-90 PinD-90 Box

D-90 PinD-90 Box

D-90 PinD-90 Box

D-90 PinD-90 Box

D-90 PinD-90 Box

D-90 PinD-90 Box

Plain End w/I.D. Beveled

36" x 1½" wall

36" x 1½" wall

36" x 1½" wall

36" Casing

36" x 1½" wall

36" x 1½" wall

36" x 1½" wall

36" x 1½" wall

Figure 20. 36" Casing Schematic

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Tool DescriptionLength

(ft)Overall

Length (ft)Bottom

ConnectionTop

Connection O.D. (in) I.D. (in)Weight (lb/ft)

Cumulative Weight (lb)

Bouyant Weight (lb)

26" bit 2 2 NA7-5/8" Reg.

Pin 26 NA 437.5 875 761

Motor 30 327-5/8" Reg.

Box6-5/8" Reg.

Box 9.625 NA 192 6635 5768

MWD 26 586-5/8" Reg.

Pin6-5/8" Reg.

Box 8.41 5.9 119 9729 8457

26" Stabilizer 6 646-5/8" Reg.

Pin6-5/8 Reg.

Box 8 3 150 10629 9239

8" DC 30 946-5/8" Reg.

Pin6-5/8 Reg.

Box 8 2.875 150 15129 13151

26" Stabilizer 6 1006-5/8" Reg.

Pin6-5/8 Reg.

Box 8 3 150 16029 13933

5 - 8" DC 150 2506-5/8" Reg.

Pin6-5/8 Reg.

Box 8 2.875 150 38529 33492

Spacer/Crossover subs 8 2586-5/8" Reg.

Pin 4-1/2" IF Box 8 3 145 39689 34500

Running Tool 3 261 4-1/2" IF Pin6-5/8 Reg.

Box 7.625 3 2133 46088 40063

Jt # Description Length Overall Length (ft)

Bottom Connection

Top Connection

Pipe O.D.

Pipe I.D.

Connection O.D.

Connection I.D.

Weight (lb/ft)*

Cumulative Weight (lb)

Bouyant Weight

(lb)

36" Casing 0.00 0.0 0 0 0

1 36" Casing 40.00 40.0 Beveled D-90 36 33 36.12 32 552.69 22108 19212

2 36" Casing 40.00 80.0 D-90 D-90 36 33 36.12 32 552.69 44215 38423

3 36" Casing 40.00 120.0 D-90 D-90 36 33 36.12 32 552.69 66323 57635

4 36" Casing 40.00 160.0 D-90 D-90 36 33 36.12 32 552.69 88430 76846

5 36" Casing 40.00 200.0 D-90 D-90 36 33 36.12 32 552.69 110538 96058

6 36" Casing 40.00 240.0 D-90 D-90 36 33 36.12 32 552.69 132646 115269

7 WHH* 21.00 261.0 D-90 WH 36 33 36.12 32 696 147262 127970

261.0 147262 127970

147262 127970

* Overall weight for WHH and Mud Mat, not lb/ft.

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LW 3-1-1 36" Drill-In Schedule

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270

Penetration Below Mud Line, ft.

Slac

koff

Wei

ght (

k-lb

s)

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270

Penetration Below Mud Line, ft.

Slac

koff

Wei

ght (

k-lb

s)

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Distance from mud line to 36" casing shoe (ft) 261Air Weight of 36" Casing (lb/ft) 553 Air Weight of BHA from bit to Running tool (kips) 46 0

Depth BML (m)

Depth BML (ft)

Csg (kips)

Bouyant

Csg (kips) Min. Wkg. WOB

BHA (kips)

Bouyant

BHA (kips)

Bouyant Neutral Wt "Csg + Mud Mat + WHH (kips)

Max. Bouyant

Wt (kips)

W/in 20% of Max.

Bouyant Wt

(kips)

Recommended

Working WOB (k-lb)

Maximum Working

WOB (k-lb)

0 0.0 0 0 0 0 126 166 133 0 08.8 29.0 16 14 5 4 126 166 133 15 18

17.7 58.0 32 28 10 9 126 166 133 29 3726.5 87.0 48 42 15 13 126 166 133 44 5535.4 116.0 64 56 20 18 126 166 133 59 7444.2 145.0 80 70 26 22 126 166 133 74 9253.0 174.0 96 84 31 27 126 166 133 88 11161.9 203.0 112 98 36 31 126 166 133 103 12970.7 232.0 128 112 41 36 126 166 133 118 14779.6 261.0 144 126 46 40 126 166 133 133 166

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8.7.3 26” Hole/20” Surface Conductor Section

Objective: Drill a 26” hole to ±2085m. Run and cement 20” casing at 2080m. The site survey indicated a buried slump at ±1540m RKB (±140m below the mudline). The well will be on the edge of this slump and may miss it altogether. If the slump is penetrated it could cause some drilling problems with potential sloughing. If sloughing is evident the hi-vis sweep volume and/or frequency will have to be increased. Over pressure is not expected but there is a very slight possibility for a salt water flow (SWF). No other hazards were noted from the site survey. The 2D seismic predicted the potential of 8.8 ppg pore pressure at ±1800 meters RKB. It is felt that the accuracy of the site survey is better than the 2D seismic. It is intended to drill this hole section with seawater and hi-vis sweeps unless there is an indication of any potential of increasing pore pressure or any type of flow. If either the pore pressure increases or a flow is observed then immediately switch to the pump and dump method. If the pump and dump method is began then a short trip back to the 36” shoe may be required to allow enough time to mix the proper amount of weighted mud. 11.5 ppg pad mud at 1800m plus the column of seawater = 9.0 ppg EMW 11.5 ppg pad mud at 2085m plus the column of seawater = 9.3+ ppg EMW

Things to do prior to Drilling and Running casing: • Strap the 20” casing, shoe, and 18¾” wellhead joint. • Paint the bottom 3 meters of the 20” shoe joint yellow to aid with viewing the

stab-in with the ROV. • Paint the top 6 meters of the wellhead joint yellow with heavy black stripes every

meter and smaller stripes every half meter to aid the ROV in viewing the land out. • Install the centralizer stop rings on the 20” casing while on the pipe rack. Install 2

on the shoe joint – 1 ±1.5 meters above the shoe and the 2nd one ±3 meters below the box. Also install one per joint on the next 3 joints, install these mid-joint.

• While the casing is on the pipe rack prepare the box of the shoe joint and the pin of the 2nd joint for thread lock.

• Make up and rack back the cement head stand (TIW/side-outlet pump-in sub/TIW). The amount of drill pipe above and below the cement head should be determined by the space / land out design. Install a lo-torque valve on the pump in sub after it has been made up. Secure same with a safety strap. Close the lo-

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torque valve and tape this valve closed. Leave the TIWs in the open position. Ensure at least one TIW valve is available while drilling (Transocean is supposed to have 4 TIWs on the rig).

• Make up a 10’ 5” drill pipe pup joint and 4½” IF box x 6⅝” Reg Pin crossover on

top of the 18¾” running tool. Move the running tool assembly to the pipe rack and install the running tool assembly into wellhead housing. While on the pipe rack install the ball and check valve assembly in the running tool. Verify all of the bull plugs are tight.

• Ensure the lockdown ring is run on the 18-3/4” wellhead housing. • If possible pre-install the Standard Bucket Type Wellhead Housing Support Plate

onto the wellhead housing while on the pipe rack. Ensure that the support plate will not slide down the wellhead joint as it is being picked up.

• Inspect the Nominal bore protector for roundness and any other previous marks/damage. If possible pre-install the Nominal bore protector while the wellhead housing is on the pipe rack.

• Out of the critical path, jet/rod out the side outlet cement ports on the 36” wellhead housing with the ROV if they are plugged.

• The inner string bowl and slips are rented from Weatherford. • Ensure that at least 1400 bbls of 14.0 ppg mud has been mixed and is lined up to

feed the DKD system. 1400 bbls of 14.0 ppg mud and 1400 bbls of 11.2 ppg CaCl2 will yield 3,800 bbls of 11.5 ppg mud. Reserve pits hold 2800 bbls.

• Rig up the DKD system and mix one pit full of 9.0 ppg mud. Note the setting on the DKD unit.

• Mix one pit of 11.5 ppg kill weight mud. Note the setting on the DKD unit. Planned 20” Casing string:

Shoe x S-60 box +/-49 joints of 20” casing (166.4 lb/ft S-60 Connections) 18¾” well head joint (S-60 pin x 18¾” wellhead)

Pre-Drilling Notes: o It is planned to run 20” to 2080m. Drill the 26” hole to match the 20” casing strap

plus 5m of rat hole. o Monitor the MWD PWD (ECD) values continuously as an indicator of hole

cleaning and as an indicator of a water flow. o Monitor the MWD Resistivity for any indication of increased pore pressure. o Monitor the MWD Gamma Ray to ensure the casing shoe will NOT be set in a

sand. Be prepared to adjust the shoe depth by one or two joints if necessary to get through a sand at hole section TD.

o Have the ROV on bottom to monitor returns while drilling: Position the ROV near the wellhead to observe returns and to monitor for flow from the well. Occasionally monitor the cement ports below the low pressure housing assembly

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to confirm that they are clear. While rotating the drill string take precautions to keep the ROV tether and umbilical away from the rotating drill string.

o There is a very slight chance of Saltwater flows per the site survey. If one is

observed the following procedure should be followed:

Kill the well with weighted mud if the flow is strong. Determine the mud weight required to stop the flow so that 20” casing can be run

with the well static. If the flow is slight attempt to drill ahead with seawater and increase the ROP to

help increase the ECD. If drilling with ECD is determined not to be feasible then drill ahead with a weighted mud in a pump and dump manner.

If the pump and dump method is used then displace the drill string with 80 bbls of seawater just prior to shutting down the mud pumps for a connection. This will balance the mud and thus allow the well to be observed for flow during the connection.

Drilling Operation:

1) Make sure everything related to the 20” casing job is ready prior to moving forward as it should be planned to POOH and start running casing as soon as possible.

2) POOH with the jetting BHA. Lay down the 36” Drill Quip running tool, spacer

subs and motor.

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3) The drilling BHA will be:

Item OD (inches)

ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

26” DSJC bit w/ 4 x 24 jets

26 2 2 875 7⅝” Reg Pin ↑

Bit Sub bored for a float

9 3.5 3 5 500 7⅝” Reg Box ↓x 6⅝” Reg Box ↑

ARC 8.25 2.81 25 30 3,000 6⅝” Reg Pin ↓x 6⅝” FH Box ↑

Power Pulse High Flow MWD

8.41 5.9 26 56 3,100 6⅝” FH Pin ↓x 6⅝” Reg Box ↑

Stabilizer 26 blades, 8 body

3 6 62 900 6⅝” Reg

8” Drill Collar 8 2⅞ 30 92 4,500 6⅝” Reg Stabilizer 26

blades, 8 body

3 6 98 900 6⅝” Reg

3 – 8” Drill collars

8 2⅞ 90 188 13,500 6⅝” Reg

Crossover Sub 7 3 4 192 550 6⅝” Reg Pin ↓ x 4½” IF Box ↑

9 - HWDP 5 3 279 471 14,000 4½” IF Jars 6½ 2¼ 30 501 1,800 4½” IF 5 - HWDP 5 3 151 652 7,800 4½” IF Air Weight 41,825lbs Below Jars Hydraulics In Out Buoyed Wt 36,400 lbs In seawater Depth (ft) 5130 6820 PV 15 15 YP 20 20 Mud Wt (ppg) 8.6 9.0 Pump Psi 3400 4000 MWD Psi Loss 640 640 GPM 1200 1180

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4) Ensure the ROV is on bottom and ready to assist in stabbing the 26” bit into the 36” wellhead.

5) TIH, after the 26” bit is stabbed into the 36” well head run one more stand of

drill pipe. Mark the connection at the rotary table with a good mark (paint). This will be an indicator on the trip out that the driller is one stand away from clearing the wellhead and thus will allow for the ROV to be ready to view this event.

6) Drill as fast as possible on the first stand or two to reduce the chances of

washing out around the 36” shoe. Due to metal interference do not survey until the Bit is ±30m (MWD ± 18m) away from the 36” shoe. Do not cycle the MWD tools while near the 36” shoe.

7) Drill ahead to planned casing point plus 5m (rathole) using seawater and

pumping 50 bbl hi-vis sweeps at a minimum of every connection. No short trips are planned but the drilling supervisor should decide if one is needed due to hole conditions.

8) Make an assessment of the hole cleaning efficiency from the PWD and ROV

observations. Sweep frequency and volumes should be adjusted as necessary.

Drilling Parameters

Bit Size WOB Rotary RPM Jets GPM 26” 0 – 10 >100 4 x 24 ±1200

9) Take MWD surveys on the fly every connection. If a survey is missed

continue drilling. A good survey is required every 150m (500’).

10) Backream each stand once prior to making a connection. Maintain the rotary at >100 RPM to aid in hole cleaning while backreaming.

11) While drilling the last stand prior to TD start displacing the hole with 11.5 ppg

pad mud.

12) Note the amount of pad pumped when returns are observed at the seafloor. This will help with determining the amount of cement to be pumped.

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13) After the hole is displaced with the 11.5 ppg pad mud strap out of the hole. If

significant drag is noticed plan a wiper trip, otherwise POOH and run 20” casing. Have the ROV monitor the wellhead while the 26” bit is near the wellhead. Driller is to be cautious as to not set the bit down on the wellhead while setting the slips on the trip out of the hole. If necessary lay down a single to avoid the bit from “bouncing” on the top the wellhead while sitting in the slips.

14) While tripping, monitor the wellhead with the ROV to observe for flow. Stop

with the bit 9m below the wellhead. Circulate and wash out well head. Monitor the well for flow.

15) Have the MWD crew rig up enough cable to allow plug in to the MWD and

rack back of MWD prior to downloading the MWD. Plug into the MWD/LWD at the rotary table and rack the stand back. The download will be done offline and require a man to go up on the man-rider to unplug from the MWD/LWD after the download is complete.

16) During the last part of the drilling or on the trip out of the hole rig up Franks

Casing equipment as much as possible.

17) Ensure that the top 6m of the wellhead and the bottom 3m of the shoe joint are painted yellow with black stripes every meter.

Casing Running Operation: Clean one of the surface pits and start mixing the mix water for the cement job in the surface pit. Rig-up to run 20” 166.4#, X-56, S-60 casing. 20” OD Casing

Weight (ppf)

Grade Pipe/Connector Yield (1,000

lbs)

Burst (psi)

Collapse (psi)

Optimum Make-up Torque* (ft*lbs)

0.812” wall 166.4 X-56 2741/1450 3980 2510 20,000 * Minimum torque = 15,000 ft*lbs. Maximum torque = 50,000 ft*lbs

Annular Sections Unit Volume (bbls/ft)

Feet/meter Volume (bbls)

Percent Excess

Total Volume (bbls)

Cum.Total (bbls)

36” Casing x 5” DP 1.03 270’ 82m 278 0 278 278 26” OH x 5” DP 0.632 1650’ 503m 1045 50 1564 1842

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Once the float shoe is picked up verify flow through the float shoe is obtained.

Back out the box protector and pin protector after the 2nd joint has been picked up and secured.

Inspect the threads on the box and pin and ensure there is a light coat of API modified thread dope (first connection to be thread locked).

Stab the pin into the box and set the entire weight of this joint down. Apply a chalk mark across the connection to monitor the amount of turn applied

when making up the connection. ± ⅝ of a turn is required to fully make up the connection. Apply the backup bull tong and the make-up bull tong and tighten the connection

with 20,000 ft*lbs torque (minimum 15,000 ft*lbs torque, maximum 50,000 ft*lbs torque).

Thread-lock the shoe joint to the next joint. Install the centralizers on the 1st 4 joints. Fill each joint with seawater as much as possible while picking up the next joint, do not slow or stop the operation to fill the casing at this time. The pipe will not fill up completely due to the air gap.

Run all of the 20” casing. Prior to PU the wellhead joint change out the casing elevators to drill pipe elevators.

Make up the 18¾” wellhead joint and install the wellhead housing support plate if it has not already been done. Land the wellhead housing support plate on the rotary.

Back out the running tool and set aside. Install the Nominal Bore protector if it has not already been installed. Split the plastic protector of the wellhead housing in half and place on top of the

wellhead housing. Install the drill pipe support plate on top of the plastic protector.

Make up the 5” cement mule shoe and run the 5” inner string so that the end of the drill string is ±12 meters (40’) above the 20” shoe.

PU and MU the running tool. The drill string should be rotated five (5) turns to the left to engage the running tool dogs into the wellhead. Verify the running tool is properly made up into the housing by checking the height of the indicator rod, it should be ⅞” from the retainer ring. Turn the running tool back to the right ⅛ of a turn to help ease the back out of the tool after jetting is complete. DO NOT EXCEED MORE THAN ¼ TURN TO THE RIGHT. Paint a vertical line on the stem and down onto the tool to aid the ROV in observing the turns to release the tool.

Ensure the top-drive brake is locked to prevent rotation while RIH. PU and remove the hang off plate.

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Verify the ball valve is open, the check valve is installed properly, and all of the bull plugs are tight.

Lower the assembly to the sea level and fill the 20” casing with seawater using the top drive.

Once the 20” is full close the valve as required and continue in the hole. Fill the drill pipe with seawater after 15 stands.

Over pull calculations:

Casing Size 20” Casing weight (lb/ft) 166.4 Buoyed Weight (lb/ft)

137.1 In 11.5 ppg mud (BF = 0.824)

144.9 In seawater (BF = 0.871)

Footage 585m (1920’)

Total Casing Weight (lbs)

263,232 In 11.5 ppg mud

278,208 In seawater 5” Drill pipe tensile (premium)

560,800 lbs

Inner String Weight (lbs)

31,910 In seawater

Drill pipe Weight (lbs)

83,285 In seawater down to wellhead

Maximum overpull (lbs)

182,373 In 11.5 ppg mud w/csg at TD

167,397 In seawater w/csg at TD

a) Have the ROV monitor the stab-in at the 36” wellhead. Also have the driller

watch the weight indicator to ensure the 20” casing is not tagging up while entering the wellhead area.

b) Once inside the 36” casing, stop at the first connection and displace the drill

pipe with 11.5 ppg pad mud (±85 bbls). CAUTION: Run in hole slowly and caution drillers to react quickly if a bridge is encountered to prevent buckling the drill pipe and/or 20” casing. Buckling and collapse are two problems associated with running 20” casing in deep water. THEREFORE, TO PREVENT BUCKLING, MONITOR THE PROGRESS OF 20”

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BELOW THE MUD LINE WITH THE ROV AND COMPARE TO PROGRESS BELOW ROTARY i.e. slack off one meter of drill pipe, ROV should see one meter of casing movement into the wellhead. ALSO, MONITOR WEIGHT INDICATOR CONTINUOUSLY.

c) While running 20” casing into the 36” wellhead housing observe for returns

out each of the cement outlet valves. If there is any question as to whether the outlets or valves are plugged, use the ROV to jet them clean.

d) Continue running the 20” casing on 5” drillpipe. Make up the cement stand

and break circulation with 11.5 ppg pad mud. Gradually increase the circulating rate to full rate. Land the 18¾” housing into the 36” wellhead. Have the ROV monitor for settling as the weight is slacked off to latch the wellhead. Slack off a maximum of 75,000 lbs to latch the 18¾” wellhead. Once latched take an overpull of 50,000 lbs to verify latch. Continue circulating a minimum of one drill pipe (including inner string) volume plus 20 bbls (±135 bbls total) of 11.5 ppg pad mud.

e) Ensure there is no flow prior to cementing. RU and test the cement line. Close

the upper TIW valve while hooking up the cement line.

f) With the BJ cement unit mix the red dye into 10 bbls of seawater and pump same. Follow this with 90 bbls of seawater and a 50 bbl Mud Clean S spacer followed by cement as per cement program below.

g) Have the ROV monitor for flow through cement ports on the 36” housing

during circulation and cementing operations.

h) The volumes below should be confirmed prior to the job.

Section Unit Vol. (bbls/ft) Feet Volum

(bbls)% Excess

Total Vol. (bbls)

Cum. Total (bbls)

Vol. (ft3) Per Section

36” x 20” 0.669 261 175 0 175 175 980 26” x 20” 0.268 1658 444.3 100 888.6 1064 4989 20” Shoe Joint 0.328 30 9.8 0 9.8 1073 55

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This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig.

20” Cement (BHST = 60ºF)

Cement (TOC @ mudline)

Recipe Lafarge Class G + 17% LW-6 (microspheres) + 0.5 gps A-400L (strength enhancer) + 1.0 gps FL-45LS (Fluid Loss) + 0.13 gps CD-33L (Dispersant, turbulent flow inducer) + 0.01 gps R-8L (Retarder) + 0.03 gps FP-9L (Defoamer)

Number of Sacks

3400 sacks

Yield (cuft/sx) 1.78 Mix water type Sea Mix water amount

5.55 gps

Weight of Slurry

13.0 ppg

Pump Time (thickening time) 70Bc

5 hours 14 minutes

Compressive Strengths @ 45ºF

6:56 hours – 50 psi

13:20 hours – 500 psi 24 hours – 1289 psi

i) Cement volumes should be calculated to bring the cement top back to the

mudline and 100% excess in open hole.

j) Displace the cement with seawater to the end of the inner string + 3 bbls. Leave TOC 10m above the 20” shoe. Monitor returns with the ROV throughout the cement job. Note returns and estimated amount of cement returns on report.

k) There is ±450 psi pressure difference in the hydrostatic of the cement and

seawater when the cement is in place. Monitor the displacement pump pressure as an indication of the amount of lift.

l) Release the pressure and check the floats. If the floats fail then pump back in

with the volume bled off and hold the pressure for a minimum of one hour and repeat the bleed off procedure.

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m) If there is no movement in the wellheads slack off and release the running tool. Be prepared to pull up to clear the running tool of the wellhead as quickly as possible. If the wellheads move downward while slacking off weight, hold the casing in place until the cement sets up.

n) Once the running tool is backed out and cleared the well head, drop a foam

wiper ball and pump 117 bbls. A slight pressure increase should be seen when the foam wiper ball lands out in the cement stinger.

o) On the trip out caution the driller to monitor the end of the inner string while

sitting down on slips when the inner string is close to the well head. If necessary lay down a single to avoid the end of the drill pipe “bouncing” on the top the wellhead while sitting in the slips.

p) Break down the cement head once out of the hole.

q) Have the ROV install a cover over the wellhead.

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18¾" WellHead

S-60MT Threads

Install stop rings while casing is on pipe rack

1 centralizer at mid joint wrapped around stop ring

1 centralizer at mid joint wrapped around stop ring

1 centralizer at mid joint wrapped around stop ring

Thread Lock 2 centralizers, 1 @ 1.5m above shoe, the other at 3m below box

Float Shoe preinstalled

20" Casing

20", 166.4 #/ft

Figure 21. 20" Casing Schematic

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8.7.4 BOPs, Stump Testing, Running and Testing

Objective: Stump Test BOPs, Run and land BOPs. Test casing, connector against Blind Shear Rams and surface equipment.

BOPs are to be configured from top down as: 5,000 psi Annular 5,000 psi Annular Upper Blind/Shear Lower Blind Shear 5” Pipe Rams 3½” – 5” Variable Bore Pipe Rams The BOPS shall be stump tested against 3½” and 5” drill pipe with 250 psi low and 7000 psi high except for the annulars which will be tested to 3500 psi high. Each test shall be held long enough to draw a straight line on a chart for a minimum of 5 minutes. The next full BOP test will be 21 days after this test is completed. The Husky Drilling Representatives should closely monitor subsea maintenance operations. Rubber goods and sealing elements should be inspected. Install a new cadmium plated VX ring gasket prior to running BOP. The 18¾” wellhead has a Cameron Hub profile looking up. Ensure the BOP Hydraulic Wellhead Connector has been changed to the Cameron Collet Connector. Ensure the funnel is used if the Dril-Quip Guidebase was not run with the 36” wellhead. After POOH with 18¾” wellhead running tool, rig up the rig floor for riser running. Move the rig at least 60m off location. Move the BOPs under the rig floor and run the BOP and riser. Test the choke, kill, rigid conduit, and boost lines after initial make-up, after every 20 joints of riser have been run, and again just prior to picking up the landing/slip joints. Refer to the Transocean riser design and Riser and BOP Running Procedures. Transocean states their policy is to test after every 10 joints of riser, but they have not had any leaks on the lines since 2001. If there are any delays in riser movement, or a need to move a boat along the side of the rig then conduct a test on the lines during this time. The choke and kill lines are to be tested to 7000 psi and the boost line to 1000 psi. Test the conduit line to the operating pressure of the control system. All of these tests shall be held long enough to verify there is no leak. While running BOP and Riser record the following on the Husky morning report:

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• Buoyant weight of complete stack. • Buoyant weight of stack and riser prior to landing on wellhead. Have the ROV clean the wellhead area prior to landing the BOP. One joint prior to picking up the landing/slip joints:

1.) Have the ROV verify that the distance between the wellhead and the BOPs is the proper distance.

2.) Test the choke, kill, rigid conduit and boost lines. 3.) While making up the landing/slip joints move the rig back to location.

Install riser tensioners on slip joint. Tension up riser and install surface choke, kill, and boost lines. Test the choke and kill lines to 250/7,000 psi, the boost line to 1,000 psi and the rigid conduit line to the operating pressure of the control system. Lower the BOPs over the wellhead and land same. Observe the landing with the ROV. Lock the BOPs to the wellhead with the ROV watching the latch movement. Verify BOP is latched with fluid gallon count and by observing the connector indicator with the ROV. Take a 50,000 lb over pull to verify lock. Function test control lines, pods, remote valves and accumulators. Set all the weight of the BOP (except 50,000 lbs.) on the wellhead to ensure that the 36”/20” casing strings will support the BOP stack in case of disconnecting at a later date. Have the ROV monitor for any movement in the wellhead when the weight is sat down. While continuing the below and or rigging down the riser running equipment (i.e. offline) Rig up the BJ cement unit and break circulation down either the choke or kill line. Close the Upper Blind/Shear rams and test the Upper Blind/Shear Rams, Wellhead Connector and 20” casing to 250 psi low for 5 minutes and 900 psi high for 15 minutes, using seawater. Ensure that these tests are charted. Document the volume used vs. the pressure. This data will be used to compare with the shoe test after drilling out. Repeat this for the lower blind shear rams. Secure and tension the riser per Transocean policy. Have the ROV record the bulls-eye slope indicators on the BOP stack and the riser. Install an indexing line below the slip joint and extend to the rig floor. This line will be used to verify all landing depths for wear bushings and hangers.

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Once the slip joint is unlocked install the diverter. Function test the diverter system and flow through each valve. The TIWs and IBOPs should be tested off line in the sub-sea shop. If a manifold valve is leaking test it again off-line (while tripping) after it has been repaired or replaced. The BOPs are to be pressure tested every 21 days and function tested every 7 days. Document all test in the IADC and Husky daily report. The Blind/shear rams shall be functioned at least once per week. The Blind/shear rams shall be tested after each casing string is run. The test pressure shall be the casing test pressure. Document these events in the IADC and Husky daily report. Low Pressure

Test High Pressure Test

Low Pressure Test Time

High Pressure Test Time

Stump Test Annulars 250 3,500 5 5 All other components

250 7,000 5 5

Stack Landed Initially Blind Shears 250 900 5 15 All surface equipment

250 5,000 5 5

Subsequent BOP Test Surface

Equipment 250 5000 5 5

Pipe Rams 250 5000 5 5 Annulars 250 3500 5 5

Casing Test 20” x Blind Shears

250 900 5 15

13⅜” x Blind Shears

250 1,750 5 15

9⅝” x Blind Shears

250 3,000 5 15

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Discoverer 534 Vesel Heading when landed Date BOP Bulls EyeWell LMRP Bulls EyeRKB- S/Bed 2nd Slick Bulls EyeEHOT with DP Stops Set @

B

LE

ED

CH

K O

I K

L E

L L

L I

I N

N E E

MPR

VPR

13.31

Wellhead Connector

Lower Pipe Rams : - 3 1/2"- 5" Variables with Shaffer Ultra Lock 2 B - Shaffer SLUpper Pipe Rams:- 5" Fixed, Posilocks- Shaffer SLLower Shear Rams:- V Shear Shaffer SL with PosilocksUpper Shear Rams:- V Shear Shaffer SL with PosilocksRiser ID 19.75" -- Choke & Kill ID 3" ------ Booster ID 3.326"

1.18

2.04Upper Annular

6.2 2.98

0.85Lower Annular

2.01Upper Shears

7.11 1.94

0.49Lower Shears

1.33

20" W/Head

36" Housing

0.489

Figure 22. BOP Schematic

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8.7.5 17½” Hole/13⅜” Intermediate Casing Section

Objective: Drill 17½” hole to ±2,390m. Run and cement 13⅜” casing at 2,385m. The Driller’s Method will be used in a well control situation. Thing to do prior to running 13⅜”:

• Strap the 13⅜” casing and the casing hanger. • Install the centralizer stop rings on the casing while on the pipe rack. • Ensure the mud loggers are rigged up and ready to go. • Witness the loading of the drill pipe dart and the 2¼” ball into the cement

head. • Make-up and rack back the 13⅜” casing hanger, complete with wiper plugs,

see details below. • Review hole section responsibilities with the mud loggers and MWD crew. • Verify that the Frank’s Shark Bite was pre-installed into the pin end of the joint

made up into the float collar. • Have the mud engineer inspect the mud pits after they are cleaned. • Once the pits are cleaned start preparing the Performax mud. • While on the pipe rack prepare (clean) the box of the float shoe, pin and box

of joint #2, pin and box of the float collar joint and the pin of joint #4 for thread locking.

13⅜” casing Hanger

Make up a 6⅝” Reg Pin x 4½” IF Box crossover sub on the bottom of a stand of 5” drill pipe.

Pick up the 13⅜” Running tool and land in the rotary. Make up the stand with the crossover into the top of the 13⅜” Running tool

and rack this assembly back. Use Transocean’s 13⅜” bowl and slips for the casing hanger make up. PU the 13⅜” Casing hanger joint and land on the slips. Lower the running tool into the casing hanger while aligning the anti-rotation

keys into their slots in the hanger. Allow the running tool to stroke closed. PU to stroke the running tool open until the anti-rotation keys start to rise. Rotate the running tool clockwise to ensure it is fully unlocked. Measure the distance from the top of the anti-rotation key to the bottom of the

lower outer body of the running tool. It should measure 11⅜”. Rotate the running tool 3 turns counterclockwise, this will lock the tool open.

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Set the tool down and measure the distance from the top of the anti-rotation key to the bottom of the lower outer body of the running tool. It should measure 8⅞”.

Rotate the running tool 4 turns counterclockwise. This will lock the tool to the hanger. Measure the distance between the knurled indicator band and the top of the hanger. It should be ¼”.

Rotate the running tool 3 turns clockwise to unlock the tool from the hanger. Pick up out of the hanger and install new lead indicator pins. Verify the seal assembly rotates without binding. Install the wiper plugs. Black is top plug and red is bottom plug. Lower the wiper plugs / running tool assembly into the hanger. Water should

be sprayed on the ID of the casing to help with installing the wiper plugs. Fill the void area above the wiper plugs with water.

Align the anti-rotation keys. Set the entire weight of the running tool down. Rotate the running tool 3 turns counterclockwise to relock the tool to the

hanger. Measure the distance between the knurled indicator band and the top of the

hanger. It should be ¼”. Rack the assembly back using care to not damage the casing pin or the seal

areas. Run the Nominal Bore Protector (information only as the bore protector should have been installed in the wellhead prior to running the wellhead):

Make up the Multi-Purpose Tool (MPT) to a stand of 5” drill pipe. Install a rotary cover and set the nominal bore protector on the rotary table. Lower the MPT into the nominal bore protector aligning the J-lugs on the MPT

with the J-slots of the nominal bore protector. Turn the MPT to the left ⅛ turn. RIH and land out with a minimum of 20,000 lbs down. Do not set more than

60,000 lbs down. Adjust the weight to neutral at the tool and turn the drill string to the right ⅛

turn using chain tongs. PU and retrieve the MPT. Verify the nominal bore protector was set by pumping down the choke or kill

line at a high enough rate to establish ±1000 psi. As the running tool is pulled by the inlet a pressure increase should be noted. Mark the drill pipe as soon as the pump pressure increases and again when the pump pressure drops. This length should be the length of the MPT (±2’).

Once the MPT tool is laid down or in the case of the Nominal bore proctor being pre-installed prepare the MPT for retrieval of the Nominal Bore

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Protector by making up the Nominal Bore Protector Retrieval Adapter, Jet sub extension and Jet sub. Drilling Operations:

1) Make up the following BHA:

Item OD (inches)

ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

17½” XR+ bit w/ 3 x 18 jets & 1 x 20 center jet

17½ 1 1 875 7⅝” Reg Pin ↑

Bit Sub bored for a float

9 3.5 3 4 500 7⅝” Reg Box ↓x 6⅝” Reg Box ↑

ARC 8.25 2.81 25 29 3,000 6⅝” Reg Pin ↓x 6⅝” FH Box ↑

Power Pulse High Flow MWD

8.41 5.9 26 55 3,100 6⅝” FH Pin ↓x 6⅝” Reg Box ↑

Stabilizer 17¼ blades, 8 body

3 6 61 900 6⅝” Reg

8” Drill Collar 8 2⅞ 30 91 4,500 6⅝” Reg Stabilizer 17¼

blades, 8 body

3 6 97 900 6⅝” Reg

3 – 8” Drill collars 8 2⅞ 90 187 13,500 6⅝” Reg Crossover Sub 7 3 4 191 550 6⅝” Reg Pin ↓

x 4½” IF Box ↑ 9 – HWDP 5 3 279 470 14,000 4½” IF Jars 6½ 2¼ 30 500 1,800 4½” IF 5 – HWDP 5 3 155 655 7,800 4½” IF Air Weight 41,025lbs Below Jars Hydraulics In Out Buoyed Wt 35,117 lbs In 9.5 ppg mud Depth (ft) 6820 7820 PV 10 10 YP 20 35 Mud Wt (ppg) 9.5 9.5 Pump Psi 3775 3900 MWD Psi Loss 640 640 GPM 1100 1075

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2) Function test the diverter on the trip in the hole. Pump seawater through all

lines at a maximum rate to ensure that the valves functioned and the lines are open. Conduct a BOP diverter drill.

3) While tripping in the hole displace the choke, kill and boost lines with 9.5 ppg

Performax Mud. When displacing the choke, kill, and boost lines monitor the pit volume. The difference in the mud weights will cause a siphoning effect and relying on pump strokes alone could result in over displacement of these lines.

4) Build and pump a 50 bbl viscous spacer to be used in front of the Performax. Once on bottom and while drilling out the cement displace the hole with 9.5 ppg Performax Mud. Once the mud has reached the boost line start the 3rd mud pump on the boost line. Have the mud engineer at the gumbo box to monitor the returns. As soon as the mud is coming back start taking returns down the flow line. Do not drill the float shoe. Adjust the riser tension for the difference in the mud weights.

5) Start the displacement once a full stand is made up and do not make a

connection until the displacement is finished to limit the amount of fluid contamination. While pumping the initial displacement pump as fast as possible and keep the drill pipe rotating during the entire time.

6) Keep the rotary RPM at 30 – 50 during the entire displacement.

7) Once the displacement is above the BOPs start pumping down the boost,

choke and kill lines with the 3rd mud pump to ensure that all of the lines are full of good mud. After the displacement is complete obtain slow pump rates and choke and kill line friction pressures.

8) Drill the 20” shoe out, wash and ream the rat hole a few times to ensure it is

clean of any cement. Keep the rotary RPM at 30 -50 while the stabilizers are inside the casing. Drill 3m of new hole and circulate long enough to get the cuttings above the BOPs. Once the cuttings are above the BOPs pick up high enough to leave the bit just inside of the 20” shoe. Perform a FIT (Formation Integrity Test) by pumping down both the drillpipe and the kill line at ½ BPM. Monitor pressures every ¼ bbl. If a departure from a straight line is noticed shut down the pumps. The shoe should be tested to a maximum of 10.5 ppg EMW (355 psi with 9.5 ppg mud in the hole). If the shoe test is below 9.8 ppg EMW (105 psi with 9.5 ppg mud in the hole) notify the drilling superintendent.

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9) If a shoe squeeze is required POOH and rack back the BHA. TIH with open ended drill pipe to ±2085m. Mix and spot 25 bbls of cement (8 bbls in open hole and ±16m up into the 20” casing). POOH 2 stands, close the upper annular and perform a braiden/hesitation squeeze.

This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig. 20” Shoe Squeeze

(BHST = ºF) Cement

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry ppg

10) Open the upper annular and pump a foam wiper ball down the drill pipe. Continue pumping until bottoms up is above the BOPs. POOH and boost riser at the same time.

11) TIH with the same drilling BHA as above, drill out the cement and repeat the

FIT.

12) Drill ahead to ±2390m – casing strap + 5m of rat hole. Once the stabilizers have cleared the casing shoe speed the rotary up to >100RPM.

Drilling Parameters

Bit Size WOB Rotary RPM Jets GPM 17½” 0 – 25 >100 3 x 18, 20 CJ ±1100

13) Monitor the MWD Gamma Ray to ensure the casing shoe will NOT be set in a

sand. Be prepared to adjust the shoe depth by one or two joints if necessary to get through a sand at hole section TD.

14) Monitor off slips weight, torque, drag, and PWD constantly to ensure the hole

is being cleaned. Pump sweeps if necessary for hole cleaning.

15) As soon as it has been determined that the well is not flowing during a connection, kick in the riser pump and boost the riser while finishing making connections.

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16) Short trips are not planned for this hole section. The drilling supervisor shall

conduct a short trip if it is warranted.

17) Back ream each stand once prior to each connection. Rotate the drill pipe at ±100 RPM while back reaming each stand to aid in hole cleaning.

18) At TD, pump a 100 bbl hi-vis sweep and circulate the hole clean. Take an

MWD survey. Strap out of the hole.

19) Note: If significant overpull or swabbing is observed, go back to bottom and circulate the hole clean.

20) A wiper trip is not planned but if excessive drag is noticed a wiper trip shall be

conducted.

21) Once at TD obtain a temperature from the MWD to verify that cement pilot tests are run at the proper temperature. If any short trips are made note the bottom hole temperature and time off bottom on morning report.

22) Maintain the mud properties as per the table below:

MW PV YP Gels Filtrate pH NaCl – Cl HTHP LGS % 9.5 ALAP 20-35 5/15 < 6 10.4 – 10.8 100k –

140k < 15 <6

23) Ensure the MWD crew has rigged up enough cable to allow plug-in at the

rotary table and rack back prior to downloading the MWD.

24) Make up the MPT tool complete with jet sub, jet sub extension and adapter. TIH and land out with 20,000 lbs down to snap into the groove on the ID of the nominal bore protector.

25) PU and retrieve the MPT/bore protector.

26) Verify the nominal bore protector was latched by pumping down the choke or

kill line at a high enough rate to establish ±1000 psi. As the running tool/bore protector is pulled by the inlet a pressure increase should be noted. Mark the drill pipe as soon as the pump pressure increases and again when the pump pressure drops. This length should be the length of the MPT plus the bore protector (±7’).

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27) Drift the landing string with a minimum 2.75” drift. The BJ dart is 2.59”. Once out of the hole inspect the nominal bore protector for wear and/or damage. Redress the MPT for running of the 13⅜” wear bushing offline.

28) Ensure the cement head stand is made up and racked back.

29) Rig up the floor to run the 13⅜” casing. A casing swage is not required for this

casing string. Make up 2 joints of casing between the float shoe and the float collar. Thread lock all connections from the top of the float collar down. Once the float shoe is picked up ensure flow is obtained through it. Also once the float collar is made up ensure flow through it.

30) If the hole has been “acting” good consider closing the lower blind shear rams

and open up all valves on the Choke line while running the casing. This would reduce the surge on the formation and allow the well to be monitored.

31) All casing must be strapped and drifted to 12¼”. Ensure that no scale or other

foreign items were left in the casing. Visually verify that float equipment is free of debris.

32) See casing schematic at the end of this section

13⅜ Casing BTC

threads

Weight (ppf)

Grade Pipe Yield

(1,000 lbs)

Burst* (psi)

Collapse (psi)

Joint Strength

(1,000 lbs)

Coupling OD

(inches)

ID (inches)

0.48” wall 68 N-80 1556 5020 2260 1585 14.375 12.415 *Leak Resistance = 4930 psi

33) Continue running the 13⅜” casing. Fill the casing with mud every joint as much as possible while lowering the joint. Once all of the casing is run completely fill the casing with mud while changing to the drill pipe elevators. Pick up and make up the casing hanger assembly, monitor the running tool to make sure it is not backing out of the hanger while making up the casing hanger joint.

34) NOTE: If BOPs need to be tested run the Transocean test joint on top of the

Casing hanger running tool. Drift the joint to ensure the darts will pass through. As a reminder the BOPs shall be function tested every 7 days and pressure tested every 21 days.

35) Monitor returns while running each joint and adjust the running speed if

returns are falling off. The pit gain should be ±7 bbls gain (±1 bbl gain after fill-up) for every 12.2m joint of casing run. Once on drill pipe the gain should

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be ±2¼ bbls gain for each stand of dry drill pipe run. Run ±20 stands of drill pipe and break circulation for ±15 minutes. Open the blind shear rams and continue running the casing. Leave the choke, kill, and boost lines open to aid in mud flow-by Fill the drill pipe again after 20 stands (13⅜” shoe should be at the 20” shoe) and break circulation for ±15 minutes.

36) Slack-off slowly while lowering the hanger through the BOP and prior to

landing hanger. Over pull calculations:

Casing Size 13⅜” Casing weight (lb/ft) 68 Buoyed Weight (lb/ft) 58.1 In 9.5 ppg mud (BF = 0.854) Footage 890m (2919’) Total Casing Weight (lbs) 169,512 In 9.5 ppg mud 5” Drill pipe tensile (premium) 560,800 lbs Drill pipe Weight (lbs) 95,437 In 9.5 ppg mud down to

wellhead Maximum overpull (lbs) 195,850 In 9.5 ppg mud w/csg at TD

37) Space out with BJ cement head. Land the 13⅜” casing hanger in the 18¾”

wellhead with 20,000 lbs down. Recheck drill pipe measurements to verify depth. Close the choke and kill lines. Rig up and test cement lines.

38) Circulate and condition mud at a reduced rate and slowly staging up to until at

least one complete drillpipe + casing volume (±520 bbls) has been pumped. If mud losses are experienced then start cementing so as to minimize mud losses.

39) Pump 100 bbls MCS spacer. Mix and pump cement per below table. Kick out

top plug dart with cement. Displace cement with 9.7 ppg Performax mud. Bump plugs with 500 – 1000 psi over circulating pressure (Wiper plugs are rated for 4500 psi maximum). Do not pump more than 6 bbls (half of shoe track) over calculated displacement. Slow the displacement to 1 bpm on the last 10 bbls of displacement. The 1st plug (bottom plug) should launch with 800 – 1200 psi. The 2nd plug (top plug) should launch with 1800 – 1900 psi.

40) The volumes below should be confirmed prior to the job.

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This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig.

13⅜” Cement (BHST = 80ºF)

Cement TOC at 2233m (152m above 13⅜” shoe)

Recipe LAFARGE Class G + 0.5 gps FL-45LS (Fluid loss control) + 0.2 gps CD-33L (Dispersant) + 0.03 gps FP-9L (Defoamer) + Sea water

Number of Sacks 504 sacks Yield 1.18 cuft/sx Mix water type Sea Mix water amount 4.57 gps Weight of Slurry 15.8 ppg Pump Time (thickening time) 70Bc

4 hours 54 minutes

Compressive Strengths @ 70ºF

24 hours – 2620 psi

41) Cement volumes should be calculated for to bring the cement top back to

152m (500’) above the 13⅜” casing shoe with 50% excess in open hole.

42) Note returns on the morning report.

43) The hydrostatic of the 152m column of cement = 9.9 ppg EMW.

44) There is ±55 psi pressure difference in the hydrostatic of the cement and 9.5 ppg mud on the backside when the cement is in place (assumes displaced with 9.7 ppg mud). Monitor the displacement pump pressure as an indication of the amount of lift.

45) Release the pressure and check the floats. If the floats fail then pump back in

with the volume bled off and hold the pressure for a minimum of one hour and repeat the bleed off procedure.

46) Break the cement line off and leave the lo-torque valve open.

Section Unit Vol. (bbls/ft) Ft. Vol.

(bbls) PercentExcess

Total Vol. (bbls)

Cum. Total (bbls)

Vol.(ft3) Per Section

17½” x 13⅜” 0.124 500 62 50 93 93 522 13⅜” Shoe Trac 0.15 85 13 0 13 491 73

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47) Set 20,000 lbs down and mark the drill pipe at the rotary and again 1 foot above the rotary. Also mark a vertical line on the drill pipe. Rotate the drill pipe 5 - 6 turns to the right. The drill pipe should drop 10” – verify drop with marks on drill pipe. Set an additional ±50,000lbs down (70,000 lbs maximum) to fully energize the seal assembly.

48) Rig up the cement unit to pump down the kill line. Break circulation down the

kill line and up the riser, ensure the drill pipe is full and open to the atmosphere. Close the kill line valve(s) and test them to 7,000 psi. Open the kill line valve(s) and close the pipe rams. Pressure up to 4,000 psi as fast as possible to hydraulically set the annulus seal assembly. Monitor the volume pumped. If more than 1 bbl is pumped shut down and determine where the fluid is being pumped. Continue pressuring up to a maximum of 6,000 psi. Hold this pressure for 5 minutes. Bled off the pressure after testing and open the pipe rams.

49) Test the BOPS now if it is anticipated that a total of 21 days since the last

BOP test will elapse prior to running the 9⅝” casing string.

50) After the pressure test(s) are completed ensure all rams/annulars are open and pick straight up to release the running tool from the seal assembly. ±7,500 lbs per shear pin overpull should be noticed when releasing the running tool. To confirm the seal assembly was properly set pick up an additional meter and break circulation down the drill pipe for 2 minutes. Set back down with 70,000 lbs maximum and retest the seal assembly as above. Open the ram and POOH.

51) Re-dress the BJ cement head with the 9⅝” darts offline.

52) The Blind Shear rams vs. casing must be tested prior to drilling ahead. This

will be done on the trip in the hole with the 12¼” BHA. Run and Set the wear bushing:

Inspect the wear bushing for any wear or damage. Make up the Multi-Purpose Tool (MPT) to a stand of 5” drill pipe. Install a rotary cover and set the 13⅜” wear bushing on the rotary table. Lower the MPT into the wear bushing and snap into the wear bushing. Pick up to verify the wear bushing is properly engaged. RIH and land out with a minimum of 20,000 lbs down. Do not set more than

60,000 lbs down. PU and retrieve the MPT. ±30,000 lb overpull should be noticed when

releasing from the wear bushing.

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Verify the wear bushing was set by pumping down the choke or kill line at a high enough rate to establish ±1000 psi. As the running tool is pulled by the inlet a pressure increase should be noted. Mark the drill pipe as soon as the pump pressure increases and again when the pump pressure drops. This length should be the length of the MPT (±2’).

POOH and lay down the MPT tool. Dress the MPT tool for retrieving the wear bushing offline.

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1 centralizer over collar every 3rd joint for next 6 centralizers

1 centralizer over collar every 3rd joint for next 7 centralizers

9 centralizersTotal

1 centralizer over collar every 3rd joint for next 8 centralizers

1 centralizer over collar above float collarFranks Shark Bite preinstalled

Thread Lock Float Collar

2 centralizers, 1 @ 5' above shoe, the other at 10' below box

4 centralizers 2 centralizers, 1 @ 5' above shoe, the other at 10' below box

Float Shoe preinstalled

13⅜" Casing

13⅜", 68 #/ftN-80

Buttress Threads

Figure 23. 13 3/8" Casing Schematic

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8.7.6 12¼” Hole/9⅝” Intermediate Casing Section

Objective: Drill 12¼” hole to ±3,165m. Log. Run and cement 9⅝” casing at 3,160m.

Thing to do prior to running 9⅝”:

• Strap the 9⅝” casing and the casing hanger. • Install the centralizer stop rings on the casing while on the pipe rack. • Witness the loading of the drill pipe dart and 2¼” ball into the cement head. • Make-up and rack back the 9⅝” casing hanger, complete with wiper plugs,

see details below. • Review hole section responsibilities with the mud loggers and MWD crew. • Verify that the Frank’s Shark Bite was pre-installed into the pin end of the joint

made up into the float collar. • While on the pipe rack prepare (clean) the box of the float shoe, pin and box

of joint #2, pin and box of the float collar joint and the pin of joint #4 for thread locking.

• Verify the bullnose on the hole opener has been strap welded. 9⅝” casing Hanger

a. Make up a 6⅝” Reg Pin x 4½” IF Box crossover sub on the bottom of a stand of 5” drill pipe.

b. Pick up the 9⅝” Running tool and land in the rotary. c. Make up the stand with the crossover into the top of the 9⅝” Running tool

and rack this assembly back. d. Use Transocean’s 9⅝” bowl and slips for the casing hanger make up. e. PU the 9⅝” Casing hanger joint and land on the slips. f. Lower the running tool into the casing hanger while aligning the anti-

rotation keys into their slots in the hanger. Allow the running tool to stroke closed.

g. PU to stroke the running tool open until the anti-rotation keys start to rise. h. Rotate the running tool clockwise to ensure it is fully unlocked. i. Measure the distance from the top of the anti-rotation key to the bottom of

the lower outer body of the running tool. It should measure 11⅜”. j. Rotate the running tool 3 turns counterclockwise, this will lock the tool

open. k. Set the tool down and measure the distance from the top of the anti-

rotation key to the bottom of the lower outer body of the running tool. It should measure 8⅞”.

l. Rotate the running tool 4 turns counterclockwise. This will lock the tool to the hanger. Measure the distance between the knurled indicator band and the top of the hanger. It should be ¼”

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m. Rotate the running tool 3 turns clockwise to unlock the tool from the hanger.

n. Pick up out of the hanger and install new lead indicator pins. o. Make up the seal assembly and verify the seal assembly rotates without

binding. p. Install the wiper plugs. Black plug on top and red plug on bottom q. Lower the wiper plugs / running tool assembly into the hanger. Water

should be sprayed on the ID of the casing to help with installing the wiper plugs. Fill the void area above the wiper plugs with water.

r. Align the anti-rotation keys. Set the entire weight of the running tool down. s. Rotate the running tool 3 turns counterclockwise to relock the tool to the

hanger. t. Measure the distance between the knurled indicator band and the top of

the hanger. It should be ¼” u. Rack the assembly back using care to not damage the casing pin or the

seal areas.

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Drilling Operations: 1) Make up the following BHA:

Item OD (inches)

ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

12¼” S519BHPX bit w/ 7 x 12 jets

12¼ 1 1 575 6⅝” Reg Pin ↑

Bit Sub bored for a float

8 3 3 4 400 6⅝” Reg Box ↓x 6⅝” Reg Box ↑

ARC 8.25 2.81 25 29 3,000 6⅝” Reg Pin ↓x 6⅝” FH Box ↑

Power Pulse High Flow MWD

8.41 5.9 26 55 3,100 6⅝” FH Pin ↓x 6⅝” Reg Box ↑

Stabilizer 12¼ blades, 8 body

3 6 61 900 6⅝” Reg

8” Drill Collar 8 2⅞ 30 91 4,500 6⅝” Reg Stabilizer 12¼

blades, 8 body

3 6 97 900 6⅝” Reg

3 – 8” Drill collars

8 2⅞ 90 187 13,500 6⅝” Reg

Crossover Sub 7 3 4 191 550 6⅝” Reg Pin ↓ x 4½” IF Box ↑

9 - HWDP 5 3 279 470 14,000 4½” IF Jars 6½ 2¼ 30 500 1,800 4½” IF 5 - HWDP 5 3 155 655 7,800 4½” IF Air Weight 41,425lbs Below Jars Hydraulics In Out Buoyed Wt 34,900 lbs In 10.2 ppg

mud Depth (ft) 7820 10,380 PV 10 10 YP 20 35 Mud Wt (ppg) 9.7 10.2 Pump Psi 4000 4000 MWD Psi Loss 670 670 GPM 1050 925

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2) While making up the BHA rig up the cement unit to test the Blind Shear rams vs. 13⅜” casing. Break circulation and close the Upper Blind Shear rams. Test the casing/Blind Shear Rams to 250 psi low for 5 minutes and 1750 psi high for 30 minutes. Repeat this on the lower Blind Shear rams.

3) Function test the diverter on the trip in the hole. Conduct a BOP diverter drill.

4) While making up the BHA / tripping in the hole displace the choke, kill, and

boost lines and riser with 9.7 ppg Performax Mud.

5) Drill the 13⅜” shoe out, wash and ream the rat hole a few times to ensure it is clean of any cement. Keep the rotary RPM at 30 -50 while the stabilizers are inside the casing. Drill 3m of new hole and circulate long enough to get the cuttings above the BOPs. Once the cuttings are above the BOPs pick up high enough to leave the bit just outside of the 13⅜” shoe. Perform a FIT (Formation Integrity Test) by pumping down both the drillpipe and the kill line at ½ BPM. Monitor pressures every ¼ bbl. If a departure from a straight line is noticed shut down the pumps. The shoe should be tested to a maximum of 11 ppg EMW (530 psi with 9.7 ppg mud in the hole). If the shoe test is below 10.6 ppg EMW (365 psi with 9.7 ppg mud in the hole) notify the drilling superintendent.

6) If a shoe squeeze is required POOH and rack back the BHA. TIH with open

ended drill pipe to ±2385m. Mix and spot 25 bbls of cement (8 bbls in open hole and ±35m up into the 13⅜” casing). POOH 3 stands, reverse out 1.5 drillpipe volumes (±200 bbls), close the upper annular and perform a braiden/hesitation squeeze.

This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig. 13⅜” Shoe Squeeze

(BHST = ºF) Cement

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry Ppg

7) Open the upper annular and pump a foam wiper ball down the drill pipe.

Continue pumping until bottoms up is above the BOPs. POOH and boost riser at the same time.

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8) TIH with the same drilling BHA as above, drill out the cement and repeat the FIT.

9) Drill ahead to ±3165m – casing strap + 5m of rat hole. Once the stabilizers

have cleared the casing shoe speed the rotary up to >100RPM. It is planned to set this casing shoe ±80m above the potential pay zone.

Drilling Parameters

Bit Size WOB Rotary RPM

Jets GPM

12¼” 0 – 25 >100 7 x 12 1050 - 925

10) Monitor the MWD Gamma Ray to ensure the casing shoe will NOT be set in a sand. Be prepared to adjust the shoe depth by one or two joints if necessary to get through a sand at hole section TD.

11) Monitor off slips weight, torque, drag, and PWD constantly to ensure the hole

is being cleaned. Pump sweeps if necessary for hole cleaning.

12) As soon as it has been determined that the well is not flowing during a connection, kick in the riser pump and boost the riser while finishing making connections.

13) Short trips are not planned for this hole section. The drilling supervisor shall

conduct a short trip if it is warranted.

14) Back ream each stand once prior to each connection. Rotate the drill pipe at ±100 RPM while back reaming each stand to aid in hole cleaning.

15) At TD, pump a 100 bbl hi-vis sweep and circulate the hole clean. Take an

MWD survey. Strap out of the hole.

16) Note: If significant overpull or swabbing is observed, go back to bottom and circulate the hole clean.

17) A wiper trip is not planned but if excessive drag is noticed a wiper trip shall be

conducted.

18) Once at TD obtain a temperature from the MWD to verify that cement pilot tests are run at the proper temperature. If any short trips are made note the bottom hole temperature and time off bottom on morning report.

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19) Maintain the mud properties as per the table below:

MW PV YP Gels Filtrate pH NaCl – Cl HTHP LGS % 9.7 ALAP 20-35 5/15 < 6 10.4 – 10.8 100k –

140k < 15 <6

10.2 ALAP 20-35 5/15 < 6 10.4 – 10.8 100k – 140k

< 15 <6

20) Ensure the MWD crew has rigged up enough cable to allow plug-in at the

rotary table and rack back prior to downloading the MWD. Logging Operations:

a) Once out of the hole rig up wire line. Three logging runs are planned: b) Log #1 PEX/AIT/DSI/EMS/GR from section TD up to the 13⅜” shoe. c) Log #2 GR/CNT from the 13⅜” shoe up to the wellhead (cased hole) d) Log #3 VSI/GR from section TD to 26” shoe to the wellhead e) Ensure the logging crew brought a strip over kit with their tools. Monitor the

logging operations for indications of ledges, excessive line pulls, sticky hole sections, or fill on bottom. Do all Open Hole repeat sections as close to the casing shoe as possible.

f) Boost the riser and pump through the choke and kill lines in between

logging runs.

g) A wiper trip after logging is not planned. If one is made TIH with 12¼” Hole opener BHA:

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Item OD (inches)

ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

12¼” Hole Opener

12¼ 6 6 575 6⅝” Reg Pin ↑

Bit Sub bored for a float

8 3 3 4 400 6⅝” Reg Box ↓x 6⅝” Reg Box ↑

ARC 8.25 2.81 25 29 3,000 6⅝” Reg Pin ↓x 6⅝” FH Box ↑

Power Pulse High Flow MWD

8.41 5.9 26 55 3,100 6⅝” FH Pin ↓x 6⅝” Reg Box ↑

Stabilizer 12¼ blades, 8 body

3 6 61 900 6⅝” Reg

8” Drill Collar 8 2⅞ 30 91 4,500 6⅝” Reg Crossover Sub 7 3 4 141 550 6⅝” Reg Pin ↓

x 4½” IF Box ↑ 9 - HWDP 5 3 279 420 14,000 4½” IF Jars 6½ 2¼ 30 450 1,800 4½” IF 5 - HWDP 5 3 155 605 7,800 4½” IF

Wear Bushing Retrieval:

a) Make up the MPT tool complete with jet sub, jet sub extension and adapter. TIH and land out with 20,000 lbs down to snap into the groove on the ID of the wear bushing.

b) PU and retrieve the MPT/wear bushing. A ±7,500 lb overpull per shear pin

should be noticed.

c) Verify the wear bushing was latched by pumping down the choke or kill line at a high enough rate to establish ±1000 psi. As the running tool/wear bushing is pulled by the inlet a pressure increase should be noted. Mark the drill pipe as soon as the pump pressure increases and again when the pump pressure drops. This length should be the length of the MPT plus the wear bushing (±6’).

d) Drift the landing string with a minimum 2.75” drift. The BJ dart is 2.59”. Once

out of the hole inspect the wear bushing for wear and/or damage. Redress the MPT for running of the 9⅝” wear bushing offline.

e) Ensure the cement head stand is made up and racked back.

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Casing/Cement Operations:

I. Rig up the floor to run the 9⅝” casing. A casing swage is required for this casing string. Make up 2 joints of casing between the float shoe and the float collar. Thread lock all connections from the top of the float collar down. Once the float shoe is picked up ensure flow is obtained through it. Also once the float collar is made up ensure flow through it.

II. If the hole has been “acting” good consider closing the lower blind shear rams

and open up all valves on the Choke line while running the casing. This would reduce the surge on the formation and allow the well to be monitored.

III. All casing must be strapped and drifted to 8½”. Ensure that no scale or other

foreign items were left in the casing. Visually verify that float equipment is free of debris.

IV. See casing schematic at the end of this section

9⅝”

Casing BTC

threads

Weight (ppf)

Grade Pipe Yield

(1,000 lbs)

Burst (psi)

Collapse (psi)

Joint Strength

(1,000 lbs)

Coupling OD

(inches)

ID (inches)

0..472” wall

47 N-80 1086 6870 4760 1161 10.625 8.681

V. Continue running the 9⅝” casing. Fill the casing with mud every joint as much

as possible while lowering the joint. If the Blind shear rams were closed be sure and open them after ±115 joints of casing have been run. Leave the choke and kill line valves open to aid in mud flow by. Once all of the casing is run completely fill the casing with mud while changing to the drill pipe elevators. Pick up and make up the casing hanger assembly, monitor the running tool to make sure it is not backing out of the hanger while making up the casing hanger joint.

VI. NOTE: If BOPs need to be tested run the Transocean test joint on top of the

Casing hanger running tool. Drift the joint to ensure the darts will pass through. As a reminder the BOPs shall be function tested every 7 days and pressure tested every 21 days.

VII. Monitor returns while running each joint and adjust the running speed if returns are falling off. The pit gain should be ±3.6 bbls gain (±0.7 bbl gain after fill-up) for every 12.2m joint of casing run. Once on drill pipe the gain should be ±2¼ bbls gain for each stand of dry drill pipe run. Run ±20 stands

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of drill pipe and break circulation for ±15 minutes, 9⅝” shoe should be at the 13⅜” shoe. Continue running casing on drillpipe.

VIII. Slack-off slowly while lowering the hanger through the BOP and prior to

landing hanger. Over pull calculations:

Casing Size 9⅝” Casing weight (lb/ft) 47 Buoyed Weight (lb/ft) 39.6 In 10.2 ppg mud (BF = 0.843) Footage 1665m (5461’) Total Casing Weight (lbs) 216,265 In 10.2 ppg mud 5” Drill pipe tensile (premium) 560,800 lbs Drill pipe Weight (lbs) 94,208 In 10.2 ppg mud down to

wellhead Maximum overpull (lbs) 250,327 In 10.2 ppg mud w/csg at TD

IX. Space out with BJ cement head. Land the 9⅝” casing hanger in the 18¾”

wellhead with 20,000 lbs down. Recheck drill pipe measurements to verify depth. Close the choke and kill lines. Rig up and test cement lines.

X. Circulate and condition mud at a reduced rate and slowly staging up to until at

least one complete drillpipe + casing volume (±485 bbls) has been pumped. If mud losses are experienced then start cementing so as to minimize mud losses.

XI. Pump 100 bbls MCS spacer. Mix and pump cement per below table. Kick out

top plug dart with cement. Displace cement with 10.5 ppg Performax mud. Bump plugs with 500 – 1000 psi over circulating pressure. Do not pump more than 3 bbls (half of shoe track) over calculated displacement. Slow the displacement to 1 bpm on the last 10 bbls of displacement. The pressure required to launch the 1st plug (bottom plug) should be 800 -1200 psi. The 2nd plug (top plug) should launch with 1800 – 1900 psi.

XII. The volumes below should be confirmed prior to the job.

Section Unit Volume(bbls/ft) Feet Volume

(bbls) PercentExcess

Total Volume (bbls

Cum. Total (bbls)

Volume(ft3) PerSection

12¼” x 9⅝” 0.056 1000 56 35 76 76 425 9⅝” Shoe Track 0.073 85 6.2 0 6 210 35

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This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig.

9⅝” Cement (BHST = 185ºF)

Cement TOC at 2860m (300m above 9⅝” shoe)

Recipe LAFARGE Class G + 0.04 gps A-3L (extender) + 0.1 gps CD-33L (Dispersant) + 0.06 gps R-8L (Retarder) + 0.03 gps FP-9L (defoamer) + Sea water

Number of Sacks 390 sacks Yield 1.18 cuft/sx Mix water type Sea Mix water amount 5.07 gps Weight of Slurry 15.8 ppg Pump Time (thickening time) 70Bc

6 hours 01 minutes

Compressive Strengths @ 185ºF

24 hours – 3050 psi

XIII. Cement volumes should be calculated to bring the cement top back to 300m

(1000’) above the 9⅝” casing shoe with 35% excess in open hole. XIV. Note returns on the morning report.

XV. The hydrostatic of the 300m column of cement = 10.7+ ppg EMW.

XVI. There is ±106 psi pressure difference in the hydrostatic of the cement and

10.2 ppg mud on the backside when the cement is in place (assumes displaced with 10.5 ppg mud). Monitor the displacement pump pressure as an indication of the amount of lift.

XVII. Release the pressure and check the floats. If the floats fail then pump back in

with the volume bled off and hold the pressure for a minimum of one hour and repeat the bleed off procedure.

XVIII. Set 20,000 lbs down and mark the drill pipe at the rotary and again 1 foot

above the rotary. Also mark a vertical line on the drill pipe. Rotate the drill pipe 5 - 6 turns to the right. The drill pipe should drop 10” – verify drop with marks on drill pipe. Set an additional ±50,000lbs down (70,000 lbs maximum) to fully energize the seal assembly.

XIX. Rig up the cement unit to pump down the kill line. Ensure the drill pipe is full

and open to monitor for leaks past the seal assembly. Break circulation down

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the kill line and up the riser. Close the kill line valve(s) and test them to 7,000 psi. Open the kill line valve(s) and close the pipe rams. Pressure up to 4,000 psi as fast as possible to hydraulically set the annulus seal assembly. Monitor the volume pumped. If more than 1 bbl is pumped shut down and determine where the fluid is being pumped. Continue pressuring up to a maximum of 6,000 psi. Hold this pressure for 5 minutes. Bled off the pressure after testing and open the pipe rams.

XX. Test the BOPS now if it is anticipated that a total of 21 days since the last

BOP test will elapse prior to drilling to TD and logging. XXI. After the pressure test(s) are completed ensure all rams/annulars are open

and pick straight up to release the running tool from the seal assembly. ±7,500 lbs per shear pin overpull should be noticed when releasing the running tool. To confirm the seal assembly was properly set pick up an additional meter and break circulation down the drill pipe for 2 minutes. Set back down with 70,000 lbs maximum and retest the seal assembly as above. Open the ram and POOH.

XXII. The Blind Shear rams vs. casing must be tested prior to drilling ahead. This

will be done on the trip in the hole with the 8½” BHA. Run and Set the wear bushing:

Inspect the wear bushing for any wear or damage. Make up the Multi-Purpose Tool (MPT) to a stand of 5” drill pipe. Install a rotary cover and set the 9⅝” wear bushing on the rotary table. Lower the MPT into the wear bushing and snap into the wear bushing. Pick up to verify the wear bushing is properly engaged. RIH and land out with a minimum of 20,000 lbs down. Do not set more than

60,000 lbs down. PU and retrieve the MPT. ±30,000 lb overpull should be noticed when

releasing from the wear bushing. Verify the wear bushing was set by pumping down the choke or kill line at a

high enough rate to establish ±1000 psi. As the running tool is pulled by the inlet a pressure increase should be noted. Mark the drill pipe as soon as the pump pressure increases and again when the pump pressure drops. This length should be the length of the MPT (±2’).

POOH and lay down the MPT tool. Dress the MPT tool for retrieving the wear bushing offline.

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1 centralizer over collar every 3rd joint for next 7 centralizers

9 centralizers

1 centralizer over collar every 3rd joint for next 8 centralizers

1 centralizer over collar above float collar

Franks Shark Bite preinstalled Float Collar

Thread Lock 2 centralizers, 1 @ 5' above shoe, the other at 10' below box

4 centralizers 2 centralizers, 1 @ 5' above shoe, theon shoe track other at 10' below box

Float Shoe preinstalled

9⅝" Casing

9⅝", 47 #/ftN-80BTC

Figure 24. 9 5/8" Casing Schematic

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8.7.7 8½” Hole Section

Objective: Drill 8½” hole to ±4,094m. Log. Thing to do prior to Drilling Ahead:

• Review hole section responsibilities with the mud loggers and MWD crew. • Verify the bullnose on the hole opener has been strap welded.

Drilling Operations:

1) Make up the following BHA:

Item OD (inches)

ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

8½” MA616BPX bit w/ 6 x 10 jets

8½ 1 1 500 4½” Reg Pin ↑

Bit Sub bored for a float

6½ 2.81 3 4 300 4½” Reg Box ↓ x 4½” IF Box ↑

ARC 6¾ 25 29 3,400 4½” IF Pin ↓ x 5½” FH Box ↑

Power Pulse MWD 6.89 5.11 26 55 2,400 5½” FH Pin ↓ x 4½” IF Box ↑

Stabilizer 8¼ blades, 6½ body

2½ 6 61 400 4½” IF

Crossover sub 7 3 4 65 550 4½” IF Pin ↓ x 4” IF Box ↑

6½” Drill collar 6½ 2.81 30 95 2,750 4” IF Crossover sub 7 3 4 99 550 4” IF Pin ↓ x 4½”

IF Box ↑ Stabilizer 8¼ blades,

6½ body 2½ 6 105 400 4½” IF Pin ↓ x

4½” IF Box ↑ Crossover sub 7 3 4 109 550 4½” IF Pin ↓ x 4”

IF Box ↑ 3 – 6½” Drill collars 6½ 2.81 90 199 8,250 4” IF Crossover sub 7 3 4 203 550 4” IF Pin ↓ x 4½”

IF Box ↑ 9 - HWDP 5 3 279 482 14,000 4½” IF Jars 6½ 2¼ 30 512 1,800 4½” IF 5 - HWDP 5 3 155 667 7,800 4½” IF Air Weight 34,600bs Below Jars Hydraulics In Out Buoyed Wt 28,750 lbs In 11 ppg mud Depth (ft) 10,380 13,200 PV 10 10 YP 25 35 Mud Wt (ppg) 10.5 11 Pump Psi 4000 4000 MWD Psi Loss 560 560 GPM 580 525

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2) While making up the BHA rig up the cement unit to test the Blind Shear rams vs. 9⅝” casing. Break circulation and close the Upper Blind Shear rams. Test the casing/Blind Shear Rams to 250 psi low for 5 minutes and 3,000 psi high for 30 minutes. Repeat this on the lower Blind Shear rams.

3) Function test the diverter on the trip in the hole. Conduct a BOP diverter drill.

4) While making up the BHA / tripping in the hole displace the choke, kill, and

boost lines and riser with 10.5 ppg Performax Mud.

5) Drill the 9⅝” shoe out, wash and ream the rat hole a few times to ensure it is clean of any cement. Keep the rotary RPM at 30 -50 while the stabilizers are inside the casing. Drill 3m of new hole and circulate long enough to get the cuttings above the BOPs. Once the cuttings are above the BOPs pick up high enough to leave the bit just outside of the 9⅝” shoe. Perform a FIT (Formation Integrity Test) by pumping down both the drillpipe and the kill line at ½ BPM. Monitor pressures every ¼ bbl. If a departure from a straight line is noticed shut down the pumps. The shoe should be tested to a maximum of 12.5 ppg EMW (1080 psi with 10.5 ppg mud in the hole). If the shoe test is below 11.5 ppg EMW (540 psi with 10.5 ppg mud in the hole) notify the drilling superintendent.

6) If a shoe squeeze is required POOH and rack back the BHA. TIH with open

ended drill pipe to ±3,165m. Mix and spot 12 bbls of cement (4 bbls in open hole and ±35m up into the 9⅝” casing). POOH 3 stands, reverse out 1.5 drill pipe volumes (±260 bbls), close the upper annular and perform a braiden/hesitation squeeze.

This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig. 9⅝” Shoe Squeeze

(BHST = ºF) Cement

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry Ppg

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7) Open the upper annular and pump a foam wiper ball down the drill pipe. Continue pumping until bottoms up is above the BOPs. POOH and boost riser at the same time.

8) TIH with the same drilling BHA as above, drill out the cement and repeat the

FIT.

9) Drill ahead to ±4,094m. Once the stabilizers have cleared the casing shoe speed the rotary up to >100RPM. As with any exploration well TD could be changed depending on knowledge gained while drilling the well.

Drilling Parameters

Bit Size WOB Rotary RPM

Jets GPM

8½” 0 – 25 >100 6 x 10 580 - 525

10) Monitor off slips weight, torque, drag, and PWD constantly to ensure the hole is being cleaned. Pump sweeps if necessary for hole cleaning.

11) As soon as it has been determined that the well is not flowing during a

connection, kick in the riser pump and boost the riser while finishing making connections.

12) Short trips are not planned for this hole section. The drilling supervisor shall

conduct a short trip if it is warranted.

13) Back ream each stand once prior to each connection. Rotate the drill pipe at ±100 RPM while back reaming each stand to aid in hole cleaning.

14) At TD, pump a 100 bbl hi-vis sweep and circulate the hole clean. Take an

MWD survey. Strap out of the hole.

15) Note: If significant overpull or swabbing is observed, go back to bottom and circulate the hole clean.

16) A wiper trip is not planned but if excessive drag is noticed a wiper trip shall be

conducted.

17) Once at TD obtain a temperature from the MWD to verify that cement pilot tests are run at the proper temperature. If any short trips are made note the bottom hole temperature and time off bottom on morning report.

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18) Maintain the mud properties as per the table below: MW PV YP Gels Filtrate pH NaCl – Cl HTHP LGS % 10.5 ALAP 20-35 5/15 < 6 10.4 – 10.8 100k –

140k < 15 <6

11.0 ALAP 20-35 5/15 < 6 10.4 – 10.8 100k – 140k

< 15 <6

19) Ensure the MWD crew has rigged up enough cable to allow plug-in at the

rotary table and rack back prior to downloading the MWD. Logging Operations: A. Once out of the hole rig up wire line. Two logging runs are planned, the MDT is

contingent:

• Log #1 PEX/AIT/DSI/NGT/EMS from section TD up to the 9⅝” shoe. • Log #2 GR/VSI • Log #3 GR/MDT (contingent)

B. Ensure the logging crew brought a strip over kit with their tools. Monitor the

logging operations for indications of ledges, excessive line pulls, sticky hole sections, or fill on bottom. Do all Open Hole repeat sections as close to the casing shoe as possible.

C. Boost the riser and pump through the choke and kill lines in between logging

runs.

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D. A wiper trip during the logging is not planned. If one is made TIH with 8½” Hole opener BHA:

Item OD

(inches) ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

8½” Hole Opener 8½ 1 1 500 4½” Reg Pin ↑ Bit Sub bored for a float

6½ 2.81 3 4 300 4½” Reg Box ↓ x 4½” IF Box ↑

ARC 6¾ 25 29 3,400 4½” IF Pin ↓ x 5½” FH Box ↑

Power Pulse MWD

6.89 5.11 26 55 2,400 5½” FH Pin ↓ x 4½” IF Box ↑

Stabilizer 8¼ blades, 6½ body

2½ 6 61 400 4½” IF

Crossover sub 7 3 4 65 550 4½” IF Pin ↓ x 4” IF Box ↑

6½” Drill collar 6½ 2.81 30 95 2,750 4” IF Crossover sub 7 3 4 99 550 4” IF Pin ↓ x

4½” IF Box ↑ 9 - HWDP 5 3 279 378 14,000 4½” IF Jars 6½ 2¼ 30 408 1,800 4½” IF 5 - HWDP 5 3 155 563 7,800 4½” IF

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8.7.8 8½” Side Track Hole/7” Liner Section A more detailed program covering this operation will be sent to the rig once it is determined what is actually needed. Use the below as a guide line for now.

• A minimum of 12m (prefer 20m) of rat hole is needed between the bottom of the zone and the landing collar.

• Ensure the electric line crew brings out some RA pip tags. 1) After logging is completed rig down the electric line. Make up a cement head

consisting of a TIW, side door pump-in sub, TIW, 10’ pup joint. Lay this to the side. Make up the 5” cement stinger and TIH to set open hole cement plug(s). At least one open plug will be set above the hydrocarbon zone(s).

2) TIH to the top of the hydrocarbon zone. Make up the cement head and circulate

one complete bottoms up. Mix and pump cement as needed to end up with a 30m cement plug. POOH ±3 stands above the top of cement and reverse out 1.5 drill pipe volumes.

This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig.

8½” Open Hole Plug (BHST = ºF)

Cement

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry ppg

3) POOH to ±90m below the 9⅝” shoe. Make up the cement head and circulate one

drill pipe volume. Mix and pump cement as needed to bring the top of the cement up to ±50m into the 9⅝” casing. POOH 3 stands above the TOC and reverse out 1.5 drill pipe volumes. Drop a foam wiper ball and pump same down to the cement stinger. POOH.

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This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig.

Sidetrack Plug (BHST = ºF)

Cement

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry ppg

4) Test BOPs and/or slip and cut drill line if either of these are close to be needed to

be done.

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5) Make up the sidetrack BHA

Item OD (inches)

ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

8½” bit 8½ 1 1 500 4½” Reg Pin ↑ A675M4570XP motor w/1.15º bend and 8⅜” stabilizer sleeve

6¾ 5.5 27 28 2,200 4½” Reg Box ↓x 4½” IF Box ↑

8⅛” Stabilizer 6½ 2.5 6 34 400 4½” IF ARC 6¾ 2.81 25 59 3,000 4½” IF Pin ↓x

5½” FH Box ↑ Power Pulse MWD

6¾ 5.11 26 85 2,400 5½” FH Pin ↓x 4½” IF Box ↑

NMDC 6¼ 2.81 30 115 2,500 4½” IF 12 - HWDP 5 3 372 487 18,600 4½” IF Jars 6½ 2¼ 30 517 1,800 4½” IF 5 - HWDP 5 3 155 672 7,800 4½” IF Air Weight 29,600bs Below Jars Hydraulics In Out Buoyed Wt 24,600 lbs In 11 ppg mud Depth (ft) 10,380 13,200 PV 10 10 YP 25 35 Mud Wt (ppg) 10.5 11 Pump Psi 4000 4000 MWD Psi Loss 560 560 GPM 580 525

6) While drilling out the cement adjust the mud weight as needed. If firm cement is

not found with in 5m of the shoe consider picking up and waiting on cement. 7) Keep the rotary RPM at 30 – 50 while the stabilizers are inside the casing. 8) Continue drilling cement until kick off point is reached. Kick off at 3175m building

@ 3º/30m and at an azimuth of 325º. Continue building until end of build at 3350m. Angle at this depth should be 14.2º. Hold the angle @14.2º and azimuth @325º until 3450m and then start dropping back to vertical at 2º/30m. The end of the drop should be at 3662m. The vertical section should be 74m. Maintain this vertical section until TD is reached.

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9) The core point(s) will be based upon depth. Once core point is reached circulate the hole clean and POOH for the core barrel. Rabbit the drill pipe with at least a 1½” rabbit as the drop ball for the core barrel is 1¼”.

10) Monitor off slips weight, torque after each slide, and PWD constantly to ensure

the hole is being cleaned. Pump sweeps if necessary for hole cleaning. Refer to Appendix for an overview of PWD operations.

11) As soon as it has been determined that the well is not flowing during a

connection kick in the riser pump and boost the riser while finishing making connections.

12) Short trips are not planned for this hole section. The drilling supervisor shall

conduct a short trip if it is warranted. 13) Back ream each stand once prior to each connection. Rotate the drill pipe at

±100 RPM while back reaming each stand to aid in hole cleaning. 14) Maintain the mud properties as per the table below:

MW PV YP Gels Filtrate pH NaCl – Cl HTHP LGS % MW10.5 ALAP 20-35 5/15 < 6 10.4

– 10.8

100k – 140k

< 15 <6 10.5

11.0 ALAP 20-35 5/15 < 6 10.4 –

10.8

100k – 140k

< 15 <6 11.0

15) Ensure the MWD crew has rigged up enough cable to allow plug-in at the rotary

table and rack back prior to downloading the MWD. 16) Make up the 18m Hydro-Lift core barrel assembly. The core barrel is 6¾” x 4” x

18m. An 8½” x 4” ARC 412C3 core head is planned to be used. RIH with Core barrel, 23 joints of HWDP, jars, and 6 joints of HWDP to just above core point.

17) While making up the core barrel and TIH, condition the mud in 2 mud pits with 30

ppb Calcium Carbonate and 1 – 2 ppb Sodium Nitrate. The Calcium Carbonate will help prevent any intrusion into the core and the Sodium Nitrate will be used as a tracer to help determine if the water inside the core is from the formation or the drilling fluid.

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18) Once on depth with the core barrel space out to have a full 18m to work with – i.e. do not make a connection while coring. Make up the drop ball sub (pre-loaded with a 1¼” ball in ball sub). Lightly tag bottom to ensure the core barrel is on depth and circulate one drill pipe volume to ensure the core barrel is clear and to get the treated fluid down to the core head. Take slow pump rates while circulating.

19) Once the treated fluid is near the core head, pick up and break a connection and

drop the 1st ball (1” ball). This ball will seal off the inner core barrel. Circulate at 300 GPM until the ball seats (1 minute per 1,000’). A ±200 psi pressure increase will be noticed when the ball seats.

20) Start coring as per core engineers recommended WOB, RPM and SPM. These

numbers should be in the range of 5 – 8K lbs WOB, 70 – 100 RPM, and 100 – 250 GPM.

21) If the ROP is steady then time the dropping of the 2nd ball to allow for the ball to

land out just after coring the last foot of core. This ball (1¼”) is dropped by opening the drop ball sub. This ball activates the Hydro-Lift core catcher so do not pick up off bottom until the Hydro-Lift core catcher is closed. Pick up ±9m and tag bottom to confirm footage cut. If no fill, POOH. If there is fill then circulate the hole clean. Once the Hydro-Lift core catcher is closed circulation can be increased.

22) POOH following the schedule below:

45 seconds stand to stand up to ±650m 3 minutes stand to stand from ±650m to ±300m 6 minutes stand to stand from ±300m to ±100m 12 minutes stand to stand from ±100m to surface.

23) Prepare for the process of laying down the core to the extent possible while

POOH. Once the core barrel is at the rotary table pull it out and break out the core head and split ring housing. Install a protector sub. Run the core barrel back in and secure it with a safety clamp. Break out the safety joint. PU on lift sub and clamp off the inner barrel. Drill a ⅛” to ¼” hole in the 1st foot from the top of the inner barrel. This will vent any trapped gas. Proper PPE shall be worn while drilling this hole. The trapped gas should be minimal if any at all due to having the gas relief check valves but be prepared. Break out the inner barrel and lay down the safety joint. Place the core shuttle in the mouse hole. Place the lifting clamp on the inner barrel. Tie an air tugger to the lifting clamp and pull the 1st joint of the inner barrel out. Place the inner barrel clamp below the next connection and back out the connection using a 48” or 36” pipe wrench. Back out 6 turns and place the blade housing around the inner tube. Screw in the closing

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blade on the housing and then remove the housing. Turn the connection below the blade 3 more turns to finish separating the inner barrels. Screw on the thread protector until it is up against the blade. Remove the blade and tighten up the thread protector. Lower the inner barrel into the shuttle in the mouse hole after attaching the cable to the thread protector. Once in place pick up the shuttle and move to pipe rack area. Install the other shuttle in the mouse hole and repeat the same procedure for laying down the other inner barrel.

24) If it is planned to cut more cores rack back the core barrel. If this is the only core

then lay down the core barrel. 25) Once coring is complete make up the previous drilling BHA and TIH. 26) Ream the cored hole using. There may be a possible core stub sticking up on

bottom so lightly wash down the last meter to ensure the drill bit is not cored by the stub sticking up.

27) Drill ahead until the next core point or to TD. Ensure there is a minimum of 12m

(prefer 20m) of rat hole between the bottom of the zone and the landing collar. Monitor the surveys to ensure we do not get back into the original hole. Once the next core point or TD is reached circulate the hole clean and POOH. While on bottom obtain torque reading at 20 RPM while circulating bottoms up. Also stop once the bit is inside the casing and obtain torque reading while rotating at 20 RPM, this data will be used when running the liner. A wiper trip is not planned but if excessive drag is noticed a wiper trip shall be conducted.

28) Once at TD obtain a temperature from the MWD to verify that cement pilot tests

are run at the proper temperature. If any short trips are made note the bottom hole temperature and time off bottom on morning report.

29) Rig up electric line and log the well. It is planned to run 3 logs:

• Log #1 NGT/DSI/PEX/AIT • Log #2 FMI/GR • Log #3 CMR/GR

30) While logging rabbit the drill pipe to be used for running the liner with a 2½”

rabbit.

31) No wiper trips are planned between the logs. Monitor the logging operations for indications of ledges, excessive line pulls, sticky hole sections, or fill on bottom. Make a wiper trip with the BHA below if necessary to insure the log runs are successful.

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Item OD

(inches) ID (inches)

Length (feet)

Cum Length (feet)

Estimated air weight (lbs)

Connections

8½” Hole Opener

8½ 1 1 500 4½” Reg Pin ↑

Bit Sub bored for a float

6½ 2.81 3 4 300 4½” Reg Box ↓x 4½” IF Box ↑

Stabilizer 8¼ blades, 6½ body

2½ 6 10 400 4½” IF

Power Pulse MWD

6.89 5.11 26 36 2,400 4½” IF

Stabilizer 8¼ blades, 6½ body

2½ 6 42 400 4½” IF Pin ↓ x 4½” IF Box ↑

Crossover sub 7 3 4 46 550 4½” IF Pin ↓ x 4” IF Box ↑

3 – 6½” Drill collars

6½ 2.81 90 136 8,250 4” IF

Crossover sub 7 3 4 140 550 4” IF Pin ↓ x 4½” IF Box ↑

9 - HWDP 5 3 279 419 14,000 4½” IF Jars 6½ 2¼ 30 449 1,800 4½” IF 5 - HWDP 5 3 155 604 7,800 4½” IF 7” Liner Operations: a) The wear bushing should be left in place as the minimum ID is 8.822” b) A Weatherford 7" X 9⅝" Hydraulic Liner Hanger System consisting of a 10’

long 7½” ID PBR, ‘C-TSP’ liner top packer and ‘CTH’ hydraulic tandem cone liner hanger will be utilized.

c) Plan to set the liner shoe one meter off TD and have a 150m overlap into the 9⅝”

casing. 7” Casing

BTC threads

Weight (ppf)

Grade Pipe Yield (1,000 lbs)

Burst (psi)

Collapse (psi)

Joint Strength

(1,000 lbs)

ID (inches)

0.362” wall 26 N-80 604 7240 5410 667 6.276

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d) Make up the cement head and either lay out or stand it back in the derrick.

e) Install as many of the stop collars as possible while the casing is on the pipe rack.

f) Rig up the floor to run the 7” casing. A casing swage is not required for this casing string. Make up 2 joints of casing between the float shoe and the float collar. Make up the landing collar on top of the joint above the float collar. Thread lock all connections from the top of the landing collar down. Once the float shoe is picked up ensure flow is obtained through it. Also once the float collar is made up ensure flow through it.

g) If the hole has been “acting” good consider closing the lower blind shear rams and open up all valves on the Choke line while running the casing. This would reduce the surge on the formation and allow the well to be monitored.

h) All casing must be strapped and drifted to 6”. Ensure that no scale or other foreign items were left in the casing. Visually verify that float equipment is free of debris.

i) Ensure the RA tag(s) is installed as per schematic at the end of this section.

j) Continue running the 7” casing. Fill the casing with mud every joint as much as possible while lowering the joint. Once all of the casing is run completely fill the casing with mud while picking up the hanger assembly and installing the wiper plug system. Make up the casing connection. Obtain the weight of the liner. Make up top drive and circulate one casing capacity – do not exceed 500 psi. Boost the riser while circulating the one casing capacity.

k) Monitor returns while running each joint and adjust the running speed if returns are falling off. The pit gain should be 1.9 bbls (dry pipe) ±⅜ bbl (steel displacement) for every 12.2m joint of casing run. Once on drill pipe the gain should be ±2¾ bbls gain for each stand of dry drill pipe run.

l) While inside of the riser and the 9⅝” casing fill the drill pipe after each 10 stands have been run. Limit the standpipe pressure to 800 psi each time circulation is gained.

m) Open the blind shear rams after the first 10 stands of drill pipe have been run. Leave the choke, kill, and boost lines open to aid in mud flow-by.

n) After 70 stands have been run the 7” liner shoe should be close to the 9⅝” shoe. On this fill up break circulation and circulate for ±15 minutes, limit pump pressure

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to 800 psi. Once the liner is in the open hole do not stop to fill up the drill pipe unless there is a need to wash down.

o) Slack-off slowly while lowering the shoe joint and again when the hanger goes through the BOPs.

p) If the hole is acting good tag bottom as lightly as possible, pick up and space out with cement head. Circulate bottoms up while reciprocating the liner ±10m, limit the pump pressure to 1000 psi. Drop the 1.75” setting ball from the ball releaser in the cement head. Pump the ball down at 2-3 bpm with a maximum pressure of 700psi. The ball should take approximately 5 minutes per 300 meters to land on its seat. Watch the pressure gauge closely. When the ball lands, stop pumping and allow the pressure to stabilize. Slowly increase the pressure to 200 psi above that required to set the liner hanger and activate the hydraulic release. When the liner is hung off, slack off 30,000 lbs. Bleed off the pressure. Pick up to 20,000 lbs less than theoretical ‘neutral’ DP weight. Increase the pressure to 2,500 psi to release the HNG running tool from the liner. Pick up to check that the tool is free. Pick up must not exceed half the distance from the by-pass slots to the junk bonnet (generally 1.5 meters). If the liner weight has been lost, set down 25,000 lbs of weight on the liner. Shear out the ball seat and note the pressure. Check for returns after shearing.

q) Line up the cement unit, break circulation and test lines as required.

r) Make sure the cement spacer (50 bbls of MSC) is mixed at 0.5 ppg heavier than the mud weight and is ready to go.

s) Mix and pump cement as per table below. Slow the displacement down to ±3 bpm 2 bbls before the dart reaches the wiper plug. Note the pressure required to release the wiper plug. Increase displacement rate back up to optimum rate after the wiper plug is released. Slow the displacement to 1 bpm on the last 10 bbls of displacement. Bump plugs with 500 – 1000 psi over final circulating pressure. Do not pump more than 2¼ bbls (half of shoe track – shoe to landing collar) over calculated displacement.

t) The volumes below should be confirmed prior to the job.

Section Unit Volum(bbls/ft) Feet Volume

(bbls)PercentExcess

Total Volume (bbls

Cum. Total (bbls

Volume(ft3) PeSection

9⅝” x 7” lap 0.026 492 12.6 0 12.6 12.6 71 8½” OH x 7” 0.023 3000 69 15 79.4 92 446 7” Shoe Track 0.038 85 3¼ 0 3¼ 95¼ 18 Above Liner Top 0.049 100 4.9 0 4.9 100 28

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This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig.

7” Cement (BHST = ºF)

Cement (TOC at 100’ above liner top)

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry 15.8 ppg

u) Cement volumes should be calculated to bring the cement top back to 30m (100’)

above the liner top with 15% excess over the calculated open hole volume. Use the FMI 4 arm caliper if it is available for the volume to used over the open hole interval.

v) Use the cement unit for displacing the cement to remove any doubts about

the volume pumped. w) The hydrostatic of the full column (4075m – 3000m) of 15.8 ppg cement = 12.3

ppg EMW. x) There is ±875 psi pressure difference in the hydrostatic of the cement and

seawater when the cement is in place. Monitor the displacement pump pressure as an indication of the amount of lift.

y) Note returns on the morning report. z) Release the pressure and check the floats. If the floats fail then pump back in

with the volume bled off and strip out of the hole to position the rotating packer actuator above the top of the PBR. Stay “top-drived up” if possible to prevent any flow back.

aa) Pull the string back to position the rotating packer actuator above the top of the

PBR. DO NOT EXCEED THE CALCULATED PICK UP DISTANCE BY MORE THAN 1 meter. Rotate the string slowly with a stable torque reading. The string will effectively shorten during this operation bringing the actuator dogs further above the PBR. Set the torque limit to the running tool releasing torque + 10%. Zero the Vernier on the weight indicator and slack off to set the TSP packer. Watch the weight indicator for positive indications. Do not slack off in excess of 50,000 lbs whilst rotating. If no shears are observed, release torque slowly and

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continue to slack off to set the packer. Maintain set down weight on liner top packer for a minimum of three minutes

bb) Continued pick up of the running tools will shear the lock sleeve of the RSM

pack-off bushing. An over-pull of approximately 4,000lbs is required. Providing the liner wiper plug has been bumped, pressure up the string to 500psi which will then bleed off when the pack-off bushing is pulled. As soon as the pressure bleeds off begin circulating slowly. It is advisable to pump approximately 10bbls of mud down the drill pipe whilst pulling the running tools above the liner top. This will ensure that the liner top will be as clean as possible.

cc) Pull back sufficient pipe to place the end of the stinger approximately 3-5 meters

above the top of the PBR. dd) Reverse circulate a minimum of 1.5 drill pipe volumes while rotating the pipe

regularly to break up any cement between the pipe and the casing, monitoring the returns to ensure that there are no losses. Do not re-enter the liner top with the tail pipe assembly.

ee) POOH and lay down the hanger running assembly. Conduct a Negative Test on the Liner Top: • Make up BJ’s 1220 Mechanical set packer and TIH to ±30m above the top of

the liner. Ensure there is no casing collar at this depth. Set packer and test the backside to 1000 psi. Open up the bypass and displace the drill pipe with seawater. Bleed off the differential pressure. Monitor the pressure for 30 minutes. Reverse out the seawater and release the packer. POOH.

• While tripping displace the choke, kill and boost lines with seawater.

Liner Clean out: I. MU a 6” bit, 7” casing scraper and TIH picking up enough 3½” drill pipe to get

±15m above the liner top. PU a 9⅝” scraper on top of the 3½” drill pipe and continue TIH with 5” drill pipe. Continue TIH, once on bottom displace the hole to seawater. Once seawater returns are back to the surface short trip 1000m. Go back to bottom and circulate with seawater until returns clear up. POOH and lay down all of the drill string below the 9⅝” scraper.

II. Rig-up Schlumberger Electric line and run a cement bond log. Rig down Schlumberger.

III. Make up the Weatherford cement retainer and TIH, prevent any right hand rotation. Consider turning the drill pipe to the left one rotation every 15 stands as

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a precautionary step. Plan to set the cement retainer ±30m above the top of the liner. Verify this depth with the casing tally to make sure the cement retainer is not sitting in a casing collar. To set the cement retainer TIH to the desired setting depth, PU 2 feet and rotate the drill pipe to the right with 10 turns at the cement retainer. Slack off 2 feet and then pull 40,000 lbs tension (50,000 lbs maximum) and hold this tension for 5 minutes. Slack off 40,000 lbs onto the tool and then pull 40,000 lbs tension again. Test the back side to 1000 psi to verify the cement retainer is fully set.

IV. Release the setting tool by pulling 500lbs tension at the tool and rotating the drill pipe 10 turns to the right. PU to verify the running tool is free from the retainer. If the running tool is snapped back into the retainer then a 5 – 8,000 lb snap should be noticed when the running tool is snapped out of the retainer. Mix and Pump ±20 ft³ of cement (15m plug) and dump same on top of the cement retainer. POOH one stand and reverse out 1.5 drill pipe volumes.

This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig. 7” Liner Top Plug

(BHST = ºF) Cement

(15m plug above liner top) Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry ppg

V. POOH to 60m below the wellhead. Mix and spot ±20 ft³ of cement (15m plug).

POOH one stand and reverse out 1.5 drill pipe volumes. POOH.

This cement design will be finalized once the lab arrives in China and tests are run with the actual cement to be delivered to the rig.

Surface Cement Plug (BHST = ºF)

Cement (60m – 45m below the mudline)

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry ppg

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VI. Rig-up to unlatch and pull the BOPs.

VII. Have the ROV install the trash cap and conduct a seafloor survey.

VIII. Plan to leave the 9⅝” wear bushing in place.

IX. Backload all equipment and demob to Singapore.

X. While demobing to Singapore lay down all of the tubulars out of the derrick.

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8.7.9 Abandonment

A more detailed program covering this operation will be sent to the rig once it is determined what is actually needed. Use the below as a guide line for now.

1) After logging is completed rig down the electric line. Make up a cement head

consisting of a TIW, side door pump-in sub, TIW, 10’ Pup joint. Lay this to the side.

2) If there are any hydrocarbon bearing sands make up the 5” cement stinger and

TIH to set open hole cement plug(s). At least one open plug will be set above the hydrocarbon zone(s).

3) TIH to the top of the hydrocarbon zone. Make up the cement head and circulate

one complete bottoms up. Mix and pump cement as needed to end up with a 30m cement plug. POOH ±3 stands above the top of cement and reverse out 1.5 drill pipe volumes.

4) This cement design will be finalized once the lab arrives in China and tests are

run with the actual cement to be delivered to the rig. 8½” Open Hole Plug

(BHST = ºF) Cement

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry Ppg

5) POOH. Lay down the cement stinger.

6) Make up the Weatherford cement retainer and TIH, prevent any right hand

rotation. Consider turning the drill pipe to the left one rotation every 15 stands as a precautionary step. Plan to set the cement retainer ±15m above the top of the 9⅝” casing shoe. Verify this depth with the casing tally to make sure the cement retainer is not sitting in a casing collar. To set the cement retainer TIH to the desired setting depth, PU 2 feet and rotate the drill pipe to the right with 10 turns at the cement retainer. Slack off 2 feet and then pull 40,000 lbs tension (50,000 lbs maximum) and hold this tension for 5 minutes. Slack off 40,000 lbs onto the tool and then pull 40,000 lbs tension again. Test the back side to 1000 psi to verify the cement retainer is fully set.

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7) Release the setting tool by pulling 500 lbs tension at the tool and rotating the drill

pipe 10 turns to the right. PU to verify the running tool is free from the retainer. Snap back into the retainer and then snap back out. A 5,000 – 8,000 lb snap should be noticed when the running tool is snapped out of the retainer. Break circulation. Mix and Pump ±20 ft³ of cement (15m plug) and dump same on top of the cement retainer. POOH one stand and reverse out 1.5 drill pipe volumes.

8) This cement design will be finalized once the lab arrives in China and tests are

run with the actual cement to be delivered to the rig.

9⅝” Shoe Plug (BHST = ºF)

Cement

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry Ppg

9) POOH to 60m below the wellhead. Mix and spot ±20 ft³ of cement (15m plug).

POOH one stand and reverse out 1.5 drill pipe volumes. POOH. If approval to leave the wellhead in place has been received displace the casing, riser, and lines with seawater prior to POOH. 10) This cement design may change when lab tests are run with the actual cement

delivered to the rig.

Surface Cement Plug (BHST = ºF)

Cement (60m – 45m below the mudline)

Recipe Number of Sacks Sacks Yield Mix water type Mix water amount Gps Weight of Slurry ppg

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11) If approvals are received the wellhead will be left in place, contact the Husky Drilling Superintendent to verify approval. If no approvals are received the 9⅝”, 13⅜”, 20” and 36” will be cut and pulled.

12) Rig-up to unlatch and pull the BOPs.

13) Have the ROV install the trash cap and conduct a seafloor survey.

14) Plan to leave the 9⅝” wear bushing in place.

15) Backload all equipment and demob to Singapore.

16) While demobing to Singapore lay down all of the tubulars out of the derrick.

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8.7.10 Lost Circulation

To help prevent losses use good drilling practices at all times:

• Calculate surge pressures before each trip. • Consider closing the blind shear rams once the drill string is above the BOPs • Boost the riser as much as possible at all times and while out of the hole to

“warm” the mud at the seafloor. • Ensure the mud properties (PV, YP, Gels) are in line with the programmed

properties. • Rotate the drill string while back reaming each stand. • Monitor the PWD the entire time. Have the MWD engineer set the limits such

that an alarm goes off before reaching the upper limit. Have the MWD engineer call the driller to verify the driller is aware that the upper limit is being approached. The driller should come off bottom and circulate until the PWD has dropped to an acceptable level. Set the upper limit a few points below the last shoe test EMW.

If losses occur while drilling, stop the down hole pump(s) (consider keeping the riser pump on line to help “clean up” the hole), pick up off bottom and place a tool joint at the rotary table. Keep the drill string moving at a dead slow rate to prevent the drill string from becoming stuck. Determine the loss rate by filling up the backside via the trip tank. Use mud and keep it in sight. If unable to fill the hole with mud then switch to seawater. Keep track of the amount and type of fluid being added to the back side. It may be necessary to POOH to the casing shoe if it is determined that it will take some time to prepare a pill In the 17½” Hole Section: If Losses are 10 – 50 bbl/hr: Pump a 100 bbl pill consisting of: 10 ppb Mil Seal (M), 8 ppb Mica (F), 7 ppb Mica (F) 10 ppb CaCO3 (M) in prehydrated gel. If Losses are 50 – 80 bbl/hr: Pump a 100 bbl pill consisting of: 20 ppb Mil Seal (M), 12 ppb (Mica (F), 8 ppb Mica (M), 20 ppb CaCO3(M) in prehydrated gel.

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If Losses are >80 bbl/hr: Pump a 100 bbl pill consisting of: 20 ppb Mil Seal (M), 12 ppb Mica (F), 8 ppb Mica (M), 20 ppb (CaCO3 (M), 20 ppb Soluflake (M) in prehydrated gel. In the 12¼” and 8½” Hole Sections: If Losses are 10 – 50 bbl/hr: Pump a 100 bbl pill consisting of: 10 ppb CaCO3 (C), 10 ppb CaCO3 (M), 10 ppb CaCO3 (F), 10 ppb Soluflake (M), 15 ppb Soluflake (F) If Losses are 50 – 80 bbl/hr: Pump a 100 bbl pill consisting of: 10 ppb CaCO3 (C), 10 ppb CaCO3 (M), 10 ppb CaCO3 (F), 12 ppb Soluflake (M), 18 ppb Soluflake (F) If Losses are >80 bbl/hr: Pump a 100 bbl pill consisting of: 5 ppb CaCO3 (C), 10 ppb CaCO3 (M), 15 ppb CaCO3 (F), 12 ppb Soluflake (M), 18 ppb Soluflake (F), 5 ppb Check Loss (F) For severe losses a Solu-Squeeze pill will be used. Solu-squeeze is a high fluid loss, high solids lost circulation squeeze technology product designed for moderate to severe lost circulation. It is 91% acid soluble. It is mixed in the rig pit(s) Enough material has been ordered to mix three 75 bbls pills.

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The typical procedure will be to mix up 50 – 75 bbls of the Solu-Squeeze (enough pill to cover 150m (500’)) and to spot it as a balanced pill. Pick up above the top of the pill or preferably to the casing shoe, close the annular and apply squeeze pressure of 50-100 psi. If the pressure holds increase the squeeze pressure in 25 psi increments until 300 – 400 psi has been achieved. Hold this pressure for 6 – 8 hours. Bled off the pressure and stage the circulation rate up to the previous drilling rate while monitoring returns. TIH and break circulation ±2 stands above the top of the pill. Wash and ream down to the pill, the bit should take weight at the top of the pill. Continue washing and reaming through the interval. Monitor returns as the pump rate is staged up to the drilling rate.

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8.7.11 Equipment / Materials Details

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13 3/8” PDC Subsea Cement Anti-Rotation Plug Assembly

• Anti-rotation and Latch Down• Casing Weight Range:48.00-72.00

lb/ft.• Core Material: Glass filled phenolic,

7000 psi tensile strength; 35,000 psi compressive strength

• Metal Content: Aluminum shear pins and launch ball extrusion ring, 5 oz.

• Fin Material: Nitrile, 65±5 Duro-meter, Shore A

• Fin Color: Black, top; Red, bottom• Temp. Rating: 275º F (135º C)• Pressure Rating: 4500 psi (300 Bar)• Launch Ball Material: 2.5 s.g. Nitrile• Anti-rotation Adapter Material: Glass

Filled Epoxy, 35,000 psi tensile strength

• Dart Core Material: Glass Filled Epoxy, 35,000 psi tensile strength

• Bottom Plug launch pressure: 130 psi ( 9 Bar)

• Ball extrusion pressure: 800-1200 psi (53-80 Bar)

• Top plug launch pressure: 1800-1900 psi (120-126 Bar)

• Requires Davis-Lynch type 700 LAP float equipment

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9 5/8” PDC Subsea Anti-Rotation Cement Plug Assembly

• Anti-rotation and Latch Down• Casing Weight Range:29.3-53.5 lb/ft• Core Material: Glass filled phenolic,

7000 psi tensile strength; 35,000 psi compressive strength

• Metal Content: Aluminum shear pins and launch ball extrusion ring, 4 oz.

• Fin Material: Nitrile, 65±5 Duro-meter, Shore A

• Fin Color: Black, top; Red, bottom• Temp. Rating: 275º F (135º C)• Pressure Rating: 8500 psi (560 Bar)• Launch Ball Material: 2.5 s.g. Nitrile• Anti-Rotation Adapter Material:

Glass Filled Epoxy, 35,000 psi tensile strength

• Dart Core Material: Glass Filled Epoxy, 35,000 psi tensile strength

• Bottom Plug launch pressure: 160 psi ( 11 Bar)

• Ball extrusion pressure: 800-1200 psi (53-80 Bar)

• Top plug launch pressure: 1800-1900 psi (120-126 Bar)

• Requires Davis-Lynch type 700 LAP float equipment

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8.7.12 Personal Responsibilities

All personal are expected to follow all of Transocean polices at all times.

Husky Drilling Supervisors Any change to the drilling program must be authorized by the drilling superintendent. There will be a four man Husky drilling team on the rig at all times of operations. It is expected that all operations will be overseen by the drilling supervisors. All equipment will be inspected by the drilling supervisors as soon as possible once it has been offloaded. A detailed rental tool list will be maintained and updated after each boat arrival and departure. The rental tool list should be emailed to the drilling superintendent on a weekly basis. A look ahead will be updated and forwarded to the drilling superintendent along with the daily drilling report on a daily basis. This outlook should cover at least 3 days and preferably 5 days ahead of the current operation. The look ahead should have the planned personal and equipment movements to and from the rig. The drilling supervisors are expected to develop a “plan of attack” on a daily basis or over a particular operation and distribute it to each rig site member that will be involved in the work. Input is expected from each member. The drilling supervisors are expected to be on the rig floor any time there is any hole problem, are to personally inspect each bit after it is pulled, are expected to personally witness BOP test, casing test, and shoe test, are expected to personally witness verification of the float equipment, are expected to be on the drill floor when casing enters the open hole, are expected to be present on the cement unit any time cement is being mixed and pumped, is expected to personally witness the launching of balls and darts during the cementing operations. Day Drilling Supervisor: Responsible for all operations Responsible for people and equipment movements Responsible for daily plans Responsible for a detailed and accurate daily report Night Drilling Supervisor: Responsible to support in all areas as above

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Is expected to consult with the Day Drilling Supervisor if anything changes during the night. Chinese Wellsite Drilling Engineer(s)/Supervisor(s): Expected to aid Day and Night Drilling Supervisors Will not be allowed to give any orders or directives Are expected to ask questions about each operation and to learn as much as possible.

Husky Wellsite G&G Personal

The wellsite Geologist(s) are expected to monitor the mudloggers and MWD/LWD personal to ensure that the necessary data is being gathered as per the Geological Well Program. He is expected to update the drilling supervisor with formation changes, correlations, formation tops, and ensure that all reports generated by the mudloggers and/or MWD/LWD personal are correct and accurate. He is expected to update the Calgary based Geologists on a daily or as needed basis. He is expected to coordinate with the drilling supervisor to ensure the proper wirline logging equipment and personal are ordered out in a timely fashion. He is expected to ensure the proper logging tools are being run in the proper order and that they are being run at the proper speeds. He is to ensure the proper heading and scales are used on all logs.

Service Personal

All Service personal are expected to give input into the daily or operation plan of attack. All Service personal are expected to inspect their tools as soon as possible upon arrival to the rig. All Service personal are expected to notify the day supervisor of any discrepancies or damage that is noticed on their equipment. All Service personal are expected to attend at least one pre-tour meeting per day they are on the rig.

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All Service personal are expected to take a pro-active role in all meetings. Mudloggers and MWD/LWD personal are expected to monitor the drilling parameters and set alarms such that small changes in the parameters can be noticed. Once an alarm is activated they are expected to notify the drilling supervisor and driller on tour immediately. All service personal are expected to give a detailed list of all equipment to be shipped back to the dock to the drilling supervisor. The service personal are also expected to coordinate with the deck foreman / crane operator so that these men know where and what is to be shipped back.

Daily Phone Calls There will be a daily morning call between the Husky China Shekou office, Calgary Operations Geologist and the drilling rig. It is expected that all personal that will have a role in the current or near future operation will be in attendance for this call. This call will be conducted daily at 0730 hours. The drilling supervisors are to either email or phone in an afternoon report between the hours of 1500 and 1600 hours to the drilling superintendent.

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Husky Contact Numbers:

Name Position Office Number Home number Mobile Number Dempsey Stover Drilling

Superintendent 86-755-2681-2657 ext 18

86-755-2688-7137

86-13923709766

Edwin Macdonald Calgary Operations Geologist

403-298-7102 403-512-5050

Henry Pan Logistic and Warehouse Supervisor

86-755-2681-2657 ext 17

86-13602513441

Fan Gui Helicopter Coordinator

Gao Dehai China G&G Manager

86-755-2681-2657 ext 19

86-13823116537

Fang Weihua Project/Operations Manager

86-755-2681-2657 ext 16

86-13823116506

Wing On Chu China General Manager

86-10-8518-2277 ext 16

86-13910091901

Cao Jun Drilling Engineer 86-10-8518-2277 ext 20

86-13480685687

Dai Hang Drilling Engineer 86-10-8518-2277 ext 35

86-13530819088

Chen Guoqiang Drilling Engineer 86-10-8518-2277 ext 36

86-13554851118

GC Xia Procurement Supervisor

86-755-2681-2657 ext 30

86-13560778250

Tristan Zhu Procurement & Logistic coordinator

86-755-2681-2657 ext 22

86-13826507750

Huang Ting Operations Secretary

86-755-2681-2657 ext 23

86-13590128129

Yang Hui Drilling Secretary 86-755-2681-2657 ext 11

86-13076967900

Al Pate Drilling Manager 403-750-1507 403-542-1541 Bill Ellsworth International Drilling Dave Johnson Exploration Manager 403-298-7215

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Bruce Campbell Backup Drilling Superintendent/HSE Manager

86-10-8518-2277 ext 12

86-13066927605

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Figure 25. Drilling Time vs Depth Graph

Figure 26. Drilling Cost vs Depth Graph

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Depth Cost0 01 4,000 Mob

1495 4,600 RU1565 5,800 36"2080 7,300 Drill 26"2080 8,500 20" casing, cement, Run BOPs2385 9,500 Drill 17.5" Hole2385 10,300 13-3/8" casing & Cement3160 12,000 Drill 12-1/4" Hole3160 13,890 Log, 9-5/8" casing, cement4000 16,590 Drill 8.5" Hole4000 17,697 Log 22,497 Drill, Log, P&A, Demob3160 18,527 Sidetrack3300 19,156 Core #13700 19,659 Drill3718 20,162 Core #23900 20,489 Drill3900 21,394 Log3900 22,400 Run Liner 27,009 Drill, log, sidetrack, core, Run Liner, T&A, Demob3900 25,509 P&A3900 27,009 Demob

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8.7.13 Miscellaneous Forms SPILL REPORT FORM

Drill Actual Spill Spill Report #: _________________________

Reporting Party: Suspected Responsible Party: Name: Company: Position: Phone: Phone: Company:

RESPONSIBLE PARTY

Date/Time Incident Occurred:

Date/Time Incident Reported to QI/IC:

Area/Block: Facility: Latitude: Longitude: Nearest City & Distance: Description of Incident:

TIME AND

LOCATION

Quantity: bbls / gals Material: API Gravity: Appearance: Length: ft / mi Width: ft / mi

MATERIALS DISCHARGED

Air Temp: ° F Water Temp: ° F

Ceiling: ft Visibility: mi Seas: ft

Wind Direction/Velocity: From @ kts / mph Current Direction/Velocity To @ kts / mph

WEATHER

Actions Taken to Correct/Mitigate Incident:

RESPONSE ACTION

Injuries: Fatalities: Evacuated: Damage:

ADDITIONAL INFORMATION

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Husky Energy Incident Investigation Report

□ NEW (# of attachments) □ Modified Report # Faxed to: Incident #

√ One Actual Severity □ Major □ Serious □ Minor □ Near Miss

√ One □ Upstream □ Midstream □ Downstream □ Canadian Frontier/International Business Unit: Department: Operational Mode

AR

EA

Facility/Plant SEQ LSD SEC TWP RGE W M □ Others Event Date (YYYY-MM-DD) Event Time 24 HR CLOCK Report Date (YYYY-MM-DD)

Reported By: Last Name: First Name: Phone

LOC

ATI

ON

TI

ME

Prepared By: Last Name: First Name: Phone

□ Husky □ Contractor Contractor Name/Address Phone

Employee Number Last Name First Name Phone

EMPL

OYE

E o

r C

ON

TRA

CTO

R

Occupation Experience Years Months □ At Task □ At Location State clearly the facts and sequence of the event:

D

ESC

RIP

TIO

N

Coordinator Sign-Off: Name: Date: (YYYY-MM-DD) □Separate Sheet attached Potential Severity □ 1. Major □ 2. Serious □ 3. Minor Potential Frequency: □1. Frequent □2. Occasional □3. Minor

Immediate Causes of the Event (What Triggered the Event) Substandard Act(s) Substandard Condition(s)

Basic Causes of the Event (What Allowed the Trigger To Exist) Personal Factors: Job Factors: Management Control Needs (check all required):

□ Leadership & Administration □ Emergency Preparedness □ Engineering

□ Management Leadership □ Rules and Permits □ Communications

□ Planned Inspection and Maintenance □ Knowledge & Skill Training □ General Promotion

□ Task Analysis & Procedure □ PPE Enforcement or Needs □ Hiring and Placement

□ Accident/Incident Investigation System □ Health and Hygiene □ Material and Service Management

□ Task Observation □ Program Evaluation System □ Off-The-Job-Safety

□ Others (specify)

Root Cause:

AN

ALY

SIS

□ Separate Sheet attached

Action By: Recommendations: (Determined by Review

Committee) Action Items:

Last Name First Name

Target Completion (YYYY-MM-DD)

Date Completed (YYYY-MM-DD)

REC

OM

MEN

DA

TIO

NS

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SPILL REPORT FORM Spill Report # Drill Actual Spill

For Spills Involving a Load out or Vessel Collision, Obtain from the Boat Captain:

Name of Captain:

Vessel Name:

Address of Captain:

Phone # of Captain:

Card Number:

Call Sign:

Agent: Flag:

Remarks:

Notifications Within the Company:

Reported by Reported to Reported to (position) Time Date

Notifications to Agencies: Reported by

(Name) Reported to

(Name) Agency Incident # Time Date

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8.7.14 General Data

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Casing Specifications

PARAMATER 20” 13⅜” 9⅝” 7” Weight (ppf) 166.4 68 47 26

Wall thickness (inch) 0.812 0.48 0.472 0.362 Grade X-56 N-80 N-80 N-80

Connection S-60 MT Buttress Buttress Buttress

Pipe ID (inch) 18.376 12.415 8.681 6.276 Drift (inch) 18.25 12.259 8.525 6.151 Burst (psi) 3980 4930 6,870 7240

Collapse (psi) 2510 2260 4,760 5410 Tensile (kips) 1450 1556 1086 604

Connection OD (inch) 21 14⅜ 10⅝ 7.656 Min MU Torque (ft-lb) 15,000 NA NA NA Opt MU Torque (ft-lb) 20,000 To the

diamond To the

diamond To the

diamond Max MU Torque (ft-lb) 50,000 NA NA NA

Capacity (bbl/ft) 0.328 0.1497 0.0732 0.038

Displacement (bbl/ft) 0.061 0.0241 0.0168 0.009

Casing Length (m/feet) 585/1920 890/2919 1665/5461 TBD Casing Wt (lbs) 324,277 198,506 256,676 TBD

Landing String 5”, 19.5 ppf 5”, 19.5 ppf 5”, 19.5 ppf 5”, 19.5 ppf

Land String length (ft) 4904 4904 4904 TBD Land String Wt (in air) 95,628 95,628 95,628 TBD

Total wt of casing & DP (in air) 419,905 198,506 256,676 TBD Land String Rating (premium) 560,800 560,800 560,800 TBD Land String Safety Factor (in

air) 1.33 2.82 2.18 TBD

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Drill Pipe Specifications

PARAMATER 5” DP 5” HWDP 3½” DP Weight (ppf) 19.5 49 13.3 Weight (ppf

w/connection) 22.79 50.38 14.49

Grade S-135 G-105 Connection 4.5” IF (NC 50) 4.5” IF (NC

50) 3.5” IF (NC

38) Pipe ID (inch) 4.276 3 2.764

Connection OD (inch) 6.625 6.625 5 Connection ID (inch) 3.25 3 2-7/16

Drift (inch) 3.125 2.688 2.313

Burst (psi) 16,105 (Premium) 19,250 (New) 19,320 (New) Collapse (psi) 10,029 (Premium) 17,600 (New) 19,760 (New)

Tensile (lbs) 560,800

(Premium) 691,200 (New) 380,190 (New)

Torsional Strength (ft-lbs) 51,700 (Premium) 56,500 (New) 22,213 (New)

Min MU Torque (ft-lbs) 25,900 28,900 9,100 Max MU Torque (ft-lbs) 26,800 30,000 11,107

Capacity (bbl/ft) 0.0173 0.0087 0.0074

Displacement (bbl/ft) 0.0083 0.0184 0.0045

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Figure 27. Offset Well Designs (1)

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BaiYun 7-1-1 Pan Yu 30-1-1 Liu Hua 19-4-1 PanYu 33-1-1 LW 3-1-1140 km WSW 80 km W 60 km NWSpud: April, 1987 Spud: April, 2002 Spud: March, 1986 Spud: October, 1984

Depth (m) Block 42/7 Block 28/27 Block 29/19 Block 28/27 Block 29/26100 WD = 499m WD = 194m WD = 208m WD = 215m WD = 1481m200300 30" @ 264m 30" @ 283m 30" @ 287m400 13-3/8" @ 371m500 20" @ 431m600 30" @ 577m LOT = 11.15700 seawater 800 20" @ 803m 20" @ 744m900 LOT = 11.6 MW = 9.0 ppg1000 13-3/8" @ 1000m1100 LOT = 13.712001300 MW = 9.6 ppg1400 MW = 9.8 ppg1500 9-5/8" @ 1540m1600 36" @ 1565m1700 MW = 9.2 ppg1800 13-3/8" @ 1804m1900 FIT = 12.12000 2100 Gas 20 units up to 20" @ 2080m2200 660 units MW = 10.0 ppg2300 MW = 9 ppg 13-3/8" @ 2299m2400 9-5/8" @ 2401m LOT = 11.6 13-3/8" @ 2385m2500 LOT = 11.2 2600 270028002900 3000 MW = 9.0 ppg3100 MW = 9.8 ppg TD = 3086m3200 TD = 3190m TVD, 9-5/8" @ 3160m3300 3478m MD3400 MW = 9 ppg3500 TD = 3527m36003700 MW = 9.7 ppg3800 9-5/8" @ 3792m3900 LOT = 13.940004100 TD = 4071m42004300 MW = 9.0 ppg4400450046004700480049005000 MW = 9.3 ppg5100 TD = 5094m

Figure 28. Offset Well Design (2)

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Rental Tools:

36” Casing Jetting/ 26” open hole:

• 5 - Spacer Subs - 6⅝” Reg connections, 1 @ 2’, 1 @ 3’, 1 @ 4’, 1 @ 5’, 1 @ 6’

• 3 - Crossover Subs – three w/6⅝” Reg Pin x 4½” IF Box • 3 - Stabilizers – three 26” hole size with 6⅝” connections • 2 - Bit Subs – two with 7⅝” Reg Box x 6⅝” Reg Box. Bored for a float • 2 - Ported flapper type Float valve for above bit sub. • 2 - Jars – two 6½” OD drilling jars with 4½” IF connections • 150 Ton split bowl complete with 8” drill collar hand slips and 5” drill pipe

hand slips • 2 – crossover subs – two 6⅝” FH Box x 6⅝” Reg Pin (Schlumberger MWD) • 2 – crossover subs – two 6⅝” FH Pin x 6⅝” Reg Box (Schlumberger MWD)

17½” Hole Size:

• 3 - Stabilizers – three 17½” hole size with 6⅝” connections • Fishing Package: 7¾” Oil jar, 7¾” Accelerator jar, 7¾” Bumper jar, 11¾” over

shot, 11¾” over shot extension, 11¾” wall hook guide, 15” oversized guide for overshot, 17½” Cone-buster junk mill, 9⅝” boot basket, 11” reverse circulation junk basket, and assorted grapples.

• Two - 8” NMDC with 6⅝” Reg connections 12¼” Hole Size:

• 2 - Bit Subs – two with 6⅝” Reg Box x Box. Bored for a float. • 3 - Stabilizers – three 12¼” hole size with 6⅝” connections • 12¼” Cone-buster junk mill • 12¼” Hole Opener with strap welded bull nose and 6⅝” Reg Pin up

8½” Hole Size:

• 2 - Bit Subs – two 4½” Reg x 4½” IF Box x Box. Bored for float. • 2 - Ported flapper type Float valve for above bit sub • 3 - Stabilizers – three 8½” hole size with 4½” IF connections • 3 - Crossover subs – three with 4½” IF Pin x 4” IF Box • 3 - Crossover subs – three with 4½” IF Box x 4” IF Pin • 8½” Hole Opener with strap welded bull nose and 4½” Reg Pin up. • Two - 6¼” NMDC with 4½” IF connections

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• Fishing Package: 6½” Oil jar, 6½” Accelerator jar, 6½” Bumper jar, (all jars with 4½” IF connections) 8⅛” over shot, 8⅛” over shot extension, 8⅛” wall hook guide, 8½” Cone-buster junk mill, 6⅝” boot basket, 7⅞” reverse circulation junk basket, and assorted grapples.

• 2 – crossover subs – two 5½” FH Pin x 4½” IF Box (Schlumberger MWD) • 2 – crossover subs – two 5½” FH Box x 4½” IF Pin (Schlumberger MWD) ALL TOOLS TO BE INSPECTED TO DS-1 CATEGORY 4 BEFORE GOING TO RIG. INSPECTION PAPERS TO BE INCLUDED WITH TOOLS.

Miscellaneous:

• 7” Liner Hanger for 7” 26#, N-80, BTC casing. • Casing Patch for 13⅜” 68#, N-80 casing • Casing Patch for 9⅝” 47#, N-80 casing • Whipstock for 9⅝” 47#, N-80 casing complete with mills

Well Abandonment package to cut and pull casing:

• For 9⅝” 47# N-80 casing • For 13⅜” 68#, N-80 casing • For 20” 166# (0.812” wall) casing • For 36” (1½” wall) casing

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APPENDIX 1 LWD Logging Programme

1.1 LWD - 17 ½” Hole

Determination of Potential Zones of Interest

Logging Contractor: Schlumberger Casing: 20” @ 2057 m SS, (2080 m RT) Bit Size: 17 ½” Total Depth: 2362 m SS, (2385 m RT) (Estimated 17 ½” TD - ITD1) Mud system: WBM

GR/ARC Gamma Ray Phase Resistivity Attenuation Resistivity Both 400 kHz and 2 mHz resistivities for each five Phase and five Attenuation measurements presented with final data. Vertical Scale: 1:200 Horizontal Scales: Resistivities: 0.2-20 ohm-m log Gamma Ray: 0-150 API

Rate of Penetration: Best scale

1.2 LWD - 12 ¼” Hole

Determination of Potential Zones of Interest

Logging Contractor: Schlumberger Intermediate Casing 13 3/8” @ 2362 m SS, (2385 m RT) Bit Size: 12 ¼” Total Depth: 3137 m SS, (3160 m RT) (12 ¼” Hole TD – ITD2) Mud system: WBM

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GR/ARC Gamma Ray Phase Resistivity Attenuation Resistivity Both 400 kHz and 2 mHz resistivities for each five Phase and five Attenuation measurements presented with final data. Vertical Scale: 1:200 Horizontal Scales: Resistivities: 0.2-20 ohm-m log Gamma Ray: 0-150 API Rate of Penetration: Best scale

1.3 LWD - 8 ½” Pilot Hole

Determination of Potential Zones of Interest

Logging Contractor: Schlumberger Intermediate Casing 9 5/8” @ 3137 m SS, (3160 m RT) Bitsize: 8 ½” Total Depth: 4071 m SS, (4094 m RT) (Est. Pilot Hole TD - PTD) Mud system: WBM

GR/ARC Gamma Ray Phase Resistivity Attenuation Resistivity Both 400 kHz and 2 mHz resistivities for each five Phase and five Attenuation measurements presented with final data. Vertical Scale: 1:200 Horizontal Scales: Resistivities: 0.2-20 ohm-m log Gamma Ray: 0-150 API

Rate of Penetration: Best scale

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1.4 LWD - 8 ½” SideTrack Hole

Determination of Potential Zones of Interest

Logging Contractor: Schlumberger Intermediate Casing 9 5/8” @ 3137 m SS, (3160 m RT) Bitsize: 8 ½” Total Depth: TBD (Estimated Sidetrack TD - STD) Mud system: WBM

GR/ARC Gamma Ray Phase Resistivity Attenuation Resistivity Both 400 kHz and 2 mHz resistivities for each five Phase and five Attenuation measurements presented with final data. Vertical Scale: 1:200 Horizontal Scales: Resistivities: 0.2-20 ohm-m log Gamma Ray: 0-150 API

Rate of Penetration: Best scale

Operation Notes:

1. Data to be transmitted to Calgary in real time as determined by Calgary office.

2. Non real time data transmitted to Calgary at least twice daily.

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3. Five (5) copies of field prints are required; one for Husky Oil China Ltd in

Shekou, one for Husky Oil Operations Ltd in Calgary, two for CNOOC, and one

for China’s Regulatory Agency.

Nine (9) copies of final prints are required; two for Husky Oil China Ltd in Beijing,

two for Husky Oil Operations in Calgary, four for CNOOC, and one for China’s

Regulatory Agency.

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December, 2005

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APPENDIX 2 Detailed Logging Programme

2.1 Run 1 - Logging Run at Intermediate Casing - ITD2

Intermediate Casing: 13 3/8” @ 2362 m SS, (2385 m RT)- ITD1

Bit size: 12 ¼”

Intermediate Depth: 3137 m SS, (3160 m RT) (Est. 12 ¼” TD – ITD2)

Mud system: WBM

Run 1- Descent 1. GR/DSI/EMS/PEX w/AIT (or HRLA): Gamma Ray, Dipole Sonic Imager, Environmental Measurement Sonde,

Litho Density, Compensated Neutron, and Array Induction.

AIT-GR: ITD2 to ITD1

Vertical Scale: 1:200 and 1:500

Horizontal Scales:

Resistivities: 0.2-2000 ohm-m Log (Lower scale)

Resistivities: 0-50 ohm-m Lin (Upper Scale)

Resistivities: 1000-0 m-mhos Lin (Upper Scale)

GR: 0-150 API (Both scales)

TLD-HGNS-GR-CAL: ITD2 to ITD1

Vertical Scale: 1:200 and 1:500

Horizontal Scales:

GR: 0-150 API (Both scales)

Calipers: 6”- 16” (Both scales)

RHOZ/RHO8: 2 – 3 g/cc (Upper scale)

PEFZ/PEF8: 0-10 Track 2 (Both scales)

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HDRA: -0.05 to 0.45 g/cc Track 2 (Both scales)

DPHZ-NPOR/HNPO: 0.45 to – 0.15 (Lower scale)

LS Porosity Scales - Rho fluid 1 g/cc Rho matrix 2.71 g/cc

NOTE: Run GR-CNL in cased hole from ITD2 to 36” casing shoe on Limestone matrix

GR-DSI-CAL: ITD2 to ITD1

Vertical Scale: 1:200 and 1:500

Horizontal Scales:

GR: 0-150 API (Both scales)

Calipers: 6”- 16” (Both scales)

DT compressional: 140 - 40 usec/ft (Both scales)

DT shear (P&S and dipole mode): 200-100usec/ft (best scale)

(Both scales)

Note: 1. Make a complete “Hi-Res” pass with gamma ray, resistivity, density, and neutron

data over all potential pay sands. Hi-Res is on a scale of 1:120 and AIT on one

foot spacing.

2. Include in digital data, porosity on Sandstone (2.65 g/cc). and Limestone Matrix

(2.71 g/cc) and two/four foot AIT spacings.

3. Simultaneously acquire DT compressional and DT shear data for wellbore

stability analysis and seismic applications (including AVO analysis) from 2385m

to TD (Dipole Mode and P&S).

4. Record and display casing signal in pipe.

5. Prepare tools accordingly for hole size of 12 ¼”.

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2.2 Run 1 - Descent #2:- GR/VSI Gamma ray with Versatile Seismic Imager.

- A four level VSI configuration with a maximum 20 m spacer between levels is to be

used.

- A gamma ray tool will be run for depth control.

- Levels from TD to 36” casing shoe will be utilized.

- Standard presentation and scales.

The airgun source array system is to be determined. The airgun hook-up

configuration is tentatively set as follows:

Surface source for checkshot or vertical VSP to be a constant offset from the drill

floor.

The source should be located 6m below sea surface to achieve frequencies up to

100 Hz.

Air supply to be provided from air compressors and backed up with rig air.

Interval to be logged is ITD2 to 36” casing shoe. Final levels to be determined by

Calgary office at the time of logging. At each station, five good airgun pops are to be

recorded.

Decisions regarding final displays, tape output etc. will be stated later. Number of

reports will be 7 (3 for Husky, and 4 for CNOOC). Number of tapes will be 2 (one for

each group).

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2.3 Run 2 - Logging Run at Pilot Hole Total Depth - PTD

Intermediate Casing: 9 5/8” @ 3137 m SS, (3160m RT) – ITD2

Bit size: 8 ½”

Total Depth: 4094 m (Estimated Pilot Hole TD - PTD)

Mud system: WBM

Run 2-Descent 1. GR/DSI/PEX/NGT w/AIT ( or HRLA ):

Gamma Ray, Dipole Sonic, Platform Express, Litho Density,

Compensated Neutron, Spectral Gamma Ray and Array Induction. (Tools

may be run separately if ‘overhole’ dictates.)

AIT-GR: PTD to ITD2

Vertical Scale: 1:200 and 1:500

Horizontal Scales:

Resistivities: 0.2-2000 ohm-m Log (Lower scale)

Resistivities: 0-50 ohm-m Lin (Upper Scale)

Resistivities: 1000-0 m-mhos Lin (Upper Scale)

GR: 0-150 API (Both scales)

TLD-HGNS-GR-CAL: PTD to ITD2

Vertical Scale: 1:200 and 1:500

Horizontal Scales:

GR: 0-150 API (Both scales)

Calipers: 6”- 16” (Both scales)

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RHOZ/RHO8: 2 – 3 g/cc (Upper scale)

PEFZ/PEF8: 0-10 Track 2 (Both scales)

HDRA: -0.05 to 0.45 g/cc Track 2 (Both scales)

DPHZ-NPOR/HNPO: 0.45 to – 0.15 (Lower scale)

LS Porosity Scales - Rho fluid 1 g/cc Rho matrix 2.71 g/cc

GR-DSI-CAL: PTD to ITD2

Vertical Scale: 1:200 and 1:500

Horizontal Scales:

GR: 0-150 API (Both scales)

Calipers: 6”- 16” (Both scales)

DT compressional: 140 - 40 usec/ft (Both scales)

DT shear: 200 - 100 usec/ft (best scale) (Both scales)

HNGS: PTD to ITD2

Vertical Scale: 1:200

Horizontal Scales:

Standard Scales

Note: 1. Make a complete “Hi-Res” pass with gamma ray, resistivity, density, and

neutron data over all potential pay sands. Hi-Res is on a scale of 1:120 and

AIT on one foot spacing. (Include two and four foot AIT spacings in digital

file).

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2. Include in digital data, porosity on Sandstone (2.65 g/cc). and Limestone

Matrix (2.71 g/cc).

3. Hole size is 8.5”. Prepare tools accordingly.

4. Simultaneously acquire DT compressional and DT shear data for wellbore

stability (Dipole Mode and P&S mode).

2.4 Run 2 - Descent #2 and 3:- GR/MDT ( Contingent ):

Gamma ray with Modular Formation Dynamics Tester.

MDT-MRMS-MRPO-MRFA-MRPA Tool should be comprised of standard equipment with two single probe modules

(with standard and large diameter probes, resistivity meters), two Multi-Sample

Modules each with 6-450cc sample bottles, (MRMS), one Pump Out Module

(MRPO), one Optical Fluid analysis Module (MRFA), and one Packer Module

(MRPA).

Backup equipment must include critical items; standard MDT system, MRPO, MRFA, and MRPA.

Gamma Ray to be used for depth-tie and for positioning.

Standard log scales to be used for gamma ray and pressure data.

Tentative Plan -

Two descents are planned. The first descent will determine pressure gradients, and

high permeability intervals. The tool configuration will be gamma Ray-standard MDT

with two single probe modules, one with a standard and one with a large diameter

probe. The second descent will be run to obtain samples. The tool configuration will

be gamma ray-standard MDT with one single probe module with resistivity meter,

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optical fluid analyzer module, pump-out module, packer module, multisample

chambers.

Procedure - pressures:

Run in the hole with the MDT tool to 100 metres above the bottom of the casing

and check the seat on the lower single probe and the seats on the dual probe.

Make pressure measurements in the mud column at 100, 50, and 0 metres

above the base of the casing. Determine the stabilization times for the various

probes and compare the mud pressures measured from the probes. Plot the

mud pressures and determine the mud column noise and gauge error. If the

packer seats and gauges checkout, run in to the top of the reservoir.

Establish a pressure measurement frequency (measurements/meter) such that

the pressure gradient is precise enough to distinguish the gas gradient of 0.305

psi/m, an oil gradient of 8.30 kPa/m or 1.200 psi/m (estimated 36° API), and a

water gradient of 150 psi/m (estimated 40,000 ppm NaCl). Record

measurements from the bottom sand to the top, to minimize hysterisis errors,

repeating depth points as necessary to obtain true formation pressures.

Depths for pressure gradients to be determined by Calgary office.

Procedure - Samples

Once adequate gas-oil-water gradients have been obtained, and if required PVT

quality hydrocarbon samples and formation water samples will then be taken

from top to bottom.

Samples depths and types to be determined by Calgary office.

2.5 Run 2 - Descent #4:- GR/VSI : Gamma ray with Versatile Seismic Imager.

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Husky Oil China Ltd. Exploration Block 29/26 Drilling Programme for Liwan 3-1-1 Pearl River Mouth Basin, Offshore China

December, 2005

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A four level VSI configuration with a maximum 20 m spacer between levels is to be

used.

A gamma ray tool will be run for depth control.

Levels from PTD to 100 m above ITD2 will be utilized.

Standard presentation and scales.

The airgun source array system is to be determined. The airgun hook-up

configuration is tentatively set as follows:

Surface source for checkshot or vertical VSP to be a constant offset from the drill

floor.

The source should be located 6m below sea surface to achieve frequencies up to

100 Hz.

Air supply to be provided from air compressors and backed up with rig air.

Interval to be logged is PTD to 100m above ITD2. Final levels to be determined by

Calgary office at the time of logging. At each station, five good airgun pops are to be

recorded.

Decisions regarding final displays, tape output etc. will be stated later. Number of

reports will be 7 (3 for Husky, and 4 for CNOOC). Number of tapes will be 2 (one for

each group).

Operation Notes: 1. Tension curve to be presented on all surveys, head tension device to be run on

all runs.

2. At least one 50 m repeat over a zone of varied response is required. If more than

one repeat is required, present all on final log. Tool should be repeated until

Companies' representative is satisfied with the data.

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Husky Oil China Ltd. Exploration Block 29/26 Drilling Programme for Liwan 3-1-1 Pearl River Mouth Basin, Offshore China

December, 2005

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3. "Before" and "after" survey calibrations should be recorded, labeled and included

with master shop calibrations. Operations should not proceed if sonde exceeds

acceptable tolerances, unless approved by Companies' representative.

4. Parameter and job event summary tables are required on the bottom of each log.

Tape and LIS summary directories are also required on log tails. Include tool

diagrams.

5. Overlap tie-ins by at least 30m.

6. Data transmission will be via satellite/internet.